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D&M CEO, John Wallace, at SPIEF Energy Panel

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D&M CEO, John Wallace, at SPIEF Energy Panel

juin 6, 2019

The Energy Panel is a premier discussion platform for oil and gas leaders, government officials and acclaimed industry experts. In 2015, UN member states unanimously supported the Resolution Transforming our World: the 2030 Agenda for Sustainable Development. This agenda is a plan of action for improving the well-being of people, securing the planet and prosperity. Oil and gas will remain the backbone of the global energy mix. Advancement of the oil and gas industry is a prerequisite for eradicating poverty and hunger, bridging the inequality gap and ensuring decent living standards, which is essential for sustainable development. The Energy Panel Session will provide a comprehensive insight into sustainable energy development, underlining the industry’s multinational and multicultural nature, and its geographical diversity. The discussion participants will exchange views on energy market trends, transformation of the oil and gas industry, and dynamics of the geopolitical impacts on the markets, as well as offering opinion on the cooperation and innovation potential, ensuring an effective transition to the low carbon economy.

View the panel presentation at this link. (You can view in English or Russian by clicking the headphone icon within the video.)

https://www.forumspb.com/en/programme/68864/?ELEMENT_ID=68864

Moderators
Evgeny Primakov, Member of the State Duma of the Federal Assembly of the Russian Federation; Journalist; Author of the International Review Programme, Russia-24 TV Channel; Chairman of the Supervisory Board, Russian Humanitarian Mission
Nobuo Tanaka, Chairman, Sasakawa Peace Foundation; Executive Director (2007–2011), International Energy Agency

Key note
Igor Sechin, Chief Executive Officer, Chairman of the Management Board, Deputy Chairman of the Board of Directors, Rosneft

Panellists
H.E. Ali Shareef Al-Emadi, Minister of Finance of Qatar
Ivan Glasenberg, Chief Executive Officer, Glencore
Robert Dudley, Group Chief Executive, BP
Neil Duffin, President, ExxonMobil Global Projects Company
Lorenzo Simonelli, Chairman of the Board of Directors, President, Chief Executive Officer, Baker Hughes, a GE Company
John W. Wallace, Chairman and CEO, DeGolyer & MacNaughton



The Saudi Plan To Boost Spare Oil Production Capacity

mai 9, 2019

Even as Saudi Arabia’s oil production reached record levels, with total output hitting 11.1m barrels per day (bpd) in November 2018, the country is boosting levels of investment to ensure there is spare capacity to meet a global supply shock and subsequent increase in prices. According to Khalid Al Falih, the minister of energy, industry and mineral resources, the country will invest $20bn to pump another 1m bpd of crude in order to maintain spare capacity.

EMERGENCY SUPPLY: The US Energy Information Administration defines spare capacity as the volume of production that can be brought online within 30 days and maintained for 90 days. Typically, lower capacity can trigger an increase in oil prices. In recent years Saudi Arabia has had the world’s largest spare capacity, of between 1.5m and 2m bpd. In October 2018 that buffer slimmed to 1.3m bpd as the country began pumping 10.7m bpd, as it has a maximum output capacity of 12m bpd. The buffer fell further to 900,000 bpd when output increased in November.

FIELD IMPROVEMENTS: Saudi Aramco was able to reach record output levels in November 2018 due to its increased capacity as one of its fields came onstream and a bottleneck in another field was repaired. The company’s 2017 annual report noted it was on course to boost output from its Khurais oil field by 300,000 bpd in 2018 to give the field a total daily output capacity of 1.5m bpd. Khurais, which produces Arabian light crude oil, was first discovered in 1957.

The latest boost in capacity is the result of an improvement programme launched in 2012, which developed the Lower Fadhli field and built new processing facilities to handle 300,000 bpd of crude, 143m standard cu feet per day (scfd) of associated gas and 34,000 bpd of natural gas liquids (NGLs). As part of this programme, approximately 650 km of pipeline was constructed to transport crude oil, gas, NGLs and seawater.

As the additional supply from Khurais entered the market in late 2018, a technical issue at the offshore Manifa field, which has the capacity to produce 900,000 bpd of heavy crude oil, was solved. The field, which is comprised of 27 drilling islands linked by a 42km causeway, was reportedly hit by a technical issue in 2017. Reuters reported that corrosion of the water injection system used to maintain pressure in the reservoir was reducing output and that costly repairs would potentially require a shutdown period. It was reported that the repairs resulted in a combined increase in production of 550,000 bpd from Khurais and Manifa in the fourth quarter of 2018.

In Saudi Aramco’s 2017 annual report the company noted it made two new oil field discoveries in 2017 at Sakab and Zumul. However, the report did not give an indication of the capacity of the two fields or of how long the development of the new sites could potentially take. In his message in the annual report, Al Falih said that the oil industry globally had lost $1trn in planned investments since the 2014 fall in oil prices, despite the growth in global demand, which rose by 1m bpd to 1.5m bpd, as well as the declining returns from some of the world’s more mature oil fields. “Significant new investments are required in additional capacity and expanded and upgraded infrastructure, as well as the development of pioneering technology to make petroleum energy more sustainable and accessible,” he wrote. “Saudi Aramco is committed to playing its unique part in meeting the world’s energy needs today and tomorrow by continuing to invest wisely throughout the cycle and across the value chain.”

NEUTRAL ZONE: If a diplomatic bottleneck can be eased, Saudi Arabia can also tap its halfshare in an additional 500,000 bpd of production in the neutral zone it shares with Kuwait. The offshore Khafji field was shut down in October 2014 and the onshore Wafra field ceased production in May 2015. Khafji is owned by Saudi Aramco Gulf Operations Company and Kuwait Gulf Oil Company (KGOC), while Wafra is operated by KGOC and Saudi Arabian Chevron.

The shutdowns were caused by disputes over flaring regulations and Kuwait’s objection to having an international oil company operating in the zone. Talks between the two countries over the operation of the fields began in the summer of 2018; however, these appeared to stall in October after a meeting between Saudi Crown Prince Mohammed bin Salman bin Abdulaziz Al Saud and Sheikh Sabah Al Jaber Al Sabah, the emir of Kuwait, failed to reach an agreement. S&P Global Platts reported that many observers believed the dispute would only be solved through international arbitration unless a sudden drop in the level global oil supply prompted the two sides to return to negotiations.

AUDIT REPORT: Saudi Arabia’s ability to meet spare capacity needs was given a boost in January 2019 with the publication of an independent auditor’s report on Saudi Aramco’s proven reserves of oil and gas, which increased the estimated total by over 2bn barrels. The audit, conducted by Texas consulting firm DeGolyer and MacNaughton (D&M), was commissioned as part of Saudi Aramco’s preparations for an initial public offering that is now slated to take place in 2021. The audit found the company had proven reserves of 263.1bn barrels of oil, 2.2bn barrels more than the estimates of the 2017 annual report. It also put total reserves of natural gas at 319.5trn cu feet, compared to the figure of 302.3trn cu feet that was previously reported. When the neutral zone total was included, D&M estimated oil reserves of 268.5bn barrels, compared to an earlier figure of 266.3bn barrels.

In a statement Al Falih welcomed the findings and said they underscored three important aspects of the country’s hydrocarbons sector: that world-leading economies of scale make the fields the lowest cost globally; the carbon intensity of Saudi Arabia’s oil is among the lowest in the world; and the findings underline the accuracy of the country’s reporting. “This certification underscores why every barrel we produce is the most profitable in the world,” he said. D&M’s assessment was based on 54 reservoirs that make up 80% of Saudi Aramco’s reserves. These reservoirs were found to contain around 213.1bn barrels compared to Saudi Aramco’s own estimate of 210.9bn barrels. The audit was limited to booked oil and gas reserves and did not include more recent discoveries including unconventional gas deposits.

CRUDE BURNING: The volumes of crude oil Saudi Arabia has available to export abroad are also affected by levels of domestic consumption. Historically, the country’s power stations have burned crude oil in the summer months as an extra feedstock to meet peak demand for air conditioning. However, a key part of upstream strategy is the development of natural gas fields that can provide a replacement source of feedstock for those power plants and industrial users. Data from the Joint Organisations Data Initiative (JODI) shows Saudi consumption of crude oil in power generation fell in recent years as the new gas came onstream. At its summer peak, the use of oil can typically rise by 600,000 bpd, but JODI figures show it fell to 430,000 bpd by 2017. Jodi data also showed that stockpiles of Saudi crude fell by 95m barrels, or 29%, from October 2015 to April 2018 as production decreases from the Organisation of Petroleum Exporting Countries (OPEC) were implemented. This suggests that as Saudi Arabia complies with new OPEC production cuts from January 2019 there will be ample storage to hold spare capacity.

Developing a deeper oil and gas spare capacity is a priority of Saudi officials to protect the sector and the economy as a whole from potential supply shocks and subsequent price instability, especially as in 2018 the energy sector contributed an estimated 34% of the country’s GDP. Substantial investment in spare capacity and reports that the country’s oil and gas reserves are larger than previously estimated support these efforts and put Saudi Arabia’s energy sector in a position of strength should a future supply shock arise.

By Oxford Business Group

https://oilprice.com/Energy/Crude-Oil/The-Saudi-Plan-To-Boost-Spare-Oil-Production-Capacity.html



NOC Chairman discusses cooperation with Caterpillar and DeGolyer & MacNaughton

mai 7, 2019

National Oil Corporation (NOC) chairman, Eng. Mustafa Sanalla, held a series of meetings yesterday in the US city of Houston as part of NOC’s 60-billion USD procurement drive. The NOC chairman is meeting with US counterparts to discuss the technology and expertise needed to achieve the corporation’s stated production target of 2.1 million barrels per day by 2023.
Sanalla met with Caterpillar’s EMEA director, Mr Mikhail Potekhin, to review the company’s activities in Libya, including a 150-million USD contract for its subsidiary Solar Turbines for power generation equipment, in addition to future potential cooperation and projects with NOC operating companies.
The NOC chairman also met with Mr John Wallace, CEO and chairman of DeGolyer and MacNaughton, a global petroleum consulting company, to discuss possible cooperation and study of Libyan field reservoirs, field development, reserve evaluation, and overall technical assistance to NOC subsidiaries.
The NOC delegation included Dr Khalifa Rajab, chairman of the Zalaf Management Committee, Mr Osama Mohammed Al Lotti, Akakus Management Committee member for Engineering and Projects, and Mr Mohamed Abdo Denbarno, general manager of NOC’s Houston office.
Caterpillar’s EMEA director was accompanied by Mr Shane Singarayer, Oil & Gas director for Africa and Europe, and Mr Raouf Ben Latifa, assistant general manager of MTA, Caterpillar’s representative for Libya and Tunisia.
DeGolyer and MacNaughton’s CEO and chairman was accompanied by Mr John Hornbrook, assistant general manager of the company’s Reservoir Studies Division.



Valeura Energy Inc. Announces Publication of prospectus & proposed LSE admission

avril 17, 2019

Valeura Energy Inc. (TSX: VLE) (« Valeura » or the « Company« ), the upstream natural gas producer focused on appraising and developing an unconventional gas accumulation in the Thrace Basin of Turkey in partnership with Equinor, is pleased to announce the approval by the UK Listing Authority and publication of a prospectus dated April 17, 2019 (the « Prospectus« ), in relation to the proposed admission of the Company’s common shares (the « Shares« ) to the Standard Segment of the Official List of the Financial Conduct Authority (« Admission« ) and trading on the Main Market of the London Stock Exchange (« LSE« ).

A copy of the Prospectus has been submitted to the National Storage Mechanism and is available for inspection (subject to securities laws) at www.morningstar.co.uk/uk/NSM. A copy of the Prospectus has also been made available on the Investors section of the Company’s corporate website: www.valeuraenergy.com/investor-information/lse-listing/.

Subject to final approval by the UK Listing Authority, the Company expects that Admission will become effective and that unconditional dealing in the Shares on the LSE is expected to commence on or around April 25, 2019 under the ticker symbol VLU. The Shares will also continue to trade on the Toronto Stock Exchange (the « TSX« ). All Shares will become fully fungible between the two exchanges. For clarity, the Company is not issuing any new equity at this time, and accordingly, the additional listing is non-dilutive.

Rationale

Valeura’s management and directors believe that the United Kingdom provides an opportunity for the Company to attract greater shareholder interest than is presently available through only its TSX listing. In particular, a listing on the LSE provides access to investors who are mandated to invest in European regulated markets, in addition to generating appeal with a broader range of equity research analysts. Accordingly, Valeura expects this move will elevate its profile amongst its international oil and gas peer group and increase trading liquidity.

The Company believes its 10.1 Tcfe of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate, attributable to its licenses in the Thrace Basin of Turkey will be attractive to European investors. Early results from the Equinor / Valeura drilling programme at Yamalik-1 and Inanli-1 are encouraging and the Company’s efforts are squarely focused on further de-risking the play with a view towards commercial development. Many European investors the Company has met have demonstrated a strong understanding of Turkish gas market dynamics (including the fact that Turkey imports over 99% of its gas supply), and have expressed a willingness to invest.

Sean Guest, Presidentand CEO commented:

« We are delighted to pursue this additional listing on the London Stock Exchange. Our goal is to provide a platform for European and UK investors to participate seamlessly along with our North American shareholders in the next phase of Valeura’s exciting story as we, alongside our partner Equinor, de-risk our unconventional basin-centered gas accumulation play in the Thrace Basin. »

Advisers

Valeura has retained GMP FirstEnergy to act as Financial Adviser to the Company on the listing and will act as corporate broker post-admission. In addition, the Company may appoint additional joint brokers at a later date. London law firm Memery Crystal is acting as legal adviser on the listing.

About Valeura Energy

Valeura Energy Inc. is a Canada-based public company engaged in the exploration, development and production of petroleum and natural gas in Turkey.

Since Valeura was established in 2010, the Company has executed a number of transactions and currently holds interests in 20 production leases and exploration licences in the Thrace Basin of Turkey totalling 0.46 MM acres (gross) or on a net basis 0.37 MM acres of shallow rights and 0.26 MM net acres of deep rights.

Valeura is appraising an unconventional basin-centered gas accumulation play in the Thrace Basin on its deep rights, which has been evaluated by DeGolyer and MacNaughton to hold, effective December 31, 2018, 10.1 Tcfe of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate. By applying 3D seismic, modern reservoir stimulation technology and horizontal and deeper vertical well drilling, Valeura is aiming to achieve commercial scale operations from this tight gas resource.

In addition, the Company owns an extensive network of gas gathering and sales infrastructure to support direct marketing of natural gas to end users, and in 2018, produced an average of 4.3 MMcf/d of natural gas from conventional gas accumulations in its shallower rights.

Additional information relating to Valeura is also available on SEDAR at www.sedar.com and on the Company’s corporate website at www.valeuraenergy.com.

Hard copies of the Prospectus will also be available during normal business hours at the offices of the Company’s UK legal adviser, Memery Crystal LLP, 165 Fleet Street, London EC4Q 2DY, UK.

For further information please contact:

Valeura Energy Inc.(General and Investor Enquiries)+1 403 237 7102
Sean Guest, President and CEO
Steve Bjornson, CFO
Robin Martin, Investor Relations Manager
Contact@valeuraenergy.com, IR@valeuraenergy.com

GMP First Energy(Financial Adviser and Corporate Broker)+44 (0) 20 7448 0200
Jonathan Wright, Hugh Sanderson

CAMARCO (PublicRelations, Media Adviser) +44(0) 20 3757 4980
Owen Roberts, Billy Clegg, Monique Perks, Thayson Pinedo
Valeura@camarco.co.uk

Oil and Gas Advisories& Definitions

Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.

There is no certainty that any portion of the prospective resources will be discovered. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the prospective resources.

Please see the Company’s annual information form for the year ended December 31, 2018, which is available under Valeura’s issuer profile on SEDAR at www.sedar.com, for more information with respect to the Company’s prospective resources, including details regarding risked estimates.

Forward-LookingStatements and Cautionary Statements

This news release contains certain forward-looking statements and information (collectively referred to herein as « forward-looking information« ) including, but not limited to: the proposed Admission and unconditional dealing in the Shares on the LSE (which are subject to the approval of the UK Listing Authority), the timing of such potential Admission and commencement of dealings and the belief that such proposed Admission may bolster value for the Company’s shareholders; the belief that such proposed Admission will provide access to additional investors and that it will generate appeal with a broader range of equity research analysts; the expectation that such proposed Admission will elevate Valeura’s profile amongst its international oil and gas peer group and increase trading liquidity; the potential of the Company’s unconventional basin-centered gas accumulation play in the Thrace Basin; and the Company’s intention to achieve commercial scale operations. Forward-looking information typically contains statements with words such as « anticipate », « estimate », « expect », « target », « potential », « could », « should », « would » or similar words suggesting future outcomes. The Company cautions readers and prospective investors in the Company’s securities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company.

Statements related to « prospective resources » are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the prospective resources can be profitably produced in the future. Specifically, forward-looking information contained herein regarding « prospective resources » include volumes of prospective resources and the ability to finance future development and, the conversion of a portion of prospective resources into reserves.

Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: continued political stability of the areas in which the Company is operating; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the Turkish government and regulators in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; decline rates; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licenses and leases; and the Company’s continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Company’s work programmes and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, fracking and other specialised oilfield equipment and service providers, changes in partners’ plans and unexpected delays and changes in market conditions. Although the Company believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

Forward-looking information involves significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Company including, but not limited to: the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the contemplated timelines and costs for the deep evaluation; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues or civil unrest in Turkey; potential changes in laws and regulations, the uncertainty regarding government and other approvals; counterparty risk; risks associated with weather delays and natural disasters; and the risk associated with international activity. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. See the AIF for a detailed discussion of the risk factors.

Additional information relating to Valeura is also available on SEDAR at www.sedar.com

This announcement doesnot constitute an offer to sell or the solicitation of an offer to buysecurities in any jurisdiction, including where such offer would be unlawful.This announcement is not for distribution or release, directly or indirectly,in or into the United States, Ireland, the Republic of South Africa or Japan orany other jurisdiction in which its publication or distribution would beunlawful.

Neither the TorontoStock Exchange nor its Regulation Services Provider (as that term is defined inthe policies of the Toronto Stock Exchange) accepts responsibility for theadequacy or accuracy of this news release.

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

SOURCE: Valeura Energy Inc. https://www.oilandgas360.com/valeura-energy-inc-announces-publication-of-prospectus-proposed-lse-admission/


Arrow Exploration Corp. Reports 2018 Year-End Reserves

avril 10, 2019

CALGARY, April 8, 2019 /CNW/ – ARROW Exploration Corp. (« Arrow » or the « Company« ) (TSXV: AXL) is pleased to report its year-end 2018 reserves in Colombia and Canada as evaluated by DeGolyer and MacNaughton (« D&M« ) of Dallas, Texas in its report dated effective as of December 31, 2018 (the « D&M Reserves Report« ). This evaluation was prepared using the guidelines outlined in the Canadian Oil and Gas Evaluation Handbook (« COGE Handbook« ) and is in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (« NI 51-101« ).

In accordance with the requirements of NI 51-101, the Company expects to file more detailed disclosure relating to its oil and gas activities for the year ended December 31, 2018 in its 2018 Annual Information Form, together with an operational update, audited annual financial statements and management’s discussion and analysis, on or before April 30, 2019.

Year-End 2018 Company Gross Reserves Highlights

  • 4.97 MMboe of Proved Reserves
  • 10.57 MMboe of Proved plus Probable Reserves
  • Proved Reserves estimated net present value before income taxes of US $56,138,000 calculated at a 10% discount rate
  • Proved plus Probable Reserves estimated net present value before income taxes of US $114,018,000 calculated at a 10% discount rate
  • Reserve Life Index of 8.1 for Proved Reserves and 17.2 for Proved plus Probable Reserves based on average fourth quarter 2018 corporate production of 1,683 boe/d

Mr. Gary Wine, Chief Executive Officer of Arrow, commented, « We’re very pleased to have increased our reserves in 2018 through the acquisition of assets in Colombia complemented by the success of our first exploration well in Colombia in Q4 2018. Our long Reserve Life Index and large under-developed land position in Colombia positions the Company very well for future growth. »

A summary of the Company’s Gross Reserves volumes according to reserve category as at December 31, 2018 is provided in the following table. Numbers in this table may not add exactly due to rounding.

2018 Year-End Company Gross Reserves Volumes (1)

Reserve Category

Light &
Medium
Crude Oil
(Mbbl)

Heavy
Oil
(Mbbl)

Condensate
(Mbbl)

Sales
Gas
(MMcf)

NGL
(Mbbl)

Total Oil
Equivalent
(Mboe)

Proved Developed Producing

1,247

254

0

1,699

12

1,796

Proved Developed Non-Producing

789

154

35

3,366

36

1,575

Proved Undeveloped

0

1,598

0

0

0

1,598

Total Proved

2,036

2,006

35

5,065

48

4,969

Probable

1,475

3,747

13

2,053

22

5,599

Total Proved plus Probable

3,511

5,753

48

7,118

70

10,568

 

Note:
(1)   See Oil and Gas Advisories and Reserves Definitions below.

A summary of the net present value of the Company’s estimated future net revenues associated with the Company’s Gross Reserves as at December 31, 2018 is provided in the following table. The net present values are estimated based on the forecast prices set out below and readers should not assume that the net present values estimated by D&M represent the fair market value of the Company’s Gross Reserves. Numbers in this table may not add exactly due to rounding.

2018 Year-End Company Gross Reserves Values (1)

Before Income Taxes Discounted at (% / year)

Reserves Category

0% (M
US $)

5% (M
US $)

10% (M
US $)

15% (M
US $)

20% (M
US $)

Proved Developed Producing

30,767

28,406

26,422

24,729

23,278

Proved Developed Non-Producing

33,254

27,485

23,043

19,574

16,815

Proved Undeveloped

12,498

9,093

6,673

4,924

3,641

Total Proved

76,519

64,984

56,138

49,227

43,734

Probable

104,207

76,676

57,880

44,694

35,226

Total Proved plus Probable

180,726

141,660

114,018

93,921

78,960

Note:
(1)   The forecast prices used in the calculations of the present value of future net revenue for year-end 2018 are shown below.

 

Forecast Prices, Cost Escalation Rates and Exchange Rates

Year

WTI
Reference
Price

AECO Gas Price

Edmonton
Condensate
Price

Edmonton
Propane
Price

Edmonton
Butane
Price

Inflation
Rates

Exchange
Rate

(US $/bbl)

(CDN
$/MMBtu)

(CDN $/bbl)

(CDN
$/bbl)

(CDN
$/bbl)

(%/year)

(US $/CDN
$)

Forecast

2019

58.58

1.88

70.10

26.13

27.32

2.0

0.757

2020

64.60

2.31

79.21

31.27

41.10

2.0

0.782

2021

68.20

2.74

83.33

34.58

49.28

2.0

0.797

2022

71.00

3.05

86.20

37.25

55.65

2.0

0.803

2023

72.81

3.21

88.16

38.73

57.92

2.0

0.807

2024

74.59

3.31

90.20

39.75

59.27

2.0

0.808

2025

76.42

3.39

92.43

40.76

60.77

2.0

0.808

2026

78.40

3.46

94.87

41.93

62.37

2.0

0.808

2027

79.98

3.54

96.80

42.84

63.65

2.0

0.808

2028

81.59

3.62

98.79

43.80

64.97

2.0

0.808

2029

83.22

3.70

100.76

44.73

66.26

2.0

0.808

2030

84.87

3.78

102.77

45.64

67.56

2.0

0.808

2031

86.57

3.85

104.84

46.56

68.92

2.0

0.808

2032

88.30

3.92

106.94

47.46

70.33

2.0

0.808

2033

90.08

4.00

109.10

48.44

71.72

2.0

0.808

2034 +

+2% / yr

+2% / yr

+2% / yr

+2% / yr

+2% / yr

2.0

0.808

 

Discussion of the D&M Reserves Report

On October 1, 2018, the Company announced it had closed its acquisition of Carrao Energy S.A. from Canacol Energy Ltd. as well as the asset purchase of a 50% beneficial interest in the under-developed Tapir Block (collectively, the « Colombian Assets« ), and completed the reverse takeover transaction with Arrow Exploration Ltd.

During the year ended December 31, 2018, the Company recorded increases in all categories of reserves due primarily to the acquisition of the Colombian Assets. Prior to acquiring the Colombian Assets, the Company’s reserves were located entirely in Canada in the Fir and Pepper Montney Fields. The Company’s Gross Proved and Probable Reserves in these fields constituted approximately 12% of the Company’s Gross Proved and Probable Reserves at year-end 2018. Subsequent to the acquisition of the Colombian Assets, Arrow successfully drilled an exploration well, Danes-1, on the LLA-23 Block in the Llanos Basin in Colombia. The Danes-1 well resulted in recognition of 376 Mbbl of Company Gross Proved Reserves and 509 Mbbl of Company Gross Proved plus Probable Reserves as discoveries in the D&M Reserves Report.

Year-End 2018 Company Gross Reserves Reconciliation

A reconciliation of the Company’s Gross Reserves volumes according to reserve category as at December 31, 2018 compared to the Company’s Gross Reserves volumes at December 31, 2017 is provided in the following table. Numbers in this table may not add exactly due to rounding.

TOTAL PROVED

Light/Medium
Crude Oil
(Mbbl)

Heavy Crude Oil
(Mbbl)

Conventional
Natural Gas (MMcf)

NGL
(Mbbl)

Total Oil
Equivalent
(Mboe)

Opening Balance (December 31, 2017)

16

–

5,371

125

1,036

Extensions

–

–

–

–

0

Improved Recovery

–

–

–

–

0

Technical Revisions

325

(6)

(7)

(38)

280

Discoveries

376

–

–

–

376

Acquisitions

1,468

2,160

–

–

3,628

Dispositions

(16)

(109)

(24)

(2)

(131)

Economic Factors

(24)

–

–

–

(24)

Production

(109)

(39)

(275)

(2)

(196)

Closing Balance (December 31, 2018)

2,036

2,006

5,065

83

4,969

TOTAL PROVED + PROBABLE

Light/Med
Crude Oil
(Mbbl)

Heavy Crude Oil
(Mbbl)

Conventional
Natural Gas (MMcf)

NGL
(Mbbl)

Total Oil
Equivalent
(Mboe)

Opening Balance (December 31, 2017)

23

–

7,707

175

1,483

Extensions

–

–

–

–

0

Improved Recovery

–

–

–

–

0

Technical Revisions

(296)

136

(279)

(52)

(259)

Discoveries

509

–

509

Acquisitions

3,452

6,240

9,692

Dispositions

(23)

(578)

(35)

(3)

(610)

Economic Factors

(45)

(6)

(51)

Production

(109)

(39)

(275)

(2)

(196)

Closing Balance (December 31, 2018)

3,511

5,753

7,118

118

10,568

 

About ARROW Exploration

Arrow Exploration Corp. (operating in Colombia via a branch of its 100% owned subsidiary Carrao Energy S.A.) is a publicly-traded company with a portfolio of Colombian oil assets that are underexploited, underexplored and may offer high potential growth. The Company’s business plan is to rapidly expand oil production from some of Colombia’s most active basins, including the Llanos, Middle Magdalena Valley and Putumayo Basin. The Company’s asset base is predominantly operated with high working interests and typically realizes Brent-linked pricing exposure. Arrow’s management is led by a hands-on and in-country executive team supported by an experienced board.  Arrow is listed on the TSX Venture Exchange under the symbol « AXL ».

OIL AND GAS ADVISORIES

D&M Reserves Report

The D&M Reserves Report was prepared using guidelines outlined in the COGE Handbook and in accordance with NI 51-101.

boe

A boe is determined by converting a volume of natural gas to barrels using the ratio of 6 Mcf to one barrel. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Further, a conversion ratio of 6 Mcf:1 boe assumes that the gas is very dry without significant natural gas liquids. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

RESERVES DEFINITIONS

With respect to the reserves data contained herein, the following terms have the meanings indicated:

« Company Gross Reserves » are the Company’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company.

« developed » reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.

« developed producing » reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

« developed non-producing » reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

« possible » reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

« probable » reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

« proved » reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

« reserves » are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

« undeveloped » reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.

OTHER DEFINITIONS

bbl means barrel.

boe means barrel of oil equivalent.

boe/d means barrel of oil equivalent per day.

CDN $ means Canadian dollars.

Mbbl means thousand barrels.

Mboe means thousand barrels of oil equivalent.

Mcf means thousand cubic feet.

MMboe means million barrels of oil equivalent.

MMcf means million cubic feet.

MM US $ means million United States dollars.

M US $ means thousand United States dollars.

Reserve Life Index is calculated by dividing the Company’s Gross Reserves by working interest production for the year, which, in 2018, is based on fourth quarter average working interest production of 1,683 boe/d. This metric expresses how long a company’s reserves will last at the current production rate with no additions to reserves.

US $ means United States dollars.

FORWARD-LOOKING STATEMENTS

This press release contains certain forward-looking statements within the meaning of applicable securities laws. Forward-looking statements are frequently characterized by words such as « plan », « expect », « project », « target », « intend », « believe », « anticipate », « estimate » and other similar words, or statements that certain events or conditions « may », « should » or « will » occur. In particular, this press release contains forward-looking statements pertaining to, among other things, the following: the timing of the release, and filing (as applicable), of Arrow’s Form 51-101F1, comprehensive operational update and year-end financial statements; Arrow’s business plan; and Arrow’s asset base and price exposure.

Statements relating to « reserves » are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein.

All forward-looking statements are based on Arrow’s beliefs and assumptions based on information available at the time the assumption was made. Arrow believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this press release should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks and assumptions discussed in the Company’s Management’s Discussion and Analysis for the three months ended September 30, 2018, under the headings « Risks and Uncertainties » and « Forward-Looking Statements« . The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Arrow’s future course of action depends on management’s assessment of all information available at the relevant time.

Any « financial outlook » or « future oriented financial information » in this press release, as defined by applicable securities legislation has been approved by management of Arrow. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

Additional information on these and other factors that could affect Arrow’s operations or financial results are included in Arrow’s reports on file with Canadian securities regulatory authorities. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein or otherwise. Arrow undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law. All subsequent forward-looking statements, whether written or oral, attributable to Arrow or persons acting on the Company’s behalf are expressly qualified in their entirety by these cautionary statements.

RESERVES AND DRILLING DATA

This press release contains oil and gas metrics that are commonly used in the oil and gas industry such as « reserve life index ». These metrics have been prepared by management of the Company and do not have standardized meanings or standardized methods of calculation and therefore such measures may not be comparable to similar measures presented by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company, and future performance may not compare to the performance in prior periods and therefore such metrics should not be unduly relied upon. The Company uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented herein, should not be relied upon for investment purposes.

There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserves and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, natural gas and NGL reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. This press release contains estimates of the net present value of the Company’s future net revenue from our reserves. Such amounts do not represent the fair market value of the Company’s reserves. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

Neither the TSX Venture Exchange (TSXV) nor its regulation services provider (as that term is defined in the policies of the TSXV) accepts responsibility for the adequacy or accuracy of this release.

SOURCE ARROW Exploration Corp.

https://www.oilandgas360.com/arrow-exploration-corp-reports-2018-year-end-reserves/


  • More News


    • Bahrain Seeks US Partners for Offshore Shale Discovery

      avril 5, 2019

      • Home to the oil and gas talent base that has successfully developed world-class unconventional resource plays such as the Permian Basin and the Eagle Ford Shale, Texas boasts a formidable storehouse of world-class expertise within its extensive borders.

        The smallest country in the Middle East wants to import some of that Texas-sized know-how to develop a massive oil and gas discovery.

        Shaikh Mohamed bin Khalifa Al-Khalifa, Bahrain’s oil minister who leads the island kingdom’s National Oil and Gas Authority (NOGA), is visiting the Lone Star State this week to entice U.S. operating and service companies to consider doing business in the Arabian Gulf country.

        In 2018, NOGA announced the kingdom’s largest-ever oil and gas discovery in the shallow waters of the Khalij Al-Bahrain Basin. The ministry, working alongside DeGolyer and MacNaughton, Halliburton and Schlumberger to assess the find, has reported that the discovery could hold at least 80 billion barrels of tight oil in place – on a P50 basis – and deep gas reserves ranging from 10 to 20 trillion cubic feet.

        According to a Columbia University Center on Global Energy Policy commentary written by the CEO of consulting firm Qamar Energy, Bahrain would claim a milestone for the oil and gas industry by developing the resource: the first instance of commercial offshore shale oil production. The feat, however, would not mark Bahrain’s first claim to fame in the industry. Standard Oil of California in 1932 made the first Arabian Gulf oil discovery in Bahrain, Al-Khalifa noted.

        “This discovery is obviously an opportunity to increase production of oil but also rich gas – like in Texas with the Eagle Ford and Permian and ethane and other natural gas liquids,” Al-Khalifa told Rigzone. “We’re close to some of the region’s largest ethane processing facilities.”

        For instance, Al-Khalifa pointed out that Bahrain is close to some of the Middle East’s largest petrochemicals sites – such as Dow Chemical Co. and Saudi Aramco’s Sadara complex in Jubail Industrial City, Saudi Arabia.

        Calling unconventional oil and gas production “very much a U.S.-based phenomenon,” Al-Khalifa pointed out that he and other Bahraini officials held earlier meetings with U.S. players last summer. This time around, they are collaborating in talks with operating and service companies as well as entities such as the American Chamber of Commerce (AmCham) and the U.S. Chamber of Commerce.

        “We’re trying to learn from the phenomenon that happened here and see if we can attract some of the companies to locate in Bahrain,” said Al-Khalifa, adding that the kingdom has set up a virtual data room and has “invested money” to better explain the quality of the resource to interested parties. “We’re collecting information and trying to set up the right structure for companies to invest. We want them to make money and apply their technologies.”

        Al-Khalifa added that Bahrain’s free trade agreement with the United States, coupled with its close proximity to Saudi Arabia and other Gulf Cooperation Council countries, make the kingdom a good launching pad for business opportunities in the region. Moreover, he noted that Bahrain boasts a “very liberal and relaxed environment for foreign companies.”

        “It’s an easy place to set up shop” for companies of various sizes, said Al-Khalifa, adding that the kingdom is also looking at the possibility of direct flights to Houston to facilitate trade ties.

        The oil minister declined to reveal specifics tied to ongoing analysis of the discovery, but he said that early signs appear positive. A pair of rigs, one operated by Helmerich and Payne and another by Trinidad Drilling, are currently mobilized under a two-year drilling program to evaluate the resource.

        “I think it’s a bit too early to throw out (anticipated) production numbers, but I can tell you the quality of the rock is very superior,” Al-Khalifa said. “We’re drilling a few wells to make the data available. It is the source rock that gave you the largest oil field in the world.”

        According to a 2018 NOGA written statement, Bahrain officials aim to have the discovery on production within five years.

        https://www.rigzone.com/news/bahrain_seeks_us_partners_for_offshore_shale_discovery-05-apr-2019-158530-article/

    • ROAN RESOURCES, INC. filed on Mon, April 01 10-K

      avril 1, 2019

      • ROAN RESOURCES, INC. filed 10-K with SEC. Read ‘s full filing at 000132642819000006.

        Net acres. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% working interest in 100 acres owns 50 net acres.

        PV-10. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows.

        Standardized measure. Discounted future net cash flows estimated by applying year end prices to the estimated future production of year end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

        Reorganization. Refers to the reorganization transactions contemplated by the master reorganization agreement, dated September 17, 2018, by and among Linn Energy, Inc., Roan Holdings, LLC, and Roan Resources LLC, pursuant to which New Linn’s and Roan Holdings’ respective 50% equity interest in Roan LLC were moved under Roan Inc.

        Riviera Separation. Refers to the reorganization transactions pursuant to which Old Linn contributed certain of its assets to Riviera except for its 50% equity interest in Roan LLC, as further described in Reorganization.

        Our predecessor, Roan LLC, was initially formed by Citizen in May 2017. In June 2017, subsidiaries of Old Linn, together with Citizen and Roan LLC entered into the Contribution, pursuant to which, among other things, Old Linn and Citizen agreed to contribute certain oil and natural gas assets to Roan LLC, each in exchange for a 50% equity interest in Roan LLC. On August 31, 2017, Old Linn and Citizen consummated the transactions contemplated by such contribution agreement. Following these transactions, Citizen’s equity interest in Roan LLC was held through its wholly-owned subsidiary, Roan Holdings.

        In the third quarter of 2018, Old Linn and certain of its subsidiaries undertook an internal reorganization, pursuant to which Old Linn merged with and into a wholly-owned subsidiary of New Linn. Following such internal reorganization, New Linn completed the spin-off of substantially all of its assets, other than its 50% equity interest in Roan LLC.

        On September 17, 2018, New Linn, Roan Holdings and Roan LLC entered into a master reorganization agreement, to effectuate the reorganization of New Linn’s and Roan Holdings’ respective 50% equity interests in Roan LLC under Roan Inc. On September 24, 2018, the Company consummated the Reorganization, which resulted in the existing stockholders of New Linn receiving 50% of the Class A common stock of the Company and Roan Holdings receiving 50% of the Class A common stock of the Company. In connection with the Reorganization, the Company became the owner, indirectly through its wholly-owned subsidiaries, of 100% of the equity in, and is the sole manager of, Roan LLC. The Company is responsible for all operational, management and administrative decisions relating to Roan LLC’s business.

        As of December 31, 2018, we held leasehold interests in approximately 383,000 gross (172,000 net) acres in the Anadarko Basin. At December 31, 2018, our total estimated proved reserves were approximately 305,959 MBoe. For the quarter ended December 31, 2018, our average net daily production was 54.1 MBoe/ d (approximately 27% oil, 42% natural gas and 31% NGLs).

        •Maintain a high degree of operational control to facilitate efficient development and capital budgeting. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As of December 31, 2018, we operated approximately 71% of our total acreage. We believe that maintaining a high degree of control of the development of our properties and of our production enables us to increase hydrocarbon recovery rates, lower capital and operating costs and improve drilling performance through optimization of our drilling, completion and production management techniques. Additionally, we believe operatorship allows us to control wellsite selection, spacing and lateral targeting and manage the pace of our development activities, which we believe can significantly enhance full-cycle returns.

        Maintain a high degree of operational control to facilitate efficient development and capital budgeting. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As of December 31, 2018, we operated approximately 71% of our total acreage. We believe that maintaining a high degree of control of the development of our properties and of our production enables us to increase hydrocarbon recovery rates, lower capital and operating costs and improve drilling performance through optimization of our drilling, completion and production management techniques. Additionally, we believe operatorship allows us to control wellsite selection, spacing and lateral targeting and manage the pace of our development activities, which we believe can significantly enhance full-cycle returns.

        •Large, contiguous acreage position in the core of the Merge play with significant operational control. We are the largest leaseholder in the Merge play, with approximately 115,000 net acres as of December 31, 2018. We believe that the scale and concentration of our acreage position allows for efficient field development through long laterals and shared facilities, with approximately 80% of our Merge sections capable of 1.5 mile or longer lateral development. Additionally, our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs within the Merge play, and provides us development opportunities through multiple stacked prospective development horizons. As of December 31, 2018, we operated 81% of our net acreage in the Merge and we intend to maintain operational control over the majority of our drilling inventory, as we believe this enables us to increase our production and reserves and control our development costs, and ultimately increase shareholder value.

        Large, contiguous acreage position in the core of the Merge play with significant operational control. We are the largest leaseholder in the Merge play, with approximately 115,000 net acres as of December 31, 2018. We believe that the scale and concentration of our acreage position allows for efficient field development through long laterals and shared facilities, with approximately 80% of our Merge sections capable of 1.5 mile or longer lateral development. Additionally, our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs within the Merge play, and provides us development opportunities through multiple stacked prospective development horizons. As of December 31, 2018, we operated 81% of our net acreage in the Merge and we intend to maintain operational control over the majority of our drilling inventory, as we believe this enables us to increase our production and reserves and control our development costs, and ultimately increase shareholder value.

        •Significant financial strength and flexibility. We believe we have a strong financial position, including a low debt profile and a large production base that generates significant cash flow, allowing us to strategically allocate capital in order to enhance shareholder value. We are well-positioned to adjust our development program based on market and industry conditions, as we have minimal commitments to deliver specified volumes, no rig contracts extending beyond 12 months and approximately 84% of our acreage is HBP as of December 31, 2018. We believe that our conservative capital structure, which we will seek to maintain through a disciplined approach to capital spending, and other potential financing sources will provide us with sufficient liquidity and flexibility to execute our development capital program.

        Significant financial strength and flexibility. We believe we have a strong financial position, including a low debt profile and a large production base that generates significant cash flow, allowing us to strategically allocate capital in order to enhance shareholder value. We are well-positioned to adjust our development program based on market and industry conditions, as we have minimal commitments to deliver specified volumes, no rig contracts extending beyond 12 months and approximately 84% of our acreage is HBP as of December 31, 2018. We believe that our conservative capital structure, which we will seek to maintain through a disciplined approach to capital spending, and other potential financing sources will provide us with sufficient liquidity and flexibility to execute our development capital program.

        •High Degree of Operational Control. We expect that we will be able to control operations on approximately 71% of our acreage in the Merge, SCOOP and STACK plays. For these purposes, we have assumed that we will control any unit in which we have leased a minimum of 37.5% of the acreage in the unit. Operational control of our leasehold positions allows us to control the development and production methods, as well as the pace of development on our wells.

        High Degree of Operational Control. We expect that we will be able to control operations on approximately 71% of our acreage in the Merge, SCOOP and STACK plays. For these purposes, we have assumed that we will control any unit in which we have leased a minimum of 37.5% of the acreage in the unit. Operational control of our leasehold positions allows us to control the development and production methods, as well as the pace of development on our wells.

        •Contiguous Acreage Position. A substantial portion of the sections in which we have operational control are offset to the north or south by adjacent controlled sections. Specifically, approximately 66% of our sections in the Merge, SCOOP and STACK plays can be developed on a multi-unit basis. As a result, we are able to develop long lateral horizontal wells for the majority of our drilling program, which we believe have exhibited superior economics as compared to shorter laterals as a result of development cost efficiencies.

        Contiguous Acreage Position. A substantial portion of the sections in which we have operational control are offset to the north or south by adjacent controlled sections. Specifically, approximately 66% of our sections in the Merge, SCOOP and STACK plays can be developed on a multi-unit basis. As a result, we are able to develop long lateral horizontal wells for the majority of our drilling program, which we believe have exhibited superior economics as compared to shorter laterals as a result of development cost efficiencies.

        •Largely Held-by-Production. Approximately 84% of our total acreage position was HBP as of December 31, 2018. We expect this high percentage of HBP acreage to enhance capital efficiencies in our development program, as we will pursue development locations with the favorable risk-adjusted rates of return in our location selection process, as opposed to selecting locations in order to hold acreage.

        Largely Held-by-Production. Approximately 84% of our total acreage position was HBP as of December 31, 2018. We expect this high percentage of HBP acreage to enhance capital efficiencies in our development program, as we will pursue development locations with the favorable risk-adjusted rates of return in our location selection process, as opposed to selecting locations in order to hold acreage.

        We refer to gross and net acreage where we are designated as operator or expect to be designated as operator based on the size of our working interest relative to other working interest owners as ‘our operated acreage’ or acreage we ‘operated’ in this Annual Report. As of December 31, 2018, we operated approximately 71% of our net acreage and had an average working interest of approximately 70% in all of our operated acreage. From January 1, 2018 through December 31, 2018, we drilled or participated in 214 gross horizontal wells that had first sales as of December 31, 2018.

        As of December 31, 2018, approximately 84% of our total net acreage was held by production. This positions us to control the pace of our development efforts, strategically develop our acreage with a near-term focus on high-return projects, limit expenditures on lease renewals and limit the risk of losing high quality acreage through expiration of leases. Additionally, we closely monitor activity of other industry participants and adjust our future development plans based on information and what we believe to be best practices learned from our peers.

        For the year ended December 31, 2018, our average net daily production was 43.7 MBoe/d (approximately 27% oil, 44% natural gas and 29% NGLs). During 2017, our average net daily production was 16.2 MBoe/d (approximately 25% oil, 49% natural gas and 26% NGLs). As of December 31, 2018, we had 1,263 gross (502 net) producing wells online, operated and non-operated.

        Evaluation of Proved Reserves. Approximately 93% of our proved reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers. Our personnel prepared reserve estimates with respect to the remaining approximate 7% of our proved reserves as of December 31, 2018.

        Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. As of December 31, 2018, approximately 84% of our total net acreage was held by production.

        The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.5% to 25.0%, resulting in a net revenue interest to us generally ranging from 74% to 81% of our working interest, with an average net revenue interest of 78.9%.

        The rates charged by many interstate liquids pipelines are currently adjusted pursuant to an annual indexing methodology established and regulated by FERC, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by obtaining market based rate authority (demonstrating the pipeline lacks market power), establishing rates by settlement with all existing shippers, or through a cost of service approach (if the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology). Increases in liquids transportation rates may result in lower revenue and cash flows for us.

        Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, as of December 31, 2018, we had $514.6 million of debt outstanding, with a weighted average interest rate of 5.21%, and a 1.0% increase in interest rates would result in an increase in annual interest expense of $5.1 million, assuming no change in the amount of debt outstanding. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

        Our credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, will determine semiannually on April 1st and October 1st of each year. The borrowing base will depend on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties securing our credit facility and hedging arrangements. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. Any increase in the borrowing base will require the consent of the lenders holding 100% of the commitments.

        As of December 31, 2018, approximately 61% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to lose leases through expiration or could cause us to reclassify our PUDs as unproved reserves. Further, we may be required to write down our PUDs if we do not drill those wells within five years after their respective dates of booking.

        Approximately 16% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

        As of December 31, 2018, approximately 16% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage. Further, to the extent we determine that it is not economic to develop particular undeveloped acreage, we may intentionally allow leases to expire.

        Our top four customers represented approximately 77% of our total revenue for the year ended December 31, 2018. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers for the foreseeable future. Loss of one of these purchasers could adversely affect our revenues in the short term.

        Our principal stockholders and their affiliates beneficially own approximately 75% (50% of which is beneficially owned by Roan Holdings) of our outstanding Class A common stock. Consequently, they will continue to have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. Because our board will be classified through the 2020 annual meeting, certain of our directors will not come up for election until after the 2020 annual meeting. This concentration of ownership and the rights of our principal stockholders will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

        among other things, potential competitive business activities or business opportunities. Several of our principal stockholders are private equity firms or investment funds in the business of making investments in entities in a variety of industries. As a result, our principal stockholders’ existing and future portfolio companies may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor. Certain of our principal stockholders owning approximately 25% of our outstanding Class A common stock own a significant interest in Riviera, the owner of Blue Mountain.

        •Average daily sales volumes were 43.7 MBoe for the year ended December 31, 2018, an increase of 170% compared to 16.2 MBoe during 2017.

        Average daily sales volumes were 43.7 MBoe for the year ended December 31, 2018, an increase of 170% compared to 16.2 MBoe during 2017.

        Production taxes. Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. As all of our oil and natural gas production is in the state of Oklahoma, we are generally subject to a tax rate of 2% for the first 36 months of production and 7% thereafter for wells spud on or after July 1, 2015. Starting with July 2018 production, the tax rate increased to 5% for the first 36 months of production and 7% thereafter. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate.

        Oil sales. Our oil sales increased by approximately $198.4 million, or 258%, to $275.2 million for the year ended December 31, 2018 from $76.9 million for the year ended December 31, 2017. This increase was primarily due to the increase in production as well as the increase in average sales prices received for our produced volumes. Our oil production increased 2,910 MBbls, or 200%, to 4,364 MBbls for the year ended December 31, 2018 from 1,454 MBbls for the year ended December 31, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and throughout 2018. The increase in average sales prices received on our oil production for the year ended December 31, 2018 reflects the increase in the index price for oil in 2018 as compared to 2017.

        Natural gas sales. Our natural gas sales increased by approximately $26.8 million, or 55%, to $76.1 million for the year ended December 31, 2018 from $49.2 million for the year ended December 31, 2017. This increase was primarily due to the increase in production, partially offset by a decrease in average sales prices received for those produced volumes and the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our natural gas production increased 24,308 MMcf, or 138%, to 41,890 MMcf for the year ended December 31, 2018 from 17,582 MMcf for the year ended December 31, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and throughout 2018. The decrease in average sales prices received on our natural gas production for the year ended December 31, 2018 reflects the decrease in the Oklahoma index prices we received under our contract terms for natural gas in 2018 as compared to 2017. Additionally, our average sales price for the year ended December 31, 2018 was reduced by transportation costs for the produced natural gas volumes.

        Production expenses. Production expenses were $47.6 million, or $2.99 per Boe, for the year ended December 31, 2018, which was an increase of $30.7 million, or 182%, from $16.9 million, or $2.86 per Boe, for the year ended December 31, 2017. The increase in production expenses during 2018 compared to 2017 was primarily due to increased production.

        Production taxes. Production taxes were $17.6 million for the year ended December 31, 2018, an increase of $13.9 million, or 377%, from $3.7 million for the year ended December 31, 2017. Production taxes primarily increased due to increased revenues and increased production tax rates, which became effective in July 2018.

        Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $123.9 million, or $7.78 per Boe, for the year ended December 31, 2018, and $37.4 million, or $6.33 per Boe, for the year ended December 31, 2017, which is an increase of $86.5 million or 232%. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production and, to a lesser extent, an increase in the depletion rate for our oil and natural gas properties. The per Boe increase in the depletion rate is attributable to higher capital expenditures in 2018.

        General and administrative. General and administrative expenses were $60.9 million, or $3.82 per Boe, for the year ended December 31, 2018, an increase of $29.5 million or 94% from $31.4 million, or $5.31 per Boe, for the year ended December 31, 2017. During the year ended December 31, 2018, general and administrative expenses included salaries and benefits of $21.7 million and equity-based compensation expense of $11.0 million. Additionally, we incurred consulting and professional fees as part of the implementation of systems and processes and transition efforts in 2018 as well as $4.6 million of costs associated with the Reorganization. These expenses were offset by bonuses paid by Citizen of approximately $9.0 million during the year ended December 31, 2017.

        Natural gas sales. Our natural gas sales increased by approximately $33.1 million, or 206%, to $49.2 million for the year ended December 31, 2017 from $16.1 million for the year ended December 31, 2016. This increase was due to increased production and an increase in average sales prices received for our produced volumes. Our natural gas production increased by 11,200 MMcf, or 175%, for the year ended December 31, 2017 compared with the year ended December 31, 2016. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in 2017. The increase in average sales prices received on our natural gas production for the year ended December 31, 2017 reflects the increase in the index price for the year ended December 31, 2017 as compared to the year ended December 31, 2016.

        NGL sales. Our NGL sales increased by approximately $32.0 million, or 385%, to $40.3 million for the year ended December 31, 2017 from $8.3 million for the year ended December 31, 2016. This increase was primarily due to increased production as well as an increase in average sales prices received for our produced volumes. Our NGL production increased by 978 MBbls, or 179%, for the year ended December 31, 2017 compared with the year ended December 31, 2016. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in 2017. The increase in average sales prices received on our NGL production for the year ended December 31, 2017 reflects the increase in the index prices for NGLs in 2017.

        Production expenses. Production expenses were $16.9 million, or $2.86 per Boe, for the year ended December 31, 2017, which was an increase of $11.8 million, or 231%, from $5.1 million, or $2.17 per Boe, for the year ended December 31, 2016. The increase in production expenses during 2017 compared to 2016 was primarily due to increased production.

        Gathering, transportation and processing. Gathering, transportation, and processing costs were $18.6 million, or $3.15 per Boe, for the year ended December 31, 2017, which was an increase of $12.7 million, or 215%, from $5.9 million, or $2.52 per Boe, for the year ended December 31, 2016. The increase in gathering, transportation and processing costs during 2017 as compared to 2016 was primarily related to increased production.

        Production taxes. Production taxes were $3.7 million for the year ended December 31, 2017, which was an increase of $2.6 million, or 239%, from $1.1 million for the year ended December 31, 2016. Production taxes primarily increased due to increased revenues.

        Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $37.4 million, or $6.33 per Boe, for the year ended December 31, 2017, which was an increase of $12.4 million, or 50%, from $25.0 million, or $10.64 per Boe, for the year ended December 31, 2016. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production.

        General and administrative. General and administrative expenses were $31.4 million, or $5.31 per Boe, for the year ended December 31, 2017, which was an increase of $25.8 million, or 462%, from $5.6 million, or $2.38 per Boe, for the year ended December 31, 2016. During the year ended December 31, 2017, general and administrative expenses included fees paid to Citizen and Linn under our MSAs of $10.0 million, bonuses paid by Citizen of approximately $9.0 million, equity-based compensation expense of $0.4 million and professional and consulting expenses related to Roan’s transition and system implementation.

        Amounts borrowed under the credit facility bear interest at London Interbank Offered Rate (‘LIBOR’) or the alternate base rate (‘ABR’) at our election. The rate used for ABR loans is based on the higher of the prime rate, the federal funds effective rate plus 0.50% or the one-month LIBOR rate plus 1%. Either rate is adjusted upward by an applicable margin (ranging from 2.00% to 3.00% for LIBOR and 1.00% to 2.00% for ABR), based on the utilization percentage of the credit facility. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50% based on utilization, which is payable at the end of each calendar quarter.

        The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, we are prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon our internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, we are required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per our most recent reserve report.

        (1) Includes interest expense on our outstanding borrowings calculated using the weighted average interest rate of 5.21% at December 31, 2018.

        Proved reserves are based on the quantities of oil, natural gas and NGL that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Our reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers, and our internal staff. DeGolyer and MacNaughton prepared reserve estimates for 93% of our total reserves.

        At December 31, 2018, we had a net asset position of $101.8 million related to our derivative contracts. Utilizing actual derivative contractual volumes under our fixed price swaps as of December 31, 2018, an increase of 10% in the forward curves associated with the underlying commodity would have decreased the net asset position to $55.9 million, while a decrease of 10% in the forward curves associated with the underlying commodity would have increased the net asset position to $159.7 million.

        As of December 31, 2018, we had $514.6 million in outstanding borrowings under our credit facility with a weighted average interest rate on these borrowings of 5.21%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $5.1 million based on outstanding borrowings of $514.6 million under our credit facility as of December 31, 2018.

        Roan LLC was initially formed by Citizen Energy II, LLC (‘Citizen’) in May 2017. On August 31, 2017, the Company executed a contribution agreement (the ‘Contribution Agreement’) by and among Roan LLC, Citizen, Linn Energy Holdings, LLC (‘LEH’) and Linn Operating, LLC (‘LOI’, and together with LEH, ‘Linn’) pursuant to which, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within an area-of-mutual-interest to the Company (collectively the ‘Contribution’). In exchange for their contributions, Citizen and Linn each received a 50% equity interest in Roan LLC.

        In 2018, the Company adopted a 401(k) retirement plan and health and welfare benefit plans in which our employees are eligible to participate. Under the 401(k) retirement plan, the Company provides for an employer match of employee contributions of up to 6% of eligible compensation and a profit-sharing contribution of up to 8% of eligible compensation. For the year ended December 31, 2018, the Company paid $1.2 million in contributions to the plan.

        As noted in Note 1 – Business and Organization, in connection with the Contribution, Roan LLC acquired from Linn certain oil and natural gas properties located in Central Oklahoma (the ‘Linn Acquisition’). In exchange for the contributed oil and natural gas properties, Linn received a 50% equity interest in Roan LLC valued at approximately $1.3 billion based on the value of the business. Accordingly, the fair value of the Company was primarily comprised of the fair value of these contributed oil and natural gas properties. See Note 10 – Equity for further discussion of the equity issued to Linn.

        (1) Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%.

        In September 2017, the Company entered into a $750.0 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (as amended, the ‘2017 Credit Facility’). In September 2018, the redetermination resulted in an increase to the borrowing base to $675.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of December 31, 2018, the Company had $514.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility. At December 31, 2018, the weighted average interest rate on borrowings under our 2017 Credit Facility was 5.21%. The 2017 Credit Facility is secured by substantially all of the assets of the Company.

        The Company amended the 2017 Credit Facility in September 2018 to increase the borrowing base as noted above as well as to allow for permitted additional debt of up to $500 million before any reduction in the borrowing base would occur, to reduce the applicable margin for both London Interbank Offered Rate (‘LIBOR’) and alternate base rate (‘ABR’) loans by 0.25% for each utilization level, and to reduce the commitment fee rate for the two lowest utilization levels to 0.375%.

        The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report.

        For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company Agreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued 1.5 billion membership units representing capital interests in Roan LLC (the ‘LLC Units’) for a 50% equity interest in Roan LLC, to Linn in exchange for the contribution of oil and natural gas properties. See Note 4 – Acquisitions for additional discussion of the Linn Acquisition. Additionally, Roan LLC issued 1.5 billion LLC Units, which represented a 50% equity interest in Roan LLC, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the LLC Units issued to Citizen was the same as that of the LLC Units issued to Linn.

        For the period January 1, 2017 through August 31, 2017, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (the ‘Citizen Operating Agreement’), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B interests. Class A interests represented capital interests in Citizen and Class B interests represented interests in profits, losses and distributions. Distributions were made to the Class A interests and Class B interests members pro rata in accordance with their membership interests; however, once the Class A interests members received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B interests members received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement.

        Prior to the Reorganization, Roan LLC granted performance share units to certain of its employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of performance share units under the Plan, hereafter referred to as the ‘PSUs,’ and are subject to the terms of the Plan and individual award agreements. The amount of PSUs that can be earned range from 0% to 200% based on the Company’s market value on December 31, 2020 (‘Performance Period End Date’). The Company’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the Company’s Class A common stock for the 30 consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the issuance of one share of the Company’s Class A common stock. Other than the security in which the PSUs are settled, no terms of the PSUs were modified in connection with the conversion of the PSUs.

        The Company’s effective combined U.S. federal and state income tax rate for the year ended December 31, 2018 excluding discrete items was 24.3%. During the year ended December 31, 2018, the Company recognized income tax expense of $356.9 million, including $304.5 million related to the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization.

        (2)Income tax expense is calculated using results from the period after the Reorganization when the Company became a taxable entity and the Company’s effective tax rate of 24.3%.

        Income tax expense is calculated using results from the period after the Reorganization when the Company became a taxable entity and the Company’s effective tax rate of 24.3%.

        https://whatsonthorold.com/2019/04/01/roan-resources-inc-filed-on-mon-april-01-10-k/

    • Approach Resources Inc. Reports Fourth Quarter and Full-Year 2018 Financial and Operating Results

      mars 20, 2019

      • Approach Resources Inc. AREX, -29.16% today reported financial and operational results for the fourth quarter and full-year 2018, estimated year-end 2018 proved reserves and provided an update on its efforts to pursue deleveraging alternatives.

        Fourth Quarter 2018 Highlights

        • Fourth quarter production of 963 MBoe or 10.5 MBoe/d
        • Net income was $0.9 million, or $0.01 per diluted share. Adjusted net loss (non-GAAP) was $6.9 million, or $0.07 per diluted share
        • EBITDAX (non-GAAP) of $13.5 million
        • Cash operating expenses (non-GAAP) of $8.85 per Boe, a 28% decrease over the prior quarter

        Full-Year 2018 Highlights

        • Full year production of 4,082 MBoe or 11.2 MBoe/d
        • Year-end 2018 proved reserves 180.1 MMBoe, an increase in oil reserves of 5% over the prior year
        • Drilled six and completed nine horizontal Wolfcamp wells during the year with an inventory of seven drilled and uncompleted wells at year-end
        • Net loss was $19.9 million, or $0.21 per diluted share. Adjusted net loss (non-GAAP) was $25 million, or $0.26 per diluted share
        • EBITDAX (non-GAAP) of $59 million, a 7% increase over the prior year
        • Revenue of $114 million, an 8% increase over the prior year
        • Unhedged cash margin (non-GAAP) of $16.19 per Boe, a 16% increase over the prior year

        Adjusted net loss, EBITDAX, cash operating expenses and unhedged cash margin are non-GAAP measures. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and reconciliations of adjusted net loss and EBITDAX to net income (loss) and unhedged cash margin to revenues.

        Management Comment

        Ross Craft, Approach’s Chairman and CEO, commented, “Due in part to the sharp decline in commodity prices and extreme WAHA gas discount in the basin in the fourth quarter, we focused on conserving capital and reducing our cash operating expenses during the quarter. Additionally, we continued to evaluate alternatives to reduce our leverage. In 2019, we will continue to focus on alternatives to strengthen our balance sheet and manage our covenants under our credit facility. Our capital expenditure budget is designed to be funded primarily through cash flows from operations. As a result of the current commodity price environment, as well as our focus on addressing our leverage, we do not expect any significant drilling and completion activity in the first quarter of 2019.”

         

        Company Continues to Explore Deleveraging Alternatives

        In order to improve our leverage position to meet upcoming financial covenants under the revolving credit facility, we have been, and currently are, pursuing or considering a number of deleveraging and strategic actions, which in certain cases may require the consent of current lenders, stockholders or bond holders. If we do not accomplish one or more of the deleveraging transactions discussed below, we do not believe we will be able to comply with the total leverage ratio covenant in our revolving credit facility beginning with the measurement date of March 31, 2019.

        On April 12, 2018, our largest shareholder, Wilks Brothers, LLC, and its affiliate SDW Investments, LLC (collectively, “Wilks”), disclosed on Schedule 13D/A that they intended to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of approximately $60 million of 7% Senior Notes due 2021 (the “Senior Notes”) currently held by Wilks (the “Exchange Transaction”). In April 2018, our board of directors formed a committee of independent directors (the “Committee”) to evaluate a potential Exchange Transaction as well as other strategic alternatives (the “Competing Transactions”). The Committee hired financial and legal advisors to advise the Committee on these matters. The Committee engaged in discussions with Wilks regarding an Exchange Transaction in 2018, but in mid-2018 the Wilks and the Committee deferred further discussions regarding a stand-alone Exchange Transaction pending resolution of the Company’s discussions regarding the potential transaction described in the following paragraph.

        In addition, management has reviewed numerous cash flow producing properties for potential acquisition over the last several years in order to grow our production base and reduce our leverage ratio to a sustainable level and one that is in compliance with our financial covenants. In early 2018, we retained a financial advisor, separate from the Committee’s advisor, and began discussions with a potential seller and multiple financing counterparties for the purchase of a set of substantial cash flow producing properties. Despite a deteriorating commodity price market, discussions with both the seller and financing parties progressed throughout 2018. However, no definitive agreements ultimately were executed, and the negotiations currently are not active.

        In March 2019, our board of directors expanded the scope of the Committee to explore, in addition to an Exchange Transaction, other financing alternatives and deleveraging transactions, including without limitation (i) amendments or waivers to the covenants or other provisions of our revolving credit facility, (ii) raising new capital in private or public markets and (iii) restructuring our balance sheet either in court or through an out of court agreement with creditors. We are also considering operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives, including: (i) acquiring assets with existing production and cash flows by issuing preferred and common equity to finance such acquisitions; (ii) selling existing producing or midstream assets; (iii) merging with a strategic partner. The Committee has re-commenced discussions with the Wilks regarding an Exchange Transaction and intends to continue those discussions as part of its review of financing alternatives and deleveraging transactions. We currently are in discussions with our CEO regarding his separation from the Company. We expect to engage in discussions with our President and Chief Administrative Officer regarding their continued employment or potential separation. The Company is evaluating plans for succession. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.

        If an event of default under our credit facility occurred, our lenders could accelerate the maturity of the outstanding indebtedness, making it immediately due and payable, and we would not have sufficient liquidity to repay those amounts. However, we believe we have adequate liquidity for current, near-term working capital needs from cash generated from operations and, to the extent available, unused borrowing capacity under our revolving credit facility, each assuming (i) no reduction in our borrowing base from our semi-annual borrowing base redetermination and (ii) no acceleration of amounts due under our revolving credit facility.

        Fourth Quarter 2018 Results

        Production for fourth quarter 2018 totaled 963 MBoe (10.5 MBoe/d), made up of 26% oil, 35% NGLs and 39% natural gas. Average realized commodity prices for fourth quarter 2018, before the effect of commodity derivatives, were $55.23 per Bbl of oil, $19.91 per Bbl of NGLs and $0.79 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $22.86 per Boe for fourth quarter 2018.

        Net income for fourth quarter 2018 was $0.9 million, or $0.01 per diluted share, on revenues of $22.4 million. Excluding the increase in the fair value of our commodity derivatives of $10.1 million, adjusted net loss (non-GAAP) for fourth quarter 2018 was $6.9 million, or $0.07 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2018 was $13.5 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net income.

        Lease operating expense (“LOE”) averaged $5.21 per Boe. Production and ad valorem taxes averaged $1.80 per Boe, or 7.7% of oil, NGLs and gas sales. Exploration costs were $0.43 per Boe. Total general and administrative (“G&A”) costs averaged $2.80 per Boe, including cash G&A costs of $1.84 per Boe. Depletion, depreciation and amortization expense averaged $14.96 per Boe. Interest expense totaled $6.6 million.

        Full-Year 2018 Results

        Production for 2018 was 4,082 MBoe (11.2 MBoe/d), made up of 26% oil, 36% NGLs and 38% natural gas. Average realized commodity prices for 2018, before the effect of commodity derivatives, were $62.04 per Bbl of oil, $23.28 per Bbl of NGLs and $1.49 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $26.21 per Boe for 2018.

        Net loss for 2018 was $19.9 million, or $0.21 per diluted share, on revenues of $114 million. Excluding the increase in fair value of our commodity derivatives of $6.7 million, adjusted net loss (non-GAAP) for 2018 was $25 million, or $0.26 per diluted share. EBITDAX (non-GAAP) for 2018 was $59 million. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net loss and EBITDAX to net loss.

        LOE averaged $5.18 per Boe. Production and ad valorem taxes averaged $2.19 per Boe, or 7.8% of oil, NGLs and gas sales. Exploration costs were $0.10 per Boe. Total G&A costs averaged $5.13 per Boe, including cash G&A costs of $4.38 per Boe. Depletion, depreciation and amortization expense averaged $15.05 per Boe. Interest expense totaled $25.1 million.

        Operations Update

        In light of continued commodity price deterioration and the extreme WAHA gas discount in the basin, we deferred third and fourth quarter 2018 drilling and completion activities, and incurred capital expenditures of $0.2 million in the fourth quarter.

        In 2018, we focused on executing a disciplined capital budget and managing natural production decline through surface facility optimization, operating efficiencies and investment in well repairs, workovers and maintenance. During 2018, we drilled six and completed nine horizontal Wolfcamp wells. Of these, three wells were completed in the A bench, three wells were completed in the B bench and three wells were completed in the C bench. At December 31, 2018, we had seven horizontal wells waiting on completion.

        Our extensive infrastructure network of centralized production facilities, water transportation, handling and recycling system, gas lift lines and salt water disposal wells continues to provide sustainable competitive advantages and environmentally responsible facility operations. In 2018, we maintained an industry leading average drilling and completion cost of $4.6 million per horizontal well and LOE per Boe of $5.18.

        Fourth Quarter and Full-Year 2018 Production

        Fourth quarter 2018 production totaled 963 MBoe (10.5 MBoe/d). Full-year 2018 production totaled 4,082 MBoe (11.2 MBoe/d).

        Three and 12 Months Ended
        December 31, 2018
        Three months 12 months
        Production:
        Oil (MBbls) 251 1,070
        NGLs (MBbls) 338 1,443
        Gas (MMcf) 2,240 9,408
        Total (MBoe) 963 4,082
        Total (Mboe/d) 10.5 11.2

        2018 Estimated Proved Reserves and Costs Incurred

        Year-end 2018 proved reserves totaled 180.1 MMBoe. Year-end 2018 proved reserves were 29% oil, 31% NGLs and 40% natural gas. Proved developed reserves represent approximately 37% of total year-end 2018 proved reserves.

        At December 31, 2018, substantially all of our proved reserves were located in our core operating area in the southern Midland Basin. Year-end 2018 estimated proved reserves included 168.2 MMBoe attributable to the horizontal Wolfcamp shale play.

        Extensions and discoveries for 2018 were 35 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2018, we reclassified 33.1 MMBoe of proved undeveloped reserves to unproved reserves. The reclassified reserves are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 0.2 MMBoe resulting from updated well performance and technical parameters, and an increase of 1.9 MMBoe due to higher commodity prices, partially offset by a decrease of 1.4 MMBoe due to an increase in operating expenses and natural gas price differentials.

        The following table summarizes the changes in our estimated proved reserves during 2018.

        Oil NGLs Natural Gas Total
        (MBbls) (MBbls) (MMcf) (MBoe)
        Balance — December 31, 2017 50,060 57,948 441,228 181,545
        Extensions and discoveries 14,572 8,819 69,362 34,951
        Production(1) (1,070 ) (1,443 ) (10,793 ) (4,312 )
        Revisions to previous estimates (11,104 ) (8,788 ) (73,359 ) (32,117 )
        Balance — December 31, 2018 52,458 56,536 426,438 180,067

        (1) Production includes 1,385 MMcf related to field fuel.

        Our preliminary, unaudited estimate of the standardized after-tax measure of discounted future net cash flows (“standardized measure”) of our proved reserves at December 31, 2018, was $660 million. The PV-10 (non-GAAP), or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2018, was $761.8 million.

        The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2018 proved reserves and PV-10 at SEC pricing. PV-10 is a non-GAAP measure. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition of PV-10 and reconciliation to the standardized measure (GAAP). Our reserve estimates and our calculation of standardized measure and PV-10 are based on the 12-month average of the first-day-of-the-month pricing of $65.68 per Bbl of oil, $24.12 per Bbl of NGLs and $3.17 per MMBtu of natural gas during 2018.

        Capital Expenditures

        Fourth quarter capital expenditures were $0.2 million. Net capital expenditures incurred during 2018 totaled $46.8 million and were attributable to drilling and development ($39.4 million), infrastructure projects and equipment ($6.6 million), exploratory project ($0.4 million) and acreage acquisitions and extensions ($0.4 million).

        Liquidity Update

        At December 31, 2018, we had a $1 billion senior secured revolving credit facility in place with a borrowing base of $325 million, and liquidity of $23.2 million. Our credit facility is subject to scheduled redeterminations of our borrowing base semi-annually, based on our reserves. Our next anticipated redetermination is expected to take place in the second quarter of 2019, although our lender has the option to redetermine our borrowing base outside of our anticipated schedule. Continued low commodity prices may adversely impact the results of the upcoming redetermination, and have a significant negative impact on the Company’s liquidity. If our borrowing base is reduced below the amount outstanding under our credit agreement, we may be required to repay a portion of our outstanding borrowings, and we may not have sufficient liquidity to meet this requirement. See “Supplemental Non-GAAP Financial and Other Measures” below for our definition and calculation of liquidity.

        Commodity Derivatives Update

        We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. At present, approximately 19% of 2019 forecasted oil and 19% of NGL production is hedged. The table below is a summary of our current derivatives positions.

        Contract
        Commodity and Period Type Volume Transacted Contract Price
        Crude Oil
        January 2019 — December 2019 Collar 500 Bbls/day $65.00/Bbl – $71.00/Bbl
        NGLs (C2 – Ethane)
        January 2019 — March 2019 Swap 900 Bbls/day $14.123/Bbl
        NGLs (C3 – Propane)
        January 2019 — March 2019 Swap 600 Bbls/day $35.165/Bbl
        January 2019 — June 2019 Swap 75 Bbls/day $42.00/Bbl
        NGLs (NC4 – Butane)
        January 2019 — March 2019 Swap 200 Bbls/day $38.63/Bbl
        NGLs (C5 – Pentane)
        January 2019 — December 2019 Swap 100 Bbls/day $65.10/Bbl
        January 2019 — December 2019 Swap 100 Bbls/day $65.31/Bbl

        Guidance

        The Company’s capital budget for 2019 is a range of $30 million to $60 million, depending on commodity prices. The table below sets forth our production and operating costs and expenses guidance for 2019, anticipating a capital budget of $30 million funded primarily through cash flows from operations. The eventual results of our strategic and deleveraging efforts may have a substantial impact on the Company’s ability to achieve the guidance set forth below.

        2019 Guidance
        Capital Expenditures (in millions) $30
        Production:
        Oil (MBbls) 925 — 975
        NGLs (MBbls) 1,250 — 1,350
        Gas (MMcf) 8,650 — 8,750
        Total (MBoe) 3,600 — 3,800
        Cash operating costs (per Boe):
        Lease operating $5.00 — 6.00
        Production and ad valorem taxes 8.5% of oil and gas revenues
        Cash general and administrative $4.50 — 5.50
        Non-cash operating costs (per Boe):
        Non-cash general and administrative $0.75 — 1.25
        Exploration $0.25 — 0.75
        Depletion, depreciation and amortization $15.00 — 17.00

        As further discussed below under “Forward-Looking and Cautionary Statements,” our guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control. In addition, our 2019 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and natural gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

        Conference Call Information and Summary Presentation

        The Company will host a conference call on Tuesday, March 19, 2019, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss fourth quarter and full-year 2018 financial and operational results. Those wishing to listen to the conference call, may do so by visiting the Events page under the Investor Relations section of the Company’s website, www.approachresources.com, or by phone:

        Dial in: (844) 884-9950 / Conference ID: 6089010
        International Dial In: (661) 378-9660
        A replay of the call will be available on the Company’s website or by dialing:
        Dial in: (855) 859-2056 / Passcode: 6089010

        In addition, a fourth quarter and full-year 2018 summary presentation will be available on the Company’s website.

        About Approach Resources

        Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and natural gas reserves in the Midland Basin of the greater Permian Basin in West Texas. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

        This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include expectations of anticipated financial and operating results. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. These assumptions, risks and uncertainties include, but are not limited to, our ability to comply with the covenants in our revolving credit facility, our leverage negatively affecting a redetermination under our credit facility, oil, NGL and natural gas prices, our ability to obtain financing to fund our long-term forecasted capital budget, and our ability to access capital markets. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on assumptions, risks and uncertainties related to the Company is available in the Company’s SEC filings, including our Annual Report on Form 10-K. The Company’s SEC filings are also available on the Company’s website at www.approachresources.com . Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

        UNAUDITED RESULTS OF OPERATIONS
        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        Revenues (in thousands):
        Oil $ 13,874 $ 14,082 $ 66,398 $ 52,748
        NGLs 6,730 8,530 14,033 27,702
        Gas 1,771 5,805 33,604 24,899
        Total oil, NGLs and gas sales 22,375 28,417 114,035 105,349
        Net cash payment on derivative settlements (364 ) (2,878 ) (7,050 ) (4,359 )
        Total oil, NGLs and gas sales including derivative impact $ 22,011 $ 25,539 $ 106,985 $ 100,990
        Production:
        Oil (MBbls) 251 270 1,070 1,107
        NGLs (MBbls) 338 377 1,443 1,486
        Gas (MMcf) 2,240 2,498 9,408 9,829
        Total (MBoe) 963 1,064 4,082 4,232
        Total (MBoe/d) 10.5 11.6 11.2 11.6
        Average prices:
        Oil (per Bbl) $ 55.23 $ 52.09 $ 62.04 $ 47.63
        NGLs (per Bbl) 19.91 22.61 23.28 18.64
        Gas (per Mcf) 0.79 2.32 1.49 2.53
        Total (per Boe) $ 23.24 $ 26.71 $ 27.94 $ 24.89
        Net cash payment on derivative settlements (per Boe) (0.38 ) (2.70 ) (1.73 ) (1.03 )
        Total including derivative impact (per Boe) $ 22.86 $ 24.01 $ 26.21 $ 23.86
        Costs and expenses (per Boe):
        Lease operating $ 5.21 $ 4.77 $ 5.18 $ 4.23
        Production and ad valorem taxes 1.80 2.09 2.19 2.04
        Exploration 0.43 0.38 0.10 0.86
        General and administrative (1) 2.80 5.16 5.13 5.75
        Depletion, depreciation and amortization 14.96 15.20 15.05 16.66
        (1) Below is a summary of general and administrative expense:
        General and administrative – cash component $ 1.84 $ 4.09 $ 4.38 $ 4.65
        General and administrative – noncash component (share-based compensation) 0.96 1.07 0.75 1.10
        APPROACH RESOURCES INC. AND SUBSIDIARIES
        UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
        (In thousands, except shares and per-share amounts)
        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        REVENUES:
        Oil, NGLs and gas sales $ 22,375 $ 28,417 $ 114,035 $ 105,349
        EXPENSES:
        Lease operating 5,013 5,076 21,129 17,902
        Production and ad valorem taxes 1,734 2,219 8,923 8,644
        Exploration 411 406 420 3,657
        General and administrative 2,693 5,491 20,922 24,333
        Depletion, depreciation and amortization 14,403 16,173 61,432 70,521
        Total expenses 24,254 29,365 112,826 125,057
        OPERATING (LOSS) INCOME (1,879 ) (948 ) 1,209 (19,708 )
        OTHER:
        Interest expense, net (6,595 ) (5,370 ) (25,117 ) (21,053 )
        Gain on debt extinguishment — — — 5,053
        Commodity derivative gain (loss) 9,747 (1,377 ) (321 ) (262 )
        Other income (expense) 1 — (29 ) 32
        INCOME (LOSS) BEFORE INCOME TAX (BENEFIT) PROVISION 1,274 (7,695 ) (24,258 ) (35,938 )
        INCOME TAX (BENEFIT) PROVISION:
        Current (66 ) — (66 ) (66 )
        Deferred 472 (53,512 ) (4,281 ) 76,487
        NET INCOME (LOSS) $ 868 $ 45,817 $ (19,911 ) $ (112,359 )
        EARNINGS (LOSS) PER SHARE:
        Basic $ 0.01 $ 0.51 $ (0.21 ) $ (1.35 )
        Diluted $ 0.01 $ 0.51 $ (0.21 ) $ (1.35 )
        WEIGHTED AVERAGE SHARES OUTSTANDING:
        Basic 94,739,926 90,114,659 94,581,294 83,404,104
        Diluted 94,736,926 90,114,659 94,581,294 83,404,104
        UNAUDITED SELECTED FINANCIAL DATA
        Unaudited Consolidated Balance Sheet Data December 31,
        (in thousands) 2018 2017
        Cash and cash equivalents $ 22 $ 21
        Other current assets 16,203 16,679
        Property and equipment, net, successful efforts method 1,068,422 1,082,876
        Total assets $ 1,084,647 $ 1,099,576
        Current liabilities $ 21,077 $ 25,067
        Long-term debt (1) 384,993 373,460
        Deferred income taxes 77,821 82,102
        Other long-term liabilities 11,511 11,531
        Stockholders’ equity 589,245 607,416
        Total liabilities and stockholders’ equity $ 1,084,647 $ 1,099,576

        (1) Long-term debt at December 31, 2018, is comprised of $85.2 million in 7% senior notes due 2021 and $301.5 million in outstanding borrowings under our revolving credit facility, net of issuance costs of $0.7 million and $1 million, respectively. Long-term debt at December 31, 2017, is comprised of $85.2 million in 7% senior notes due 2021 and $291 million in outstanding borrowings under our revolving credit facility, net of issuance costs of $1.1 million and $1.7 million, respectively.

        Unaudited Consolidated Cash Flow Data Year Ended December 31,
        (in thousands) 2018 2017
        Net cash provided by (used in):
        Operating activities $ 34,744 $ 37,454
        Investing activities (42,764 ) (52,409 )
        Financing activities 8,021 14,955

        Supplemental Non-GAAP Financial and Other Measures

        This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations below of the non-GAAP financial measures to the most directly comparable GAAP financial measures and on the Non-GAAP Financial Information page under the Financial Reporting subsection of the Investor Relations section of our website at www.approachresources.com.

        Adjusted Net Loss

        This release contains the non-GAAP financial measures adjusted net loss and adjusted net loss per diluted share, which excludes (1) non-cash fair value gain commodity derivatives, (2) gain on debt extinguishment, (3) write-off of deferred tax assets, (4) acquisition related costs, (5) tax benefit related to federal tax law change, and (6) related income tax effect on adjustments and other discrete tax items. The amounts included in the calculation of adjusted net loss and adjusted net loss per diluted share below were computed in accordance with GAAP. We believe adjusted net loss and adjusted net loss per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        The table below provides a reconciliation of adjusted net loss to net income (loss) for the three and twelve months ended December 31, 2018 and 2017 (in thousands, except per-share amounts).

        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        Net income (loss) $ 868 $ 45,817 $ (19,911 ) $ (112,359 )
        Adjustments for certain items:
        Non-cash fair value (gain) loss on derivatives (10,111 ) (1,500 ) (6,729 ) (4,097 )
        Gain on debt extinguishment — — — (5,053 )
        Write-off of deferred tax assets — — — 139,090
        Acquisition related costs — 110 — 110
        Tax benefit related to change in federal tax law — (51,939 ) — (51,939 )
        Tax effect and other discrete tax items (1) 2,318 1,446 1,677 4,443
        Adjusted net loss $ (6,925 ) $ (6,066 ) $ (24,963 ) $ (29,805 )
        Adjusted net loss per diluted share $ (0.07 ) $ (0.07 ) $ (0.26 ) $ (0.36 )

        (1) The estimated income tax impacts on adjustments to net income (loss) are computed based upon a statutory rate of 21% and 35%, applicable to 2018 and 2017, respectively. Additionally, this includes the tax impact of a tax shortfall related to share-based compensation of $0.2 million, and $1 million for the three months ended December 31, 2018, and December 31, 2017, respectively; and $0.3 million and $1.3 million for the years ended December 31, 2018, and December 31, 2017, respectively.

        EBITDAX

        We define EBITDAX as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) non-cash fair value (gain) loss on derivatives, (5) gain on debt extinguishment, (6) interest expense, net, and (7) income tax provision (benefit). EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income (loss) because of its wide acceptance by the investment community as a financial indicator of a company’s ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        The table below provides a reconciliation of EBITDAX to net income (loss) for the three and twelve months ended December 31, 2018 and 2017 (in thousands).

        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        Net income (loss) $ 868 $ 45,817 $ (19,911 ) $ (112,359 )
        Exploration 411 406 420 3,657
        Depletion, depreciation and amortization 14,403 16,173 61,432 70,521
        Share-based compensation 923 1,138 3,047 4,656
        Non-cash fair value (gain) loss on derivatives (10,111 ) (1,500 ) (6,729 ) (4,097 )
        Gain on debt extinguishment — — — (5,053 )
        Interest expense, net 6,595 5,370 25,117 21,053
        Income tax provision (benefit) 406 (53,512 ) (4,347 ) 76,421
        EBITDAX $ 13,495 $ 13,892 $ 59,029 $ 54,799

        Unhedged Cash Margin and Cash Operating Expenses

        We define unhedged cash margin as revenue, less cash operating expenses. We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense, and (3) share-based compensation expense. Unhedged cash margin and cash operating expenses are not measures of operating income or cash flows as determined by GAAP. The amounts included in the calculations of unhedged cash margin and cash operating expenses were computed in accordance with GAAP. Unhedged cash margin and cash operating expenses are presented herein and reconciled to the GAAP measures of revenue and operating expenses. We use unhedged cash margin and cash operating expenses as an indicator of the Company’s profitability and ability to manage its operating income and cash flows. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        The table below provides a reconciliation of unhedged cash margin and cash operating expenses to revenues and operating expenses for the three and twelve months ended December 31, 2018 and 2017 (in thousands, except per-Boe amounts).

        Three Months Ended Twelve Months Ended
        December 31, December 31,
        2018 2017 2018 2017
        Revenues $ 22,375 $ 28,417 $ 114,035 $ 105,349
        Production (Mboe) 963 1,064 4,082 4,232
        Average realized price (per Boe) $ 23.24 $ 26.71 $ 27.94 $ 24.89
        Operating expenses $ 24,254 $ 29,365 $ 112,826 $ 125,057
        Exploration (411 ) (406 ) (420 ) (3,657 )
        Depletion, depreciation and amortization (14,403 ) (16,173 ) (61,432 ) (70,521 )
        Share-based compensation (923 ) (1,138 ) (3,047 ) (4,656 )
        Cash operating expenses $ 8,517 $ 11,648 $ 47,927 $ 46,223
        Cash operating expenses per Boe $ 8.85 $ 10.95 $ 11.75 $ 10.92
        Unhedged cash margin $ 13,858 $ 16,769 $ 66,108 $ 59,126
        Unhedged cash margin per Boe $ 14.39 $ 15.76 $ 16.19 $ 13.97

        PV-10

        The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $761.8 million at December 31, 2018, and was calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and gas, of $65.68 per Bbl of oil, $24.12 per Bbl of NGLs and $3.17 per MMBtu of natural gas price during 2018, adjusted for basis differentials, grade and quality.

        PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.

        The table below reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

        (in millions) December 31, 2018
        PV-10 $ 761.8
        Less income taxes:
        Undiscounted future income taxes (478.2 )
        10% discount factor 376.4
        Future discounted income taxes (101.8 )
        Standardized measure of discounted future net cash flows $ 660

        Liquidity

        Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company’s ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the measurement on a company’s financial statements. This measurement is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        The table below summarizes our liquidity at December 31, 2018 and 2017 (in thousands).

        Year Ended December 31,
        2018 2017
        Credit Facility commitments $ 325,000 $ 325,000
        Cash and cash equivalents 22 21
        Long-term debt — Credit Facility (301,500 ) (291,000 )
        Undrawn letters of credit (325 ) (325 )
        Liquidity $ 23,197 $ 33,696

        View source version on businesswire.com: https://www.businesswire.com/news/home/20190318005810/en/

        SOURCE: Approach Resources Inc.

        Sergei Krylov
        Executive Vice President & Chief Financial Officer
        ir@approachresources.com
        817.989.9000

        Copyright Business Wire 2019

        https://www.marketwatch.com/press-release/approach-resources-inc-reports-fourth-quarter-and-full-year-2018-financial-and-operating-results-2019-03-18

    • Frontera Delivers Strong Fourth Quarter and 2018 Results and Replaces 103% of 2018 Produced Reserves

      mars 14, 2019

      • Frontera Energy Corporation (TSX: FEC) (« Frontera » or the « Company« ) announced today the release of its consolidated financial statements, management discussion and analysis (« MD&A« ), Annual Information Form (« AIF« ) and Form 51-101 F1 – Statement of Reserves Data and Other Oil and Gas Information for the Company (the « F1 Report« ) for the year ended December 31, 2018. These documents, among others, will be posted on the Company’s website at www.fronteraenergy.ca and SEDAR at www.sedar.com. All values in this news release and the Company’s financial disclosures are in United States dollars unless otherwise stated. All production numbers in this news release are before royalties unless otherwise stated.

        FOURTH QUARTER AND FULL YEAR 2018 HIGHLIGHTS

        Strong Fourth Quarter Operational and Financial Results

        • Production averaged 71,924 boe/d, an increase of 8% compared to the third quarter of 2018 and a 3% increase compared to the fourth quarter of 2017.
        • Oil production represented over 95% of total company production in the fourth quarter of 2018, compared to 94% in the third quarter of 2018 and 92% in the fourth quarter of 2017.
        • Net loss of $116.6 million ($1.17/share) in the fourth quarter of 2018 includes $143.9 million of non-recurring charges relating to payments under terminated pipeline contracts, impairments on infrastructure investments, oil and gas assets and on the carrying values of investments in associates offset by the benefit of the reversal of provisions related to high-price clause. This compares to a net loss of $32.5 million ($0.33/share) in the fourth quarter of 2017 which included a net benefit $63.8 million from the reversal of a provision related to high-price clause, offset by impairments on oil and gas assets and transmission line assets. Refer to notes 7 and 26 of the consolidated financial statements for more detail.
        • Operating EBITDA of $118.4 million was 27% higher than the prior quarter and 13% higher than the prior year quarter.
        • General and administrative expenses (« G&A« ) of $21.8 million in the fourth quarter of 2018 declined 5% from the third quarter of 2018 and 11% from the fourth quarter of 2017, reflecting the benefit of the Company’s ongoing focus on efficiency and cost reduction projects throughout the organization.
        • Capital expenditures of $156.4 million were 26% higher than in the third quarter of 2018 and 41% higher than the fourth quarter of 2017, as anticipated, reflecting the completion of the Quifa SW water handling expansion project which has added over 3,000 bbl/d to Company production so far in 2019.
        • Cash used by operating activities of $3.5 million in the fourth quarter of 2018 reflected the normalization of timing of accounts receivable and payable through the cash management process.
        • The Company repurchased for cancellation 1.3 million shares at a cost of $13.3 million (C$13.87/share) under its normal course issuer bid during the fourth quarter of 2018. To date the Company has repurchased for cancellation 2.4 million shares at a cost of $24.9 million (C$13.96/share), representing 47% of the authorized buyback under the normal course issuer bid.
        • Total cash, including restricted cash, was $588.4 million as at December 31, 2018, down 25% from the third quarter of 2018 and down 9% compared to December 31, 2017.
        • Hedged on approximately 27% of expected 2019 production after royalties using put options with a Brent price of $55.00/bbl.

        2018 Operational and Financial Results

        • Frontera’s 2P Reserves as at December 31, 2018, were 154.9 MMboe after royalties, which was 0.4% higher than at the end of 2017.
        • The Company achieved a 2P Reserves Replacement Ratio of 103% based on 2018 production after royalties of 23.6 MMboe.
        • The Company’s 2P Reserve Life Index increased to 6.8 years in 2018 from 6.1 years in 2017.
        • Net present value of 2P reserves discounted at 10%, before taxes, was $2.2 billion at the end of 2018, a decrease of 13% compared to 2017. The decrease reflects lower heavy oil price assumptions of $3.00/bbl over the first 10 years, partially offset by an increase of $0.80/bbl in light oil price assumptions. Heavy oil represents 62% of proved plus probable reserves, light oil 36% and natural gas 2%.
        • Net present value of proved plus probable reserves discounted at 10%, after taxes, was $1.9 billion, a decrease of 1% compared to 2017.
        • 2018 production averaged 71,032 boe/d before royalties (63,187 boe/d after royalties) within the annual guidance range of 70,000 to 72,000 boe/d before royalties (63,000 to 65,000 boe/d after royalties).
        • Net loss of $259.1 million ($2.59/share) in 2018 includes $327.0 million of non-recurring charges relating to payments under terminated pipeline contracts, impairments on infrastructure investments, oil and gas assets and on the carrying values of investments in associates offset by the benefit of the reversal of provisions related to high-price clause. This compares to a net loss of $216.7 million ($2.17/share) in 2017 which included $27.2 million of non-recurring charges relating to impairments offset by the reversal of a provision related to high-price clause. Please refer to notes 7 and 26 of the consolidated financial statements for more detail.
        • Operating EBITDA in 2018 increased by $28.7 million, or 7%, to $422.5 million compared to the prior year.
        • Oil and gas sales and other revenue of $1.4 billion in 2018 were 15% higher compared to the prior year. Net sales for the year (including the impact of realized losses on risk management contracts, royalties, and diluent costs) decreased by 2% compared to 2017.
        • Operating netback for 2018 was $25.98/boe, 14% higher than $22.79/boe in 2017.
        • The Company generated $312.0 million in cash provided by operating activities in the year compared to $314.4 million in the prior year, contributing to a strong balance sheet with a total cash position, including restricted cash, of $588.4 million as at December 31, 2018.
        • Capital expenditures during 2018 were $446.1 million compared to $236.4 million in the prior year.

        Dividends

        • On December 5, 2018, the Company’s Board of Directors declared a dividend, payable on January 17, 2019 of C$0.33 per share (approximately $25 million in aggregate), to common shareholders of record on January 3, 2019.
        • On March 13, 2019, the Company’s Board of Directors declared a dividend, payable on or about April 16, 2019 of C$0.165 (approximately $12.5 million in aggregate), to common shareholders of record on April 2, 2019.

        2018 Guidance

        The Company achieved or exceeded its original 2018 guidance targets, with the exception of production guidance where it achieved revised guidance. Average production before royalties of 71,032 boe/d (within guidance range of 70,000 to 72,000 boe/d), operating EBITDA of $422.5 million (within guidance range of $400 to $450 million), capital expenditures of $446.1 million (within revised guidance range of $440 to $460 million, below original guidance of $450 to $500 million) and G&A expenses of $93.0 million (below revised guidance range of $95 to $105 million).

        Richard Herbert, Chief Executive Officer of Frontera, commented:

        « Frontera stabilized its core production base in 2018 as the Company began enhancing the portfolio to deliver growth. As planned, we replaced over 100% of produced reserves in 2018, which was enabled by the completion of the Quifa water handling expansion project, as well as exploration successes at Alligator and Coralillo in the Guatiquia block and Jaspe in the Quifa North area. Significant investment in Colombia in 2018 has contributed to a strong start in 2019, particularly in the Quifa SW field with new water handling facilities in operation. In addition, after last year’s interruptions, production from Block 192 in Peru has recently restarted. As it returns to peak levels, total company production is the strongest it has been in over a year. With solid production and cash flow generation, we are executing a number of initiatives to drive production and reserves growth including; successfully being awarded two highly prospective blocks in an exploration bid round in Ecuador, and testing the deliverability of natural gas production from our Z-1 block, offshore Peru. We are also very excited by upcoming drilling on the VIM-1 block in Colombia and on the Corentyne block offshore Guyana later this year. »

        Gabriel de Alba, Chairman of the Board of Directors of the Company, commented:

        « Thanks to substantial progress by the Frontera team in 2018, the Company is better positioned than ever to deliver returns to shareholders. With improved capital allocation and a plan to sustain production and reserves from our existing production base at current levels for the next five years – both of which we’re already delivering on – Frontera can generate sufficient cash flow to drive growth initiatives in the upstream business, as well as take steps to further enhance shareholder returns, as oil prices permit. Continuing on our progress in reducing G&A in 2018, we are pursuing additional opportunities to improve the efficiency and cost structure of the business, especially in the field, and to monetize non-core assets.  These actions will generate additional cash flow and capital for growth and enhanced equity returns. Frontera is off to a positive start in 2019. Production is strong, Brent oil prices are averaging close to $63.00/bbl, in line with our guidance, and the Company is currently benefiting from narrow oil price differentials. »

        Financial Results

        2018

        2017

        Q4

        Full Year

        Q4

        Full Year

        Revenue

        ($MM)

        265

        1,320

        345

        1,254

        Net loss (1)

        ($MM)

        (117)

        (259)

        (33)

        (217)

        Per share – basic (2)

        ($)

        (1.17)

        (2.59)

        (0.33)

        (2.17)

        Net sales (3)

        ($MM)

        228

        1,083

        307

        1,111

        Cash (used) provided by operating activities

        ($M)

        (3)

        312

        115

        314

        Operating EBITDA (3)

        ($MM)

        118

        423

        104

        394

        Operating EBITDA margin (Operating EBITDA/Net sales)(3)

        (%)

        52%

        39%

        34%

        35%

        General and administrative (G&A)

        ($MM)

        22

        93

        24

        105

        Total cash, including restricted cash(4)

        ($MM)

        588

        588

        644

        644

        Working capital

        ($MM)

        216

        216

        310

        310

        Average shares outstanding – basic

        (MM)

        99,417

        99,842

        100,012

        100,008

        1

        Net loss attributable to equity holders of the Company.

        2

        Basic and diluted weighted average numbers of common shares for the year ended December 31, 2018 were 99,841,652 (December 31, 2017: 100,007,826 ).

        3

        These metrics are Non-IFRS financial measures. See Advisories – « Non-IFRS Financial Measures » – below and « Non-IFRS Measures » on page 17 of the MD&A.

        4

        Includes $446 million of cash and cash equivalents, $40 million of short term restricted cash and $103 million of long term restricted cash.

        The average Brent oil benchmark price decreased in the fourth quarter of 2018 to an average of $68.60/bbl, down 9.5% from $75.84/bbl in the third quarter of 2018. Brent oil benchmark price averaged $61.46/bbl in the fourth quarter of 2017. The Company’s realized oil price of $62.15/bbl in the fourth quarter of 2018 excludes the impact of $5.55/bbl of realized losses on risk management contracts.

        During the fourth quarter of 2018, net loss attributable to equity holders of the Company was $116.6 million ($1.17 /share), compared with net income of $45.1 million ($0.45/share) in the third quarter of 2018. The net loss primarily reflects several one-time items, including impairments on investments in associates, exploration expenses and payments under terminated pipeline contracts offset by the reversal of provisions related to high-price clause which in aggregate amounted to $143.9 million in the fourth quarter of 2018. Please refer to notes 7 and 26 of the consolidated financial statements for more detail.

        For the fourth quarter of 2018, net sales of $228.4 million were 23.7% lower than the third quarter of 2018 reflecting lower sales price and volumes, and 25.5% lower than the fourth quarter of 2017 as a result of losses on risk management contracts and lower sales volumes partially offset by higher oil prices.

        Cash used by operating activities was $3.5 million in the fourth quarter compared to cash provided by operating activities of $177.6 million in the third quarter of 2018, reflecting lower sales volumes and oil prices as well as one-time cash payments associated with the termination of pipeline contracts.

        Operating EBITDA of $118.4 million in the fourth quarter of 2018 increased 26.7% in comparison with the third quarter of 2018, and was 13.5% higher than in the fourth quarter of 2017 as a result of a reversal of the overlift accumulated in the second and third quarters of 2018.

        Frontera continued taking actions to improve its cost structure in the fourth quarter by completing a project to increase organizational efficiency and reduce costs. These efforts helped the Company deliver lower G&A expenses of $21.8 million in the fourth quarter of 2018, a decrease of 4.9% from the third quarter of 2018, and a decrease of 10.7% from the fourth quarter of 2017. Going forward, the Company will look to further improve operational efficiency to drive additional cost savings.

        Production and Development Summary(1)

        Production, before royalties

        2018

        2017

        Q4

        Q3

        Q2

        Q1

        Full Year

        Q4

        Full Year

        Oil and liquids (bbl/d)

        Colombia

        59,687

        57,655

        59,108

        58,246

        58,675

        61,719

        65,142

        Peru

        8,974

        4,616

        8,414

        10,737

        8,171

        2,840

        5,122

        Total oil and liquids (bbl/d)

        68,661

        62,271

        67,522

        68,983

        66,846

        64,559

        70,264

        Natural gas (boe/d)(2)

        Colombia

        3,263

        4,122

        4,504

        4,875

        4,186

        5,315

        5,784

        Total natural gas (boe/d)

        3,263

        4,122

        4,504

        4,875

        4,186

        5,315

        5,784

        Total equivalent production (boe/d)

        71,924

        66,393

        72,026

        73,858

        71,032

        69,874

        76,048

        1

        Additional production details are available in the MD&A « Financial and operational results » section, page 6.

        2

        Colombian standard natural gas conversion ratio of 5.7 Mcf per bbl as required by the Colombian Ministry of Mines and Energy.

        Current production before royalties is over 67,500 boe/d (over 63,000 boe/d after royalties), as production from Block 192 continues to ramp up following the repair of the NorPeruano pipeline. Production, before royalties in the fourth quarter of 2018 averaged 71,924 boe/d (63,898 boe/d after royalties), an increase of 8.3% compared with the third quarter of 2018. The increase in quarterly production was a result of increased production from Peru while the NorPeruano pipeline was in service during October and November, as well as increases from light, medium and heavy oil in Colombia. Production from Colombia increased 1.9% during the fourth quarter of 2018 compared with the previous quarter, as a result of increased production at the Quifa block following the completion of the water handling expansion project, as well as production from the Coralillo discovery on the Guatiquia block.

        Sales volumes for the three months ended December 31, 2018, were 50,298 boe/d, 17.6% lower than the previous quarter, reflecting the settlement of an overlift of 809 Mbbl built up in the second and third quarters of 2018 and an increase in inventory in Colombia, resulting in lower volumes available for sale.

        During the fourth quarter of 2018, total capital expenditures were $156.4 million, up 26.1% than the previous quarter and 40.6% from the fourth quarter of 2017. The increase during the fourth quarter relates to the construction of additional water handling facilities in the Quifa SW field and the testing costs associated with the Acorazado-1 exploration well on the Llanos 25 block in Colombia. Additionally, Colombian exploration wells were drilled at Jaspe and Sabanero as well as two development wells at Zopilote Sur on the Cravo Viejo block.

        A total of 29 wells were drilled in the fourth quarter of 2018, slightly lower than the 31 wells planned, as the Cocodrilo exploration well was deferred with the new acreage awarded at the Coralillo field on the Guatiquia block. Twenty-two heavy oil development wells and two water injection wells were drilled in the Quifa SW area in connection with the increased fluid handling capacity that was initiated during the fourth quarter. Three light oil development wells were drilled with two on the Candelilla field on the Guatiquia block and one at the Zopilote Sur field on the Cravo Viejo block. The Company also completed the drilling of two exploration wells, Jaspe 7D in the Quifa North area and the Chaman well on the Sabanero block. Additionally, four of five planned water injection wells were converted from producing wells on the Neiva and Orito blocks.

        During the first quarter of 2019, the Company plans to drill 28 wells including 23 development wells in the Quifa SW area, two development wells in its light and medium oil areas, two exploration wells, and a conversion of an existing well to a water injection well at Orito. The Company is targeting to keep seven rigs active throughout the first quarter of 2019.

        2018 Reserves:

        For the year ended December 31, 2018, the Company’s reserves were independently evaluated by DeGolyer and MacNaughton (« D&M »), in accordance with  the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter) (« COGEH ») and – National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities (« NI 51-101 ») and are based on the Company’s 2018 year-end estimated reserves as evaluated by D&M in their reserves report dated February 25, 2019 with an effective date of December 31, 2018 (the « Reserves Report »). See Advisory Note regarding Oil and Gas Information.

        The Company’s proved plus probable reserves before royalties of 170.5 MMboe (154.9 MMboe after royalties) for the year ended December 31, 2018. This compares with 172.7 MMboe of proved plus probable reserves before royalties (154.3 MMboe after royalties) for the year ended December 31, 2017. Proved reserves of 104.8 MMboe for the year ended December 31, 2018 represent 68% of the total proved plus probable reserves compared with 74% of the total proved plus probable reserves for the year ended December 31, 2017.

        The following table provides a summary of the Company’s oil and natural gas reserves based on forecast prices and costs effective December 31, 2018 as applied in the Reserves Report. The Company’s net reserves after royalties incorporate all applicable royalties under Colombia and Peru fiscal legislation based on forecast pricing and production rates evaluated in the Reserves Report, including any additional participation interest related to the price of oil applicable to certain Colombian blocks, as at year-end 2018.

        Reserves at December 31, 2018 (MMboe)(1)(6)

        Country

        Field

        Proved (1P)

        Probable

        Proved Plus
        Probable (2P)

        Hydrocarbon Type

        Gross

        Net

        Gross

        Net

        Gross

        Net

        Colombia

        Quifa SW block

        45.0

        38.6

        11.8

        9.7

        56.8

        48.4

        Heavy oil

        Other heavy oil blocks(2)

        35.8

        34.2

        15.0

        14.2

        50.8

        48.4

        Heavy oil

        Light/medium oil blocks(3)

        29.9

        27.5

        23.1

        21.2

        52.9

        48.7

        Light and medium oil and
        associated natural gas

        Natural gas blocks(4)

        1.6

        1.6

        1.1

        1.1

        2.7

        2.7

        Natural gas

        Sub-total

        112.3

        101.9

        51.0

        46.2

        163.2

        148.2

        Oil and natural gas

        Peru

        Light/medium oil and
        natural gas blocks (5)

        3.5

        2.9

        3.8

        3.8

        7.3

        6.7

        Light and medium oil and
        associated natural gas

        Total at Dec. 31, 2018

        115.8

        104.8

        54.8

        50.0

        170.5

        154.9

        Oil and natural gas

        Total at Dec. 31, 2017

        128.7

        114.1

        44.0

        40.2

        172.7

        154.3

        Difference

        (12.9)

        (9.3)

        10.8

        9.8

        (2.2)

        0.6

        2018 Production

        25.8

        22.9

        Total Reserves
        Incorporated

        23.7

        23.6

        1

        See « Boe Conversion » section in the « Advisories » at the end of this press release.

        2

        Includes Cajua, Jaspe, Quifa North, Sabanero, and CPE-6 blocks.

        3

        Includes Cubiro, Cravo Viejo, Canaguaro, Guatiquia, Casimena, Corcel, Neiva, Cachicamo, and other producing blocks.

        4

        Includes La Creciente field and Guaduas block.

        5

        Includes onshore Block 192 and offshore Block Z1.

        6

        « Gross » refers to WI before royalties, « Net » refers to WI after royalties.

        Note: Numbers in the table may not add due to rounding differences.

        2018 2P Reserves Reconciliation (1)

        Oil Equivalent Gross 2P
        Reserves (MMboe)

        Oil Equivalent Net 2P
        Reserves (MMboe)

        December 31, 2017

        172.7

        154.3

        Net Additions

        8.7

        8.0

        Economic and Technical Revisions

        15.0

        15.6

        Production(2)

        (25.8)

        (22.9)

        December 31, 2018

        170.5

        154.9

        1

        Numbers in the table may not add due to rounding differences.

        2

        Production represents the production for the twelve month period ended December 31, 2018.

        Fourth Quarter and Year End 2018 Conference Call Details:

        As previously disclosed, a conference call for investors and analysts will be held on Thursday, March 14, 2019 at 8:00 a.m. (MDT), 9:00 a.m. (GMT-5) and 10:00 a.m. (EDT). Participants will include Gabriel de Alba, Chairman of the Board of Directors, Richard Herbert, Chief Executive Officer, David Dyck, Chief Financial Officer and select members of the senior management team.

        Analysts and investors are invited to participate using the following dial-in numbers:

        Participant Number (International/Local):

        (647) 427-7450

        Participant Number (Toll free Colombia):

        01-800-518-0661

        Participant Number (Toll free North America):

        (888) 231-8191

        Conference ID:

        7391259

        Webcast Audio:

        www.fronteraenergy.ca

        A replay of the conference call will be available until 10:59 p.m. (GMT-5) and 11:59 p.m. (EDT) Thursday, March 28, 2019 and can be accessed using the following dial-in numbers:

        Encore Toll Free Dial-in Number:

        1-855-859-2056

        Local Dial-in Number:

        (416)-849-0833

        Encore ID:

        7391259

        About Frontera:

        Frontera Energy Corporation is a Canadian public company and a leading explorer and producer of crude oil and natural gas, with operations focused in South America. The Company has a diversified portfolio of assets with interests in more than 30 exploration and production blocks. The Company’s strategy is focused on sustainable growth in production and reserves. Frontera is committed to conducting business safely, in a socially and environmentally responsible manner. Frontera’s common shares trade on the Toronto Stock Exchange under the ticker symbol « FEC ».

        If you would like to receive News Releases via e-mail as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe.

        Advisories:

        Cautionary Note Concerning Forward-Looking Statements

        This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding estimates and/or assumptions in respect of production, revenue, cash flow and costs, drilling plans and timing thereof, the Company’s exploration and development plans and objectives, the timing of payment of dividends and implementation of cost saving initiatives) are forward-looking statements. Any statements relating to reserves and resource estimates including, without limitation, potential resources and reserves, are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; uncertainties associated with estimating oil and natural gas reserves; failure to establish estimated resources or reserves; volatility in market prices for oil and natural gas; fluctuation in currency exchange rates; inflation; changes in equity markets; perceptions of the Company’s prospects and the prospects of the oil and gas industry in Colombia and the other countries where the Company operates or has investments; uncertainties relating to the availability and costs of financing needed in the future; the uncertainties involved in interpreting drilling results and other geological data; and the other risks disclosed under the heading « Risk Factors » and elsewhere in the Company’s AIF dated March 13, 2019 filed on SEDAR at www.sedar.com. Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.

        In addition, reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this news release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.

        Non-IFRS Financial Measures

        This news release contains the following financial terms that do not have standardized definitions in the International Financial Reporting Standards (« IFRS »): « operating EBITDA », « operating netback », and « net sales ». These financial measures, together with measures prepared in accordance with IFRS, provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. The Company’s determination of these non-IFRS measures may differ from other reporting issuers, and therefore are unlikely to be comparable to similar measures presented by other companies. Further, these non-IFRS measures should not be considered in isolation or as a substitute for measures of performance or cash flows prepared in accordance with IFRS. These financial measures are included because management uses this information to analyze operating performance and liquidity.

        Management believes that EBITDA is a common measure used to assess profitability before the impact of different financing methods, income taxes, depreciation and impairment of capital assets and amortization of intangible assets.

        EBITDA is a commonly used measure that adjusts net income (loss) as reported under IFRS to exclude the effects of income tax expense, net finance costs and Depletion, depreciation and amortization expense.

        Operating EBITDA represents the operating results of the Company’s primary business, excluding the items noted above, including fees paid on suspended pipeline capacity, other investments (such as infrastructure assets), certain non-cash items (such as impairments, foreign exchange and unrealized risk management contracts, and share based compensation) and gains or losses arising form the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA as they are not indicative of the underlying core operating performance of the Company.

        The following table provides a complete reconciliation of net loss to Operating EBITDA:

        Three months ended
        December 31

        Year ended
        December 31

        ($M)

        2018

        2017

        2018

        2017

        Net loss (1)

        (116,631)

        (32,544)

        (259,083)

        (216,703)

        Fees paid on suspended pipeline capacity

        —

        24,656

        82,372

        108,831

        Payments under terminated pipeline contracts

        59,040

        —

        74,618

        —

        Share-based compensation

        166

        2,119

        4,042

        2,605

        Depletion, depreciation and amortization

        80,461

        95,526

        316,751

        382,246

        Impairment and exploration expenses and other

        125,944

        35,774

        315,292

        126,844

        Reversal of provision related to PAP

        (41,079)

        (99,622)

        (62,911)

        (99,622)

        Restructuring, severance and other costs

        8,092

        2,436

        14,592

        12,617

        Share of income from associates

        (8,952)

        (14,809)

        (83,601)

        (76,186)

        Equity tax

        —

        —

        —

        11,694

        Foreign exchange loss (gain)

        13,087

        3,472

        3,375

        (1,876)

        Finance income

        (7,581)

        (4,620)

        (25,832)

        (17,646)

        Finance expense

        14,668

        10,098

        52,724

        41,814

        Unrealized (gain) loss on risk management contracts

        (31,392)

        80,774

        (107,337)

        71,762

        Other income (loss), net

        832

        4,322

        4,741

        5,425

        Reclassification of currency translation adjustments

        (2,753)

        —

        48,094

        —

        Loss on extinguishment of debt

        —

        —

        25,628

        —

        Income tax expense (recovery)

        16,067

        (10,438)

        18,721

        15,265

        Non-controlling interests

        8,429

        7,172

        322

        26,788

        Operating EBITDA

        118,398

        104,316

        422,508

        393,858

        1

        Net loss attributable to equity holders of the Company.

        2018

        2017

        ($M)

        Q4

        Q3

        Q2

        Q1

        Q4

        Q3

        Q2

        Q1

        Financial and Operational results:

        Operating EBITDA

        118,398

        93,455

        124,667

        85,988

        104,316

        110,243

        86,857

        92,442

        Netbacks

        Management believes that Netback is a useful measure to assess the net profit after all the costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performance expressed as profit per barrel. Operating Netback represents realized price per barrel plus realized gain or loss on financial derivatives, less production costs, high price royalties and royalties paid in cash, and transportation and diluent costs, and shows how efficient the Company is at extracting and selling its product. Refer to the « Operating Netback » section on page 9 of the MD&A.

        Net Sales

        Net sales is a non-IFRS subtotal that adjusts revenue to include realized gains and losses from risk management contracts while removing the cost of dilution activities. This is a useful indicator for management as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these risk management activities. The exclusion of diluent cost is helpful to understand the Company’s sales performance based on the net realized proceeds from production net of dilution, the cost of which is partially recovered when the blended product is sold. Net sales does not include the sales and purchases of oil and gas for trading as the gross margins from these activities are not considered significant or material to the Company’s operations.  Refer to the reconciliation in the « Sales » section on page 10 of the MD&A.

        Advisory Note Regarding Oil and Gas Information

        The reserves information contained in this press release has been prepared in accordance with NI 51-101.  Complete reserves disclosure required in accordance with NI 51-101 is contained in the F1 Report filed on SEDAR.  Actual oil and natural gas reserves and future production may be greater than or less than the estimates provided in this news release. There is no assurance that forecast prices and costs assumed in the Reserves Report, and presented in this this news release, will be attained and variances from such forecast prices and costs could be material. The estimated future net revenue from the production of the disclosed oil and natural gas reserves in this news release does not represent the fair market value of these reserves.

        The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

        The term reserves replacement ratio is used in this news release. This term is consistent with disclosure by other oil and gas companies. Reserves replacement ratio is calculated by dividing proved plus probable boe reserves added during the year by the total boe production during the year.

        Boe Conversion

        The term « boe » is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet to barrels is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, boe has been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy. 

        Definitions:

        1P

        Proved reserves.

        2P

        Proved plus probable reserves.

        bbl(s)

        Barrel(s) of oil.

        bbl/d

        Barrel of oil per day.

        Boe

        Refer to « Boe Conversion » disclosure above.

        boe/d

        Barrel of oil equivalent per day.

        Mbbl

        Thousand barrels of oil.

        Mboe

        Thousand barrels of oil equivalent.

        MMboe

        Million barrels of oil equivalent.

        Mcf

        Thousand cubic feet.

        Net Production

        Net production after royalties represents the Company’s working interest volumes, net of royalties and internal consumption.

        WI

        Working interest.

        SOURCE Frontera Energy Corporation

        https://www.prnewswire.com/news-releases/frontera-delivers-strong-fourth-quarter-and-2018-results-and-replaces-103-of-2018-produced-reserves-300812301.html

    • Valeura Announces Fourth Quarter 2018 Financial and Operating Results, Year-End 2018 Reserves

      mars 14, 2019

      •  

        Valeura Energy Inc. (TSX:VLE) (« Valeura » or the « Company« ), the upstream natural gas producer focused on appraising and developing an unconventional gas accumulation in the Thrace Basin of Turkey, is pleased to report its financial and operating results for the three month period ended December 31, 2018 and the year ended December 31, 2018, and year-end 2018 reserves and prospective resources.

        The complete quarterly reporting package for the Company, including the audited financial statements and associated management’s discussion and analysis (« MD&A« ) and the 2018 annual information form (« AIF« ), have been filed on SEDAR at www.sedar.com and posted on the Company’s website at www.valeuraenergy.com.

        2018 Financial and Operating Results Highlights

        • Average Q4 2018 realised gas prices of $9.06/Mcf, up 36% from Q3 2018
        • Q4 2018 average production of 623 boe/d, 2018 exit rate of 777 boe/d
        • Q4 2018 operating netbacks of $32.48/boe, up 37% from Q3 2018
        • Net working capital surplus at year-end of $59.5 million
        • Total Proved Plus Probable Reserves of 7,350 Mboe at year-end, down 6% from the prior year
        • Total Proved Plus Probable Reserves value of $87.5 million, up 35% from the prior year
        • Prospective Resources of 10.1 Tcf of unrisked natural gas remains unchanged at year end 2018

        Ongoing Operations and Corporate Highlights

        • Devepinar-1 has been drilled to its intermediate casing point at 3,375 metres and is currently being readied for logging. Clear indication of overpressured gas prior to section TD.
        • Operations are ongoing at Yamalik-1 with preparations for Production Logging Tool (« PLT ») zonal analysis which is planned for the coming weeks.
        • Operations are ongoing at Inanli-1 for a Diagnostic Fracture Injectivity Test (« DFIT ») in the coming weeks to assist in planning for reservoir stimulation and testing operations in Q2 2019.
        • Preparation and filing of documents for listing of the Company’s common shares on the London Stock Exchange is ongoing, with timing of announcement driven by final approval from the UK Listing Authority.

        Sean Guest, President and CEO commented:

        « Our financial results from 2018 reflect the high value of gas in Turkey and reiterates why we have built a portfolio of scale in this optimally located market. With prices continuing to track the broader European markets, we have seen price realisations of more than $9/Mcf, and coupled with our focus on managing production costs, we generated strong operating netbacks of $32.48/boe in Q4. These results bode well for the long-term value of our unconventional resource in Turkey, and underscore just how valuable our Basin Centered Gas Accumulation (« BCGA ») play could be for Valeura shareholders.

        We are progressing our deep appraisal programme on all fronts. The Inanli-1 well accomplished all its drilling objectives earlier this year, including encountering two intervals interpreted to be reservoir sweet spots, which correlate to Yamalik-1. We are about to embark on an exciting completion programme at Inanli.  Meanwhile, the Devepinar-1 well is drilling ahead at a location 20km to the west and will test the lateral extent of our play. Already we have seen early indications of over-pressured gas, which confirms our mapping on the breadth of the play. At Yamalik-1, we continue to monitor the production and will re-enter the wellbore to conduct some zone-by-zone production analysis aimed at gathering as much data as possible.

        Financially, we are in a strong position. With approximately $60 million cash on hand, we are fully funded through our 2019 capital programme. And with our upcoming listing of the Company’s common shares in London, we are looking forward to attracting more market interest, to bolster value for our shareholders. »

        Table 1 Financial and Operating Results Summary

        Three Months
        Ended

        December 31,
        2018

        Three Months
        Ended

        September 30,
        2018

        Year Ended

        December 31,
        2018

        Three Months
        Ended

        December 31,
        2017

        Year Ended

        December 31,
        2017

        Financial

        (thousands of CDN$ except share and per
        share amounts)

        Petroleum and natural gas revenues

        3,150

        2,401

        11,969

        3,824

        14,646

        Adjusted funds flow (used) (1)

        3,078

        (430)

        3,655

        (446)

        (1,205)

        Net loss from operations

        (634)

        (2,647)

        (7,120)

        (946)

        (8,384)

        Exploration and development capital

        3,282

        2,739

        8,023

        1,856

        12,791

        Acquisitions

        –

        –

        –

        –

        21,450

        Dispositions

        –

        –

        –

        –

        (26,288)

        Net working capital surplus

        59,520

        56,337

        59,520

        3,421

        3,421

        Cash

        62,380

        56,522

        62,380

        11,108

        11,108

        Common shares outstanding

        Basic

        86,232,988

        86,136,988

        86,232,988

        73,148,321

        73,148,321

        Diluted

        90,831,655

        90,831,655

        90,831,655

        79,518,821

        79,518,821

        Share trading

        High

        4.81

        4.85

        8.27

        5.02

        5.02

        Low

        2.34

        2.58

        2.34

        0.43

        0.43

        Close

        3.21

        4.18

        3.21

        4.35

        4.35

        Operations

        Production

        Crude oil (barrels (« bbl« )/d)

        8

        –

        8

        9

        8

        Natural Gas (one thousand cubic feet
        (« Mcf« )/d)

        3,689

        3,931

        4,257

        6,176

        5,662

        boe/d (@ 6:1)

        623

        655

        717

        1,038

        952

        Average reference price

        Brent ($ per bbl)

        89.56

        98.12

        91.66

        78.05

        70.29

        BOTAS Reference ($ per Mcf) (2)

        9.18

        6.65

        7.61

        6.65

        7.07

        Average realised price

        Crude oil ($ per bbl)

        104.41

        –

        91.85

        82.78

        71.84

        Natural gas ($ per Mcf)

        9.06

        6.64

        7.54

        6.61

        6.98

        Average Operating Netback

        ($ per boe @ 6:1) (1)

        32.48

        23.63

        25.79

        22.35

        23.76

        Notes:

        See the MD&A filed on SEDAR for further discussion.

        (1)

        The above table includes non-IFRS measures, which may not be comparable to other companies.  Adjusted funds flow is calculated as net income (loss) for the period adjusted for non-cash items in the statement of cash flows.  Operating netback is calculated as petroleum and natural gas sales less royalties, production expenses and transportation.

        (2)

        Boru Hatlari ile Petrol Tasima Anonim Sirketi (« BOTAS« ) owns and operates the national crude oil and natural gas pipeline grids in Turkey and purchases the majority of Turkey’s natural gas imports.  BOTAS regularly posts prices and its Level-2 Wholesale Tariff benchmark is shown herein as a reference price.  See the AIF filed on SEDAR for further discussion.

        Net petroleum and natural gas sales in Q4 2018 averaged 623 boe/d, which was 5% lower than Q3 2018.  This reflects natural declines in producing conventional reservoirs. Production was increased in late Q4 2018 as a result of workover activities and the exit rate for the last week of the quarter was 777 boe/d. The Company is continuing an active workover and maintenance programme intended to minimise the natural declines, despite most of the Company’s operational effort being applied to the appraisal of its deeper unconventional gas resource.

        Production revenue in Q4 2018 was $3.2 million, an increase of 31% over Q3 2018. This reflects markedly higher realised commodity prices in Q4, driven mainly by increases in Turkey’s BOTAS Reference price. The increased realised prices resulted in much higher average operating netbacks of $32.48/boe, an increase of 37% over the $23.63/boe recorded in Q3 2018.

        Exploration and development capital spending was $3.3 million in Q4 2018, increased from $2.7 million in the prior quarter, reflecting spending related to the tie-in and testing of the Yamalik-1 well and procurement of long-lead items associated with the ongoing appraisal drilling and testing programme planned for 2019.

        As of December 31, 2018, the Company had a net working capital surplus of $59.5 million, which is more than adequate to fund its planned forward capital expenditure programme throughout 2019.

        2019 OUTLOOK

        Valeura is fully focused on appraising and de-risking its BCGA play in the Thrace Basin. The objective of the Company’s work program for 2019 is to demonstrate that over-pressured gas is pervasive across Valeura’s Thrace Basin lands and to show that commercial flow rates can be achieved. The key activities to support this objective include ongoing data-capture from the Yamalik-1 exploration well, and the Company’s continuing appraisal drilling and testing programme.

        Valeura is continuing to gather data from the Yamalik-1 exploration well, which was drilled and flow-tested in 2017, and subsequently recompleted and tied into the Company’s production infrastructure in 2018.  In 2019, the Company intends to re-enter the well to conduct production logging testing as a way to understand zone-by-zone fluid composition and production rates, thereby refining target intervals for future drilling and completion operations.

        The Company concluded the drilling of Inanli-1 to a total depth of 4,885 metres in January 2019.  Valeura announced positive results that the well had encountered a 1,615 metre gross column of high net-to-gross, gas-bearing sandstone, and identified at least four zones interpreted to contain greater natural fracturing than previously observed. The well has been cased and left in a state ready for production testing.  Fracking and testing operations are expected to commence in early Q2 2019 and could extend throughout the quarter.  The Company is constructing a pipeline to tie in the well to its infrastructure in anticipation of a long-term production test. Costs for the Inanli-1 testing will be carried by Equinor Turkey B.V. (« Equinor ») and completion will fulfill their earning obligations under the Banarli farm-in agreement.

        Valeura began drilling the second appraisal well, Devepinar-1, in February 2019.   The well is a substantial step-out from prior BCGA wells, approximately 20 km from Inanli-1, and accordingly, will test the lateral extent of the BCGA play to the western side of the basin.  If drilling and logging results are positive, the Company intends to complete, frack, and production test the well.  Costs for Devepinar-1 are being shared proportionately by the working interest share of each partner, with Valeura’s share being 31.5%.

        A third appraisal well is envisaged for 2019, and Valeura and its partners will select a location based on drilling and testing data gathered from Yamalik-1, Inanli-1, and Devepinar-1.

        Valeura remains very well positioned to finance its ongoing BCGA appraisal and all corporate activities through to 2020. The Company’s working capital position is more than adequate to fund its working interest share of the two appraisal wells post Inanli-1 and all of the expected fracking and testing. In all its activities, the Company remains committed to continuing its safe and environmentally responsible operations and ensuring that operational and administrative functions are conducted in the most cost-efficient way.

        2018 YEAR-END CORPORATE RESERVES REPORT

        The Company has completed its independent reserves evaluation as at December 31, 2018. This evaluation was conducted by DeGolyer and MacNaughton (« D&M ») in its report dated March 13, 2019 (« D&M Reserves Report »).

        Table 2 summarises the Company’s reserves in Turkey and the before tax net present value discounted at 10% (« NPV10« ). D&M evaluated reserves as at December 31, 2018 on the Company’s Banarli licenses (100% working interest shallow/50% deep) and TBNG JV lands (81.5 % working interest shallow / 31.5% deep).

        Table 2 Company Gross Reserves Volumes and Values (1)(2)(3)(4)

        RESERVES

        (Mboe)

        Before Tax NPV10

        ($ MILLIONS – $MM)

        2018

        2017

        %

        CHANGE

        2018

        2017

        %

        CHANGE

        Proved

        Developed producing

        502

        602

        -17

        9.6

        5.5

        75

        Developed non-producing

        204

        311

        -34

        4.1

        4.7

        -13

        Undeveloped

        1256

        1,298

        -3

        12.6

        7.5

        68

        Total Proved (1P)

        1,962

        2,211

        -11

        26.3

        17.7

        49

        Probable

        5,388

        5,605

        -4

        61.1

        47.1

        30

        Total Proved Plus Probable (2P)

        7,350

        7,816

        -6

        87.5

        64.8

        35

        Possible

        4213

        4,433

        -5

        61.0

        51.2

        19

        Total Proved Plus Probable Plus
        Possible (3P)

        11,563

        12,249

        -6

        148.5

        116.0

        28

        Notes:

        (1)

        See Oil and Gas Advisories and Reserves and Resources Definitions below.

        (2)

        D&M’s valuations for reserves in Turkey are prepared in US$ and have been converted for purposes of this illustration to Cdn$ assuming a $Cdn/$US exchange rate of 0.80 for the year-end 2017 values and 0.73 for the year-end 2018 values.

        (3)

        The forecast prices used in the calculations of the present value of future net revenue for year-end 2018 are included in Table 4 and are based on the D&M December 31, 2018 forecast prices.

        (4)

        Due to rounding, summations in the table may not add.

        The reserves are primarily natural gas but small oil volumes are assigned to a number of wells. The 2018 year-end reserves by principal product type are summarised in Table 3.

        Table 3 2018 Year-end Company Gross Reserves Volumes by Principal Product Type (1)

        RESERVES

        CATEGORY

        LIGHT AND MEDIUM
        CRUDE OIL

        (Mbbl)

        CONVENTIONAL
        NATURAL GAS

        (Bcf)

        TOTAL OIL
        EQUIVALENT

        (Mboe)

        Proved

        15

        11.7

        1,962

        Probable

        6

        32.3

        5,388

        Total Proved Plus Probable

        21

        44.0

        7,350

        Possible

        10

        25.2

        4,213

        Total Proved Plus Probable Plus Possible

        31

        69.2

        11,563

        Note:

        (1)

        See Oil and Gas Advisories and Reserve Definitions below.

        The forecast oil and natural gas prices and cost escalation rates used in the D&M Reserves Report are shown in Table 4.

        Table 4 Forecast Prices and Cost Escalation Rates (1)(2)

        YEAR

        CONVENTIONAL NATURAL
        GAS         (2)

        LIGHT AND MEDIUM
        CRUDE OIL

        COST

        ESCALATION

        (US$/Mcf)

         (US$/bbl)

        %/YEAR

        2019

        7.24

        57.35

        0.0

        2020

        7.33

        58.08

        2.0

        2021

        7.39

        58.52

        2.0

        2022

        7.44

        58.88

        2.0

        2023

        7.46

        59.07

        2.0

        2024

        7.61

        60.25

        2.0

        2025

        7.76

        61.46

        2.0

        2026

        7.92

        62.69

        2.0

        2027

        8.07

        63.94

        2.0

        2028

        8.24

        65.22

        2.0

        2029

        8.40

        66.52

        2.0

        2030

        8.57

        67.85

        2.0

        2031+

        +2.0%/year

        thereafter

        +2.0%/year

        thereafter

        +2.0%/year

        thereafter

        Notes:

        (1)

        The forecast prices used in the calculation of the present value of future net revenue are based on the D&M December 31, 2018 forecast prices, which are included in the AIF filed on SEDAR.

        (2)

        The Conventional Natural Gas price forecast in Table 3 is for the TBNG assets. The Conventional Natural Gas price for the Banarli assets is approximately 97% of the TBNG forecast, reflecting a 15% discount in sale to TBNG with Valeura interest in TBNG at 81.5%.

        Table 5 sets forth a reconciliation of reserves changes in 2018.

        Table 5 2018 Year-end Company Gross Reserves Reconciliation

        CHANGES

        1P

        (Mboe)

        2P

        (Mboe)

        At December 31, 2017

        2,211

        7,816

        Technical Revisions

        -12

        -243

        Discoveries

        27

        41

        Acquisitions

        0

        0

        Economic Factors

        0

        0

        Production

        -265

        -265

        At December 31, 2018

        1,961

        7,349

        2018 YEAR-END UNCONVENTIONAL PROSPECTIVE RESOURCES SUMMARY

        There were no substantial changes to the Company’s prospective resources in Turkey as at December 31, 2018 versus December 31, 2017. In preparing their report (the « D&M Resources Report« ), D&M reviewed the flow data from the Yamalik-1 long-term production test, and drilling data from a portion of the Inanli-1 well, which was being drilled at year end.  Based on the limited new information available as of December 31, 2018, neither the volumes nor the risking were changed. Like the prior year’s resources report, the D&M Resources Report indicates 10.1 Tcf of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate.

        Table 6 Valeura Working Interest Natural Gas Prospective Resources at December 31, 2018(1)

        Valeura Working
        Interest Lands

        Unrisked

        Chance of
        Commerciality
        %

        Risked
        Mean Estimate

        Low
        Estimate

        Best
        Estimate

        High
        Estimate

        Mean
        Estimate

        Conventional Natural Gas – Bcf

        Total

        3,229

        7,652

        20,077

        10,137

        51.1

        5,182

        Note:

        (1)

        See Notes to Prospective Resources Table (Table 6) below.

        ANNUAL AND SPECIAL MEETING MATTERS

        Valeura will hold its annual general meeting of shareholders on May 9, 2019. The meeting materials will be mailed in the first part of April 2019.

        CONFERENCE CALL

        The management team will host an investor and analyst conference call and question session at 9:00 a.m. (Calgary), 11:00 a.m. (Toronto), 3:00 p.m. (London) today, Thursday, March 14, 2019.

        Interested listeners can connect via live webcast or dial-in conference call, as indicated below. Please register approximately 15 minutes prior to the start of the call. The results will be made available on the Company’s website at: www.valeuraenergy.com.

        Event title: Valeura Fourth Quarter 2018 Results Conference Call

        Webcast link: https://event.on24.com/wcc/r/1938046/559D5CA7E1328CDCEA05EE6E6247F220  
        Calgary dial-in: +1 587 880 2171
        Toronto dial-in: +1 416 764 8688
        North America toll-free: +1 888 390 0546
        UK toll-free: +44 (0) 800 652 2435

        ABOUT THE COMPANY

        Valeura Energy Inc. is a Canada-based public company currently engaged in the exploration, development and production of petroleum and natural gas in Turkey.

        OIL AND GAS ADVISORIES

        D&M Reserves Report and D&M Resources Report
        The D&M Reserves Report and the D&M Resources Report were prepared using guidelines outlined in the Canadian Oil and Gas Evaluation Handbook (« COGE Handbook ») and in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (« NI 51-101 »). Additional reserves and resources information as required under NI 51-101 is included in the AIF filed on SEDAR.

        Use of Unrisked Estimates
        The unrisked estimates of prospective resources referred to in this news release have not been risked for either the chance of discovery or the chance of development. There is no certainty that any portion of the prospective resources will be discovered. See the AIF for details regarding risked estimates. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the prospective resources.

        boes
        A boe is determined by converting a volume of natural gas to barrels using the ratio of 6 Mcf to one barrel. boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Further, a conversion ratio of 6 Mcf:1 boe assumes that the gas is very dry without significant natural gas liquids. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilising a conversion on a 6:1 basis may be misleading as an indication of value.

        RESERVES AND RESOURCES DEFINITIONS

        With respect to the reserves and resources data contained herein, the following terms have the meanings indicated:

        « chance of development » is the estimated probability that, once discovered, a known accumulation will be commercially developed.

        « chance of discovery » is the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum.

        « Company Gross reserves » are the Company’s working interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Company.

        « developed » reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.

        « developed producing » reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

        « developed non-producing » reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

        « mean recoverable » resources are the probability weighted average (expected value).

        « possible » reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

        « probable » reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

        « prospective resources » are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.

        « proved » reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

        « reserves » are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

        « resources » are petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including discovered and undiscovered (recoverable and unrecoverable) plus quantities already produced. Total resources is equivalent to total petroleum initially-in-place.

        « undeveloped » reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

        NOTES TO PROSPECTIVE RESOURCES TABLE (Table 6)

         « Valeura Working Interest Lands » Valeura’s working interest in the lands (exploration licences and production leases) that are encompassed (all or a portion thereof) in the basin-centered gas prospect in the Teslimkoy/Kesan formation is as follows: Banarli 50%, West Thrace 31.5% and South Thrace 81.5%.

        « Low Estimate » The low estimate is the P90 quantity. P90 means there is a 90% chance that the estimated quantity will be equaled or exceeded.

        « Best Estimate » The best estimate is the P50 quantity. P50 means there is a 50% chance that the estimated quantity will be equaled or exceeded.

        « High Estimate » The high estimate is the P10 quantity. P10 means there is a 10 % chance that the estimated quantity will be equaled or exceeded.

        « Mean Estimate » The mean estimate is the probability-weighted average (expected value).

        « Chance of Commerciality » The chance of commerciality is defined as the product of the chance of discovery and the chance of development.

        Chance of discovery in the D&M Resources Report is referred to as the probability of geologic success (Pg), which is defined as the probability of discovering reservoirs that flow hydrocarbons at a measurable rate. The Pg is estimated by quantifying with a probability, each of the following geologic chance factors: trap, source, reservoir and migration. The product of the probabilities of these four chance factors is Pg. Pg is predicated and correlated to the minimum case prospective resources gross recoverable volume(s). Consequently, the Pg is not linked to economically viable volumes, economic flow rates or economic field size distributions.

        In the D&M Resources Report, two factors have been considered in determining the chance of development as follows:

        Chance of development = Ptefs (probability of threshold economic field size) x Pd (probability of development)

        D&M defines Ptefs as the probability of discovering an accumulation that is large enough to be economically viable. Ptefs is estimated by using the prospective resources potential recoverable quantities distribution in conjunction with the threshold economic field size (TEFS). TEFS is the minimum amount of the producible petroleum required to recover the total capital and operating expenditure used to establish the potential accumulation as having a potential present worth at 10% equal to zero using the most likely price scenario.

        D&M defines Pd as the probability that a given discovery will be a viable development project. It takes into account the chance that the discovered target zone will flow the predicted hydrocarbon phase(s) at a commercial rate. It also considers the chance that the target zone can be mechanically completed and appraised in a reasonable time and in compliance with the projected cost schedule. The Pd is estimated by the quantification and product of these two chance factors.

        « Risked Mean Estimate » The risked mean estimate of conventional natural gas prospective resources = the unrisked mean estimate x chance of discovery x chance of development.

        Note, the Unrisked Low Estimate, Best Estimate, and High Estimate are arithmetic summations of all prospects.

        ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION

        This news release contains certain forward-looking statements and information (collectively referred to herein as « forward-looking information ») including, but not limited to: the potential of a basin-centered gas play in the Thrace Basin; management’s belief regarding the potential of the Company’s deep basin-centred gas play and shallow gas business in the Thrace Basin; the Company’s belief in the pervasiveness of over-pressured gas across the Company’s Thrace Basin lands; the intention of the Company to appraise and de-risk its BCGA in the Thrace Basin; the objective of the 2019 work program and the key activities anticipated to support such objective; the costs and timelines for the deep drilling and BCGA evaluation programme and the adequacy of its financial resources to fund forward appraisal operations; the ability to use Yamalik-1 data to refine target intervals for future drilling; the Company’s intention to re-enter the Yamalik-1 wellbore to conduct zone-by-zone production analysis; the intention of the Company and timing to conduct fracking, flow-testing and completion on Inanli-1 and Devepinar-1; the Company’s expectation that there will be a third appraisal well in 2019; the Company’s expectation of a long-term production test with respect to Inanli-1; and the potential listing of the Company’s common shares in London and that such potential listing may bolster value for the Company’s shareholders. Forward- looking information typically contains statements with words such as « anticipate », estimate », « expect », « target », « potential », « could », « should », « would » or similar words suggesting future outcomes. The Company cautions readers and prospective investors in the Company’s securities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company.

        Statements related to « reserves » or « prospective resources » are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and prospective resources can be profitably produced in the future. Specifically, forward-looking information contained herein regarding « reserves » and « prospective resources » may include: estimated volumes and value of Valeura’s oil and gas reserves; estimated volumes of prospective resources and the ability to finance future development; and, the conversion of a portion of prospective resources into reserves.

        Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: continued political stability of the areas in which the Company is operating; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the Turkish government and regulators in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; decline rates; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licenses and leases; and the Company’s continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Company’s work programmes and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, fracking and other specialised oilfield equipment and service providers, changes in partners’ plans and unexpected delays and changes in market conditions. Although the Company believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

        Forward-looking information involves significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Company including, but not limited to: the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the contemplated timelines and costs for the deep evaluation; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues or civil unrest in Turkey; potential changes in laws and regulations, the uncertainty regarding government and other approvals; counterparty risk; risks associated with weather delays and natural disasters; and the risk associated with international activity. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. See the 2018 AIF for a detailed discussion of the risk factors.

        The proposed admission of the Company’s common shares to the Standard Segment of the Official List of the Financial Conduct Authority and trading on the Main Market of the London Stock Exchange is subject (inter alia) to the approval of the UK Listing Authority (« UKLA ») and the publication by the Company of a prospectus approved by the UKLA. It is not intended that there will be any issue of common shares in conjunction with such admission and listing.

        Additional information relating to Valeura is also available on SEDAR at www.sedar.com

        Neither the Toronto Stock Exchange nor its Regulation Services Provider (as that term is defined in the policies of the Toronto Stock Exchange) accepts responsibility for the adequacy or accuracy of this news release.

        SOURCE Valeura Energy Inc.

        https://www.newswire.ca/news-releases/valeura-announces-fourth-quarter-2018-financial-and-operating-results-year-end-2018-reserves-845337491.html

    • EOG Resources Reports Fourth Quarter and Full Year 2018 Results and Announces 2019 Capital Program

      mars 1, 2019

        • Earns Record Net Income in 2018 and Generates Significant Net Cash from Operating Activities and Free Cash Flow
        • Exceeds Fourth Quarter Crude Oil and NGL Production Target Midpoints
        • Increases Proved Reserves by 16% and Replaces 238% of 2018 Production at Sub-$10 Finding Cost
        • Targets Improved Capital Efficiency, Significant Investment in High-Quality New Drilling Potential and 12-16% U.S. Crude Oil Volume Growth in 2019, Funded with Net Cash from Operating Activities at $50 Oil

        EOG Resources, Inc. (EOG) today reported fourth quarter 2018 net income of $893 million, or $1.54 per share. This compares to fourth quarter 2017 net income of $2.4 billion, or $4.20 per share. For the full year 2018, EOG reported a company record net income of $3.4 billion, or $5.89 per share, compared to $2.6 billion, or $4.46 per share, for the full year 2017. Net cash from operating activities for the fourth quarter and full year 2018 was $2.1 billion and $7.8 billion, respectively.

        Adjusted non-GAAP net income for the fourth quarter 2018 was $718 million, or $1.24 per share, compared to adjusted non-GAAP net income of $401 million, or $0.69 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2018 was $3.2 billion, or $5.54 per share, compared to adjusted non-GAAP net income of $648 million, or $1.12 per share, for the full year 2017. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

        Fourth Quarter and Full Year 2018 Review
        EOG delivered exceptional financial and operating performance in 2018. The company generated record net income and free cash flow, while ending the year with strong improvements in well productivity and additional cost reductions. Total company crude oil volumes grew 19 percent to 399,900 barrels of oil per day (Bopd). Natural gas liquids production increased 31 percent, while natural gas volumes grew 11 percent, contributing to total company production growth of 18 percent.

        In the fourth quarter 2018, EOG exceeded the high end of its target range for U.S. crude oil volumes by producing 430,300 Bopd, an increase of 17 percent compared to the same prior year period. Per-unit operating expenses declined during the fourth quarter 2018 compared to the same prior year period. Lower general and administrative expenses, transportation costs and depreciation, depletion and amortization expenses each contributed to the overall cost reduction.

        EOG generated $2.1 billion of discretionary cash flow and incurred total expenditures of $1.5 billion in the fourth quarter 2018. After considering cash exploration and development expenditures, excluding acquisitions, of $1.3 billion and dividend payments of $127 million, the company generated free cash flow during the fourth quarter of $637 million. For the full year 2018 EOG generated a company record $1.7 billion of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.

        « Our goal at EOG is to be one of the best companies in the S&P 500. Our stellar 2018 performance delivered a premium combination of high returns and double-digit production growth while generating record free cash flow, » said William R. « Bill » Thomas, Chairman and Chief Executive Officer. « Our 2018 results show that we can be competitive with the best companies across all sectors, and we remain relentlessly focused on further improving our cost structure and operating performance. »

        2019 Capital Plan
        EOG’s capital plan is custom-designed each year to increase returns and capital efficiencies. In 2019, EOG is allocating more capital to opportunistic, high quality new drilling potential and somewhat less capital to drilling in established areas. The company’s disciplined growth strategy emphasizes generating free cash flow while lowering well costs and per-unit operating expenses and driving improvement in well productivity. Retaining high-quality equipment and crews during the fourth quarter of 2018 positioned the company to further improve efficiencies and returns in 2019.

        EOG expects to grow U.S. crude oil production by 12 to 16 percent, fund capital investment and pay the dividend with net cash from operating activities in 2019 at $50 oil. Exploration and development expenditures for 2019 are expected to range from $6.1 to $6.5 billion, including facilities and gathering, processing and other expenditures, excluding acquisitions and non-cash exchanges.

        EOG expects to complete approximately 740 net wells in 2019 compared to 763 net wells in 2018. Activity will remain focused in EOG’s highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and Bakken. The company’s investment in new potential areas in the United States includes spending for leasing and related infrastructure to drill wells in a number of new prospects in 2019.

        « EOG’s disciplined 2019 capital plan delivers improved capital efficiency and strong high-return growth while making investments in new organic high-quality drilling potential to improve the future performance of the company, » Thomas said. « Our focus on innovation and operational execution, as well as our investment in new drilling potential, will continue to increase the quality of EOG’s premium portfolio. EOG is poised to further improve its position as one of the lowest cost oil producers in the global market, able to create shareholder value through commodity price cycles. »

        Operating Highlights
        EOG completed 262 net wells in the Delaware Basin and increased crude oil production 47% to 126,800 Bopd in 2018. The company made significant progress during 2018 in improving well productivity and reducing well costs. EOG refined spacing and development patterns, reduced drilling days and applied new completion technology designed to lower costs and improve well productivity.

        EOG continues to drive growth and operating efficiencies in its premier South Texas Eagle Ford asset. In 2018, the company grew crude oil production 9% to 171,000 Bopd. Of the 304 net wells completed in 2018, EOG drilled a total of 65 wells with lateral lengths greater than 10,000 feet. These wells included the Slytherin C#3H, which, at 13,500 feet, was a company record in the Eagle Ford.

        EOG’s Powder River Basin and Wyoming DJ Basin activity both contributed to the company’s 2018 crude oil production growth. In the Powder River Basin, the company brought eight wells on line during the fourth quarter targeting the Turner, Mowry and Parkman formations. The company plans to add infrastructure and further delineate the field and test additional targets in 2019 to be positioned to execute a more robust development program in the Niobrara and Mowry in 2020 and beyond. In the Wyoming DJ Basin, EOG generated further cost reductions during 2018 through efficiency improvements in drilling, completion and production operations. The company brought 20 wells to sales in the fourth quarter, all targeting the Codell formation. EOG expects further crude oil production growth from its high rate of return drilling in the DJ Basin in 2019.

        EOG continued development of its premium play in the Eastern Anadarko Basin Woodford Oil Window, where it brought five wells on line in the fourth quarter. The company made significant progress in reducing well costs during 2018, and, as a result, has lowered its 2019 well cost target to $7.6 million.

        In the Williston Basin, EOG realized significant operational improvements in 2018. The company drilled 20 net wells with an average treated lateral length of 9,500 feet per well. Efficient drilling performance delivered, on average, an additional 1,000 feet of lateral length per well in 2018 for the same cost as 2017. EOG’s Austin 45-1113H well set a company record in the basin with a spud-to-total depth time of 8.4 days.

        Reserves
        At year-end 2018, total company net proved reserves were 2,928 million barrels of oil equivalent (MMBoe), an increase of 16 percent compared to year-end 2017. Net proved reserve additions from all sources, excluding revisions due to price, replaced 238 percent of EOG’s 2018 production at a finding and development cost of $9.33 per barrel of oil equivalent. Revisions due to price increased net proved reserves by 35 MMBoe and asset divestitures decreased net proved reserves by 11 MMBoe. For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

        For the 31st consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.

        Financial Review
        At December 31, 2018, EOG’s total debt outstanding was $6.1 billion for a debt-to-total capitalization ratio of 24 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG’s net debt was $4.5 billion for a net debt-to-total capitalization ratio of 19 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

        EOG completed its previously announced agreement to divest all of its U.K. operations in the fourth quarter 2018. Proceeds from the U.K. divestment and other asset sales in 2018 totaled $227 million.

        Fourth Quarter 2018 Results Webcast
        Wednesday, February 27, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)
        Webcast will be available on EOG website for one year.
        http://investors.eogresources.com/Investors

        About EOG
        EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.

        Investor Contacts
        David Streit  713-571-4902
        Neel Panchal  713-571-4884
        John Wagner  713-571-4404

        Media and Investor Contact
        Kimberly Ehmer  713-571-4676

        This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG’s future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG’s management for future operations, are forward-looking statements.  EOG typically uses words such as « expect, » « anticipate, » « estimate, » « project, » « strategy, » « intend, » « plan, » « target, » « aims, » « goal, » « may, » « will, » « should » and « believe » or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.  In particular, statements, express or implied, concerning EOG’s future operating results and returns or EOG’s ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Moreover, EOG’s forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG’s control.  Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position.  Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG’s actual results may differ materially from such measures and estimates.  Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward-looking statements include, among others:

        • ­ the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
        • ­ the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
        • ­ the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
        • ­ the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;
        • ­ the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation and refining facilities;
        • ­ the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;
        • ­ the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
        • ­ EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
        • ­ the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully and economically;
        • ­ competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
        • ­ the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;
        • ­ the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
        • ­ weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage and transportation facilities;
        • ­ the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
        • ­ EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
        • ­ the extent to which EOG is successful in its completion of planned asset dispositions;
        • ­ the extent and effect of any hedging activities engaged in by EOG;
        • ­ the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
        • ­ geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
        • ­ the use of competing energy sources and the development of alternative energy sources;
        • ­ the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
        • ­ acts of war and terrorism and responses to these acts;
        • ­ physical, electronic and cybersecurity breaches; and
        • ­ the other factors described under ITEM 1A, Risk Factors, on pages 13 through 22 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and any updates to those factors set forth in EOG’s subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

        In light of these risks, uncertainties and assumptions, the events anticipated by EOG’s forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG’s forward-looking statements. EOG’s forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

        The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only « proved » reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also « probable » reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as « possible » reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves).  Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include « potential » reserves, « resource potential » and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines.  Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

        EOG RESOURCES, INC.

        Financial Report

        (Unaudited; in millions, except per share data)

        Three Months Ended

        Twelve Months Ended

        December 31,

        December 31,

        2018

        2017

        2018

        2017

        Operating Revenues and Other

        $

        4,574.5

        $

        3,340.4

        $

        17,275.4

        $

        11,208.3

        Net Income 

        $

        892.8

        $

        2,430.5

        $

        3,419.0

        $

        2,582.6

        Net Income Per Share 

                Basic

        $

        1.55

        $

        4.22

        $

        5.93

        $

        4.49

                Diluted

        $

        1.54

        $

        4.20

        $

        5.89

        $

        4.46

        Average Number of Common Shares

                Basic

        577.0

        575.4

        576.6

        574.6

                Diluted

        580.3

        579.2

        580.4

        578.7

        Summary Income Statements

        (Unaudited; in thousands, except per share data)

        Three Months Ended

        Twelve Months Ended

        December 31,

        December 31,

        2018

        2017

        2018

        2017

        Operating Revenues and Other

                Crude Oil and Condensate

        $

        2,383,326

        $

        1,929,471

        $

        9,517,440

        $

        6,256,396

                Natural Gas Liquids

        266,037

        249,172

        1,127,510

        729,561

                Natural Gas

        389,213

        246,922

        1,301,537

        921,934

                Gains (Losses) on Mark-to-Market Commodity
                   Derivative Contracts

        132,095

        (45,032)

        (165,640)

        19,828

                Gathering, Processing and Marketing

        1,331,105

        1,008,385

        5,230,355

        3,298,087

                Gains (Losses) on Asset Dispositions, Net

        79,904

        (65,220)

        174,562

        (99,096)

                Other, Net

        (7,144)

        16,741

        89,635

        81,610

                       Total

        4,574,536

        3,340,439

        17,275,399

        11,208,320

        Operating Expenses

                Lease and Well

        346,442

        281,941

        1,282,678

        1,044,847

                Transportation Costs

        196,095

        191,717

        746,876

        740,352

                Gathering and Processing Costs

        112,396

        43,295

        436,973

        148,775

                Exploration Costs

        33,862

        22,941

        148,999

        145,342

                Dry Hole Costs

        145

        4,532

        5,405

        4,609

                Impairments 

        186,087

        153,442

        347,021

        479,240

                Marketing Costs

        1,349,416

        1,009,566

        5,203,243

        3,330,237

                Depreciation, Depletion and Amortization

        919,963

        881,745

        3,435,408

        3,409,387

                General and Administrative

        116,904

        117,005

        426,969

        434,467

                Taxes Other Than Income

        190,086

        158,343

        772,481

        544,662

                       Total

        3,451,396

        2,864,527

        12,806,053

        10,281,918

        Operating Income 

        1,123,140

        475,912

        4,469,346

        926,402

        Other Income, Net

        21,220

        803

        16,704

        9,152

        Income Before Interest Expense and Income Taxes

        1,144,360

        476,715

        4,486,050

        935,554

        Interest Expense, Net

        56,020

        63,362

        245,052

        274,372

        Income Before Income Taxes

        1,088,340

        413,353

        4,240,998

        661,182

        Income Tax Provision (Benefit)

        195,572

        (2,017,115)

        821,958

        (1,921,397)

        Net Income 

        $

        892,768

        $

        2,430,468

        $

        3,419,040

        $

        2,582,579

        Dividends Declared per Common Share

        $

        0.2200

        $

        0.1675

        $

        0.8100

        $

        0.6700

        EOG RESOURCES, INC.

        Operating Highlights

        (Unaudited)

        Three Months Ended

        Twelve Months Ended

        December 31,

        December 31,

        2018

        2017

        2018

        2017

        Wellhead Volumes and Prices

        Crude Oil and Condensate Volumes (MBbld) (A)

              United States

        430.3

        366.9

        394.8

        335.0

              Trinidad

        0.8

        1.1

        0.8

        0.9

              Other International (B)

        4.5

        0.1

        4.3

        0.8

                    Total

        435.6

        368.1

        399.9

        336.7

        Average Crude Oil and Condensate Prices ($/Bbl) (C)

              United States

        $

        59.37

        $

        56.95

        $

        65.16

        $

        50.91

              Trinidad

        51.80

        46.56

        57.26

        42.30

              Other International (B)

        70.44

        45.72

        71.45

        57.20

                    Composite

        59.47

        56.97

        65.21

        50.91

        Natural Gas Liquids Volumes (MBbld) (A)

              United States

        122.8

        100.6

        116.1

        88.4

              Other International (B)

        –

        –

        –

        –

                    Total

        122.8

        100.6

        116.1

        88.4

        Average Natural Gas Liquids Prices ($/Bbl) (C)

              United States

        $

        23.54

        $

        26.92

        $

        26.60

        $

        22.61

              Other International (B)

        –

        –

        –

        –

                    Composite

        23.54

        26.92

        26.60

        22.61

        Natural Gas Volumes (MMcfd) (A)

              United States

        974

        829

        923

        765

              Trinidad

        230

        299

        266

        313

              Other International (B)

        32

        32

        30

        25

                    Total

        1,236

        1,160

        1,219

        1,103

        Average Natural Gas Prices ($/Mcf) (C)

              United States

        $

        3.50

        $

        2.17

        $

        2.88

        $

        2.20

              Trinidad

        3.03

        2.52

        2.94

        2.38

              Other International (B)

        4.02

        4.23

        4.08

        3.89

                    Composite

        3.42

        (D)

        2.31

        2.92

        (D)

        2.29

        Crude Oil Equivalent Volumes (MBoed) (E)

              United States 

        715.5

        605.6

        664.7

        551.0

              Trinidad

        39.0

        51.0

        45.1

        53.0

              Other International (B)

        10.0

        5.4

        9.4

        4.9

                    Total

        764.5

        662.0

        719.2

        608.9

        Total MMBoe (E)

        70.3

        60.9

        262.5

        222.3

        (A) Thousand barrels per day or million cubic feet per day, as applicable.

        (B) Other International includes EOG’s United Kingdom, China and Canada operations.  The United Kingdom operations were sold in the fourth quarter of 2018.

        (C) Dollars per barrel or per thousand cubic feet, as applicable.  Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG’s Annual Report on Form 10-K for the year ended December 31, 2018).

        (D) Includes positive revenue adjustments of $0.49 per Mcf and $0.44 per Mcf for the three and twelve months ended December 31, 2018, respectively, related to the adoption of ASU 2014-09, « Revenue From Contracts with Customers » (ASU 2014-09).  (see Note 1 to the Consolidated Financial Statements in EOG’s Annual Report on Form 10-K for the year ended December 31, 2018).  In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas Revenues.

        (E) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas.  Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.  MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

        EOG RESOURCES, INC.

        Summary Balance Sheets

        (Unaudited; in thousands, except share data)

        December 31,

        December 31,

        2018

        2017

        ASSETS

        Current Assets

             Cash and Cash Equivalents

        $

        1,555,634

        $

        834,228

             Accounts Receivable, Net

        1,915,215

        1,597,494

             Inventories

        859,359

        483,865

             Assets from Price Risk Management Activities

        23,806

        7,699

             Income Taxes Receivable

        427,909

        113,357

             Other

        275,467

        242,465

                    Total

        5,057,390

        3,279,108

        Property, Plant and Equipment

             Oil and Gas Properties (Successful Efforts Method)

        57,330,016

        52,555,741

             Other Property, Plant and Equipment

        4,220,665

        3,960,759

                    Total Property, Plant and Equipment

        61,550,681

        56,516,500

             Less:  Accumulated Depreciation, Depletion and Amortization

        (33,475,162)

        (30,851,463)

                    Total Property, Plant and Equipment, Net

        28,075,519

        25,665,037

        Deferred Income Taxes

        777

        17,506

        Other Assets

        800,788

        871,427

        Total Assets

        $

        33,934,474

        $

        29,833,078

        LIABILITIES AND STOCKHOLDERS’ EQUITY

        Current Liabilities

             Accounts Payable

        $

        2,239,850

        $

        1,847,131

             Accrued Taxes Payable

        214,726

        148,874

             Dividends Payable

        126,971

        96,410

             Liabilities from Price Risk Management Activities

        –

        50,429

             Current Portion of Long-Term Debt

        913,093

        356,235

             Other

        233,724

        226,463

                    Total

        3,728,364

        2,725,542

        Long-Term Debt

        5,170,169

        6,030,836

        Other Liabilities

        1,258,355

        1,275,213

        Deferred Income Taxes

        4,413,398

        3,518,214

        Commitments and Contingencies

        Stockholders’ Equity

             Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 
                580,408,117 Shares and 578,827,768 Shares Issued at December 31, 2018
                and 2017, respectively.

        205,804

        205,788

             Additional Paid in Capital

        5,658,794

        5,536,547

             Accumulated Other Comprehensive Loss

        (1,358)

        (19,297)

             Retained Earnings

        13,543,130

        10,593,533

             Common Stock Held in Treasury, 385,042 Shares and 350,961 Shares at
                December 31, 2018 and 2017, respectively.

        (42,182)

        (33,298)

                    Total Stockholders’ Equity

        19,364,188

        16,283,273

        Total Liabilities and Stockholders’ Equity

        $

        33,934,474

        $

        29,833,078

        EOG RESOURCES, INC.

        Summary Statements of Cash Flows

        (Unaudited; in thousands)

        Twelve Months Ended

        December 31,

        2018

        2017

        Cash Flows from Operating Activities

        Reconciliation of Net Income to Net Cash Provided by Operating Activities:

             Net Income

        $

        3,419,040

        $

        2,582,579

             Items Not Requiring (Providing) Cash

                    Depreciation, Depletion and Amortization

        3,435,408

        3,409,387

                    Impairments 

        347,021

        479,240

                    Stock-Based Compensation Expenses

        155,337

        133,849

                    Deferred Income Taxes

        894,156

        (1,473,872)

                    (Gains) Losses on Asset Dispositions, Net

        (174,562)

        99,096

                    Other, Net

        7,066

        6,546

             Dry Hole Costs

        5,405

        4,609

             Mark-to-Market Commodity Derivative Contracts

                    Total (Gains) Losses

        165,640

        (19,828)

                    Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts 

        (258,906)

        7,438

             Other, Net

        3,108

        1,204

             Changes in Components of Working Capital and Other Assets and Liabilities

                    Accounts Receivable

        (368,180)

        (392,131)

                    Inventories

        (395,408)

        (174,548)

                    Accounts Payable

        439,347

        324,192

                    Accrued Taxes Payable

        (92,461)

        (63,937)

                    Other Assets

        (125,435)

        (658,609)

                    Other Liabilities

        10,949

        (89,871)

             Changes in Components of Working Capital Associated with Investing and Financing
                Activities

        301,083

        89,992

        Net Cash Provided by Operating Activities

        7,768,608

        4,265,336

        Investing Cash Flows

             Additions to Oil and Gas Properties

        (5,839,294)

        (3,950,918)

             Additions to Other Property, Plant and Equipment

        (237,181)

        (173,324)

             Proceeds from Sales of Assets

        227,446

        226,768

             Other Investing Activities

        (19,993)

        –

             Changes in Components of Working Capital Associated with Investing Activities

        (301,140)

        (89,935)

        Net Cash Used in Investing Activities

        (6,170,162)

        (3,987,409)

        Financing Cash Flows

             Long-Term Debt Repayments

        (350,000)

        (600,000)

             Dividends Paid

        (438,045)

        (386,531)

             Treasury Stock Purchased

        (63,456)

        (63,408)

             Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 

        20,560

        20,840

             Repayment of Capital Lease Obligation

        (8,219)

        (6,555)

             Changes in Components of Working Capital Associated with Financing Activities

        57

        (57)

        Net Cash Used in Financing Activities

        (839,103)

        (1,035,711)

        Effect of Exchange Rate Changes on Cash

        (37,937)

        (7,883)

        Increase (Decrease) in Cash and Cash Equivalents

        721,406

        (765,667)

        Cash and Cash Equivalents at Beginning of Period

        834,228

        1,599,895

        Cash and Cash Equivalents at End of Period

        $

        1,555,634

        $

        834,228

        EOG RESOURCES, INC.

        Fourth Quarter 2018 Well Results by Play

        (Unaudited)

        Wells Online

        Initial Gross 30-Day Average Production Rate

        Gross

        Net

        Lateral
        Length
        (ft)

        Crude Oil and
        Condensate
        (Bbld) (A)

        Natural Gas
        Liquids
        (Bbld) (A)

         Natural Gas
        (MMcfd) (A)

        Crude Oil
        Equivalent
        (Boed) (B)

        Delaware Basin

        Wolfcamp

        42

        37

        7,000

        1,950

        600

        3.7

        3,150

        Bone Spring

        13

        11

        5,300

        1,550

        300

        1.9

        2,150

        Leonard

        2

        1

        4,600

        1,200

        550

        3.7

        2,350

        South Texas Eagle Ford

        82

        78

        7,300

        1,300

        150

        0.8

        1,600

        South Texas Austin Chalk

        6

        5

        5,500

        2,650

        550

        2.6

        3,650

        Powder River Basin

        Turner

        4

        3

        9,700

        800

        200

        2.4

        1,400

        Mowry

        2

        2

        9,200

        700

        450

        5.5

        2,050

        DJ Basin Codell

        20

        10

        9,600

        700

        50

        0.3

        800

        Williston Basin Bakken/Three Forks

        7

        5

        10,100

        550

        25

        0.1

        600

        Anadarko Basin Woodford Oil Window

        5

        4

        9,200

        600

        75

        0.4

        750

        (A)  Barrels per day or million cubic feet per day, as applicable.

        (B)  Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas.  Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.

        EOG RESOURCES, INC.

        Quantitative Reconciliation of Adjusted Net Income (Non-GAAP)

        To Net Income (GAAP)

        (Unaudited; in thousands, except per share data)

        The following chart adjusts the three-month and twelve-month periods ended December 31, 2018 and 2017 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2018 and 2017, to add back impairment charges related to certain of EOG’s assets in 2018 and 2017, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017, to add back certain joint interest billings deemed uncollectible in 2017 and to eliminate certain adjustments in 2018 and 2017 related to the 2017 U.S. tax reform.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

        Three Months Ended 

        Three Months Ended 

        December 31, 2018

        December 31, 2017

        Income

        Diluted

        Income

        Diluted

        Before

        Tax

        After

        Earnings

        Before

        Tax

        After

        Earnings

        Tax

        Impact

        Tax

        per Share

        Tax

        Impact

        Tax

        per Share

        Reported Net Income (GAAP)

        $          1,088,340

        $        (195,572)

        $            892,768

        $          1.54

        $          413,353

        $       2,017,115

        $          2,430,468

        $          4.20

        Adjustments:

        (Gains) Losses on Mark-to-Market Commodity
             Derivative Contracts

        (132,095)

        29,096

        (102,999)

        (0.18)

        45,032

        (16,142)

        28,890

        0.05

        Net Cash Received from (Payments for)
             Settlements of Commodity Derivative
             Contracts

        (78,678)

        17,330

        (61,348)

        (0.11)

        2,708

        (971)

        1,737

        –

        Add:  Net (Gains) Losses on Asset Dispositions

        (79,904)

        13,625

        (66,279)

        (0.11)

        65,220

        (23,315)

        41,905

        0.07

        Add:  Impairments

        131,795

        (29,031)

        102,764

        0.18

        100,304

        (35,954)

        64,350

        0.11

        Add:  Joint Interest Billings Deemed Uncollectible

        –

        –

        –

        –

        4,528

        (1,623)

        2,905

        0.01

        Less:  Tax Reform Impact

        –

        (46,684)

        (46,684)

        (0.08)

        –

        (2,169,376)

        (2,169,376)

        (3.75)

        Adjustments to Net Income 

        (158,882)

        (15,664)

        (174,546)

        (0.30)

        217,792

        (2,247,381)

        (2,029,589)

        (3.51)

        Adjusted Net Income (Non-GAAP)

        $             929,458

        $        (211,236)

        $            718,222

        $          1.24

        $          631,145

        $         (230,266)

        $             400,879

        $          0.69

        Average Number of Common Shares (GAAP)

               Basic

        577,035

        575,394

               Diluted

        580,288

        579,203

        Twelve Months Ended 

        Twelve Months Ended 

        December 31, 2018

        December 31, 2017

        Income

        Diluted

        Income

        Diluted

        Before

        Tax

        After

        Earnings

        Before

        Tax

        After

        Earnings

        Tax

        Impact

        Tax

        per Share

        Tax

        Impact

        Tax

        per Share

        Reported Net Income (GAAP)

        $          4,240,998

        $        (821,958)

        $         3,419,040

        $          5.89

        $          661,182

        $       1,921,397

        $          2,582,579

        $          4.46

        Adjustments:

        (Gains) Losses on Mark-to-Market Commodity
             Derivative Contracts

        165,640

        (36,486)

        129,154

        0.22

        (19,828)

        7,107

        (12,721)

        (0.02)

        Net Cash Received from (Payments for)
             Settlements of Commodity Derivative
             Contracts

        (258,906)

        57,029

        (201,877)

        (0.35)

        7,438

        (2,666)

        4,772

        0.01

        Add:  Net (Gains) Losses on Asset Dispositions

        (174,562)

        37,860

        (136,702)

        (0.24)

        99,096

        (35,270)

        63,826

        0.11

        Add:  Impairments

        152,671

        (33,629)

        119,042

        0.21

        261,452

        (93,718)

        167,734

        0.29

        Add:  Legal Settlement – Early Lease Termination

        –

        –

        –

        –

        10,202

        (3,657)

        6,545

        0.01

        Add:  Joint Venture Transaction Costs

        –

        –

        –

        –

        3,056

        (1,095)

        1,961

        –

        Add:  Joint Interest Billings Deemed Uncollectible

        –

        –

        –

        –

        4,528

        (1,623)

        2,905

        0.01

        Less:  Tax Reform Impact

        –

        (110,335)

        (110,335)

        (0.19)

        –

        (2,169,376)

        (2,169,376)

        (3.75)

        Adjustments to Net Income

        (115,157)

        (85,561)

        (200,718)

        (0.35)

        365,944

        (2,300,298)

        (1,934,354)

        (3.34)

        Adjusted Net Income (Non-GAAP)

        $          4,125,841

        $        (907,519)

        $         3,218,322

        $          5.54

        $       1,027,126

        $         (378,901)

        $             648,225

        $          1.12

        Average Number of Common Shares (GAAP)

               Basic

        576,578

        574,620

               Diluted

        580,441

        578,693

        EOG RESOURCES, INC.

        Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP)

        To Net Cash Provided by Operating Activities (GAAP)

        (Unaudited; in thousands)

        Calculation of Free Cash Flow (Non-GAAP)

        (Unaudited; in thousands)

        The following chart reconciles the three-month and twelve-month periods ended December 31, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes – Net Receivable (Payable), Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities.  EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the three months and twelve months ended December 31, 2018.  EOG management uses this information for comparative purposes within the industry.

        Three Months Ended

        Twelve Months Ended

        December 31,

        December 31,

        2018

        2017

        2018

        2017

        Net Cash Provided by Operating Activities (GAAP)

        $

        2,085,228

        $

        1,327,548

        $

        7,768,608

        $

        4,265,336

        Adjustments:

        Exploration Costs (excluding Stock-Based Compensation Expenses) 

        27,270

        16,420

        123,986

        122,688

        Other Non-Current Income Taxes – Net Receivable (Payable)

        86,572

        (513,404)

        148,993

        (513,404)

        Changes in Components of Working Capital and Other Assets

        and Liabilities

        Accounts Receivable

        (185,349)

        366,686

        368,180

        392,131

        Inventories

        108,591

        156,874

        395,408

        174,548

        Accounts Payable

        98,178

        (211,298)

        (439,347)

        (324,192)

        Accrued Taxes Payable

        55,570

        13,970

        92,461

        63,937

        Other Assets

        22,101

        574,669

        125,435

        658,609

        Other Liabilities

        (25,725)

        20,647

        (10,949)

        89,871

        Changes in Components of Working Capital Associated with 

        Investing and Financing Activities

        (205,599)

        (210,365)

        (301,083)

        (89,992)

        Discretionary Cash Flow (Non-GAAP)

        $

        2,066,837

        $

        1,541,747

        $

        8,271,692

        $

        4,839,532

        Discretionary Cash Flow (Non-GAAP) – Percentage Increase

        34%

        71%

        Discretionary Cash Flow (Non-GAAP)

        $

        2,066,837

        $

        8,271,692

        Less:  

        Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a)

        (1,302,999)

        (6,172,950)

        Dividends Paid (GAAP) 

        (126,970)

        (438,045)

        Free Cash Flow (Non-GAAP)

        $

        636,868

        $

        1,660,697

        (a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months and twelve months ended December 31, 2018:

        Total Expenditures (GAAP)

        $

        1,504,438

        $

        6,706,359

        Less:  

                  Asset Retirement Costs

        (27,910)

        (69,699)

                  Non-Cash Expenditures of Other Property, Plant and Equipment

        (547)

        (49,484)

                  Non-Cash Acquisition Costs of Unproved Properties

        (128,719)

        (290,542)

                  Acquisition Costs of Proved Properties

        (44,263)

        (123,684)

        Total Cash Expenditures Excluding Acquisitions (Non-GAAP) 

        $

        1,302,999

        $

        6,172,950

        EOG RESOURCES, INC.

        Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net,

        Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, 

        Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX)

         (Non-GAAP) to Net Income (GAAP)

        (Unaudited; in thousands)

        The following chart adjusts the three-month and twelve-month periods ended December 31, 2018 and 2017 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the (gains) losses on asset dispositions (Net).  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

        Three Months Ended

        Twelve Months Ended

        December 31,

        December 31,

        2018

        2017

        2018

        2017

        Net Income (GAAP)

        $

        892,768

        $

        2,430,468

        $

        3,419,040

        $

        2,582,579

        Adjustments:

             Interest Expense, Net

        56,020

        63,362

        245,052

        274,372

             Income Tax Provision (Benefit)

        195,572

        (2,017,115)

        821,958

        (1,921,397)

             Depreciation, Depletion and Amortization

        919,963

        881,745

        3,435,408

        3,409,387

             Exploration Costs

        33,862

        22,941

        148,999

        145,342

             Dry Hole Costs

        145

        4,532

        5,405

        4,609

             Impairments 

        186,087

        153,442

        347,021

        479,240

                     EBITDAX (Non-GAAP)

        2,284,417

        1,539,375

        8,422,883

        4,974,132

             Total (Gains) Losses on MTM Commodity Derivative Contracts  

        (132,095)

        45,032

        165,640

        (19,828)

             Net Cash Received from (Payments for) Settlements of Commodity
                 Derivative Contracts

        (78,678)

        2,708

        (258,906)

        7,438

             (Gains) Losses on Asset Dispositions, Net

        (79,904)

        65,220

        (174,562)

        99,096

        Adjusted EBITDAX (Non-GAAP)

        $

        1,993,740

        $

        1,652,335

        $

        8,155,055

        $

        5,060,838

        Adjusted EBITDAX (Non-GAAP) – Percentage Increase

        21%

        61%

        EOG RESOURCES, INC.

        Quantitative Reconciliation of Net Debt (Non-GAAP) and Total

        Capitalization (Non-GAAP) as Used in the Calculation of

        The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to

        Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation.  A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation.  EOG management uses this information for comparative purposes within the industry.

        At

        At

        December 31,

        December 31,

        2018

        2017

        Total Stockholders’ Equity – (a)

        $

        19,364

        $

        16,283

        Current and Long-Term Debt (GAAP) – (b)

        6,083

        6,387

        Less: Cash 

        (1,556)

        (834)

        Net Debt (Non-GAAP) – (c)

        4,527

        5,553

        Total Capitalization (GAAP) – (a) + (b)

        $

        25,447

        $

        22,670

        Total Capitalization (Non-GAAP) – (a) + (c)

        $

        23,891

        $

        21,836

        Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)]

        24%

        28%

        Net Debt-to-Total Capitalization (Non-GAAP) – (c) / [(a) + (c)]

        19%

        25%

        EOG RESOURCES, INC.

        Reserves Supplemental Data

        (Unaudited)

        2018 NET PROVED RESERVES RECONCILIATION SUMMARY  

         United 

         Other 

         States 

        Trinidad

         International 

         Total 

        CRUDE OIL AND CONDENSATE (MMBbl)

        Beginning Reserves

        1,304.1

        0.9

        8.0

        1,313.0

        Revisions 

        (13.2)

        (0.2)

        –

        (13.4)

        Purchases in Place

        2.7

        –

        –

        2.7

        Extensions, Discoveries and Other Additions

        383.0

        –

        –

        383.0

        Sales in Place

        (0.8)

        –

        (6.3)

        (7.1)

        Production 

        (144.1)

        (0.3)

        (1.5)

        (145.9)

        Ending Reserves

        1,531.7

        0.4

        0.2

        1,532.3

        NATURAL GAS LIQUIDS (MMBbl)

        Beginning Reserves

        503.5

        –

        –

        503.5

        Revisions 

        23.9

        –

        –

        23.9

        Purchases in Place

        2.0

        –

        –

        2.0

        Extensions, Discoveries and Other Additions

        127.4

        –

        –

        127.4

        Sales in Place

        –

        –

        –

        –

        Production 

        (42.5)

        –

        –

        (42.5)

        Ending Reserves

        614.3

        –

        –

        614.3

        NATURAL GAS (Bcf) 

        Beginning Reserves 

        3,898.5

        313.4

        51.2

        4,263.1

        Revisions 

        (127.2)

        20.7

        15.0

        (91.5)

        Purchases in Place

        41.3

        –

        –

        41.3

        Extensions, Discoveries and Other Additions

        951.4

        –

        4.6

        956.0

        Sales in Place

        (22.2)

        –

        –

        (22.2)

        Production 

        (351.2)

        (97.1)

        (11.2)

        (459.5)

        Ending Reserves

        4,390.6

        237.0

        59.6

        4,687.2

        OIL EQUIVALENTS (MMBoe) 

        Beginning Reserves 

        2,457.3

        53.1

        16.6

        2,527.0

        Revisions 

        (10.5)

        3.3

        2.5

        (4.7)

        Purchases in Place

        11.6

        –

        –

        11.6

        Extensions, Discoveries and Other Additions

        669.0

        –

        0.7

        669.7

        Sales in Place

        (4.5)

        –

        (6.3)

        (10.8)

        Production 

        (245.1)

        (16.5)

        (3.4)

        (265.0)

        Ending Reserves

        2,877.8

        39.9

        10.1

        2,927.8

        Net Proved Developed Reserves (MMBoe) 

        At December 31, 2017

        1,300.7

        50.8

        12.8

        1,364.3

        At December 31, 2018

        1,503.4

        37.7

        7.0

        1,548.1

        2018 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) 

         United 

         Other 

         States 

        Trinidad

         International 

         Total 

        Acquisition Cost of Unproved Properties

        $          486.0

        $          1.3

        $                       –

        $          487.3

        Exploration Costs

        157.2

        22.5

        13.9

        193.6

        Development Costs

        5,515.4

        (0.8)

        30.8

        5,545.4

        Total Drilling

        6,158.6

        23.0

        44.7

        6,226.3

        Acquisition Cost of Proved Properties

        123.7

        –

        –

        123.7

        Asset Retirement Costs 

        90.0

        (12.1)

        (8.2)

        69.7

        Total Exploration and Development Expenditures 

        6,372.3

        10.9

        36.5

        6,419.7

        Gathering, Processing and Other

        286.0

        0.4

        0.3

        286.7

        Total Expenditures

        6,658.3

        11.3

        36.8

        6,706.4

        Proceeds from Sales in Place

        (53.3)

        –

        (174.1)

        (227.4)

        Net Expenditures

        $       6,605.0

        $        11.3

        $                 (137.3)

        $       6,479.0

        RESERVE REPLACEMENT COSTS ($ / Boe ) * 

        All-in Total, Net of Revisions 

        $            8.84

        $        6.97

        $                  13.97

        $            8.85

        All-in Total, Excluding Revisions Due to Price

        $            9.32

        $        6.97

        $                  13.97

        $            9.33

        RESERVE REPLACEMENT *

        Drilling Only

        273%

        0%

        21%

        253%

        All-in Total, Net of Revisions and Dispositions  

        272%

        20%

        -91%

        251%

        All-in Total, Excluding Revisions Due to Price

        257%

        20%

        -91%

        238%

        All-in Total, Liquids

        281%

        -67%

        -420%

        275%

        *   See attached reconciliation schedule for calculation methodology

        EOG RESOURCES, INC.

        Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP)

        As Used in the Calculation of Reserve Replacement Costs ($ / BOE)

        To Total Costs Incurred in Exploration and Development Activities (GAAP)

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe.  There are numerous ways that industry participants present Reserve Replacement Costs, including « Drilling Only » and « All-In », which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources.  Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program.  Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.  Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures.  Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs.  EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

        For the Twelve Months Ended December 31, 2018

         United 

         Other 

         States 

         Trinidad 

         International 

         Total 

        Total Costs Incurred in Exploration and Development Activities (GAAP)

        $       6,372.3

        $           10.9

        $                   36.5

        $       6,419.7

        Less:  Asset Retirement Costs

        (90.0)

        12.1

        8.2

        (69.7)

                  Non-Cash Acquisition Costs of Unproved Properties

        (290.5)

        –

        –

        (290.5)

                   Total Acquisition Costs of Proved Properties

        (123.7)

        –

        –

        (123.7)

        Total Exploration and Development Expenditures (Non-GAAP) (a) 

        $       5,868.1

        $           23.0

        $                   44.7

        $       5,935.8

        Total Costs Incurred in Exploration and Development Activities (GAAP)

        $       6,372.3

        $           10.9

        $                   36.5

        $       6,419.7

        Less:  Asset Retirement Costs

        (90.0)

        12.1

        8.2

        (69.7)

                  Non-Cash Acquisition Costs of Unproved Properties

        (290.5)

        –

        –

        (290.5)

                  Non-Cash Acquisition Costs of Proved Properties

        (70.9)

        –

        –

        (70.9)

        Total Exploration and Development Expenditures (Non-GAAP) (b) 

        $       5,920.9

        $           23.0

        $                   44.7

        $       5,988.6

        Total Expenditures (GAAP)

        $       6,658.3

        $           11.3

        $                   36.8

        $       6,706.4

        Less:  Asset Retirement Costs

        (90.0)

        12.1

        8.2

        (69.7)

                  Non-Cash Acquisition Costs of Unproved Properties

        (290.5)

        –

        –

        (290.5)

                  Non-Cash Acquisition Costs of Proved Properties

        (70.9)

        –

        –

        (70.9)

                  Non-Cash Capital – Other Miscellaneous

        (49.5)

        –

        –

        (49.5)

        Total Cash Expenditures (Non-GAAP) 

        $       6,157.4

        $           23.4

        $                   45.0

        $       6,225.8

        Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe) 

        Revisions Due to Price (c)

        34.8

        –

        –

        34.8

        Revisions Other Than Price

        (45.3)

        3.3

        2.5

        (39.5)

        Purchases in Place

        11.6

        –

        –

        11.6

        Extensions, Discoveries and Other Additions (d)

        669.0

        –

        0.7

        669.7

        Total Proved Reserve Additions (e) 

        670.1

        3.3

        3.2

        676.6

        Sales in Place

        (4.5)

        –

        (6.3)

        (10.8)

        Net Proved Reserve Additions From All Sources (f) 

        665.6

        3.3

        (3.1)

        665.8

        Production (g) 

        245.1

        16.5

        3.4

        265.0

        RESERVE REPLACEMENT COSTS ($ / Boe)

        Total Drilling, Before Revisions (a / d) 

        $            8.77

        $              –

        $                  63.86

        $            8.86

        All-in Total, Net of Revisions (b / e)  

        $            8.84

        $           6.97

        $                  13.97

        $            8.85

        All-in Total, Excluding Revisions Due to Price (b / (e – c)) 

        $            9.32

        $           6.97

        $                  13.97

        $            9.33

        RESERVE REPLACEMENT

        Drilling Only (d / g) 

        273%

        0%

        21%

        253%

        All-in Total, Net of Revisions and Dispositions (f / g) 

        272%

        20%

        -91%

        251%

        All-in Total, Excluding Revisions Due to Price ((f – c ) / g) 

        257%

        20%

        -91%

        238%

        Net Proved Reserve Additions From All Sources – Liquids (MMBbl) 

        Revisions

        10.7

        (0.2)

        –

        10.5

        Purchases in Place

        4.7

        –

        –

        4.7

        Extensions, Discoveries and Other Additions (h)

        510.4

        –

        –

        510.4

        Total Proved Reserve Additions 

        525.8

        (0.2)

        –

        525.6

        Sales in Place

        (0.8)

        –

        (6.3)

        (7.1)

        Net Proved Reserve Additions From All Sources (i) 

        525.0

        (0.2)

        (6.3)

        518.5

        Production (j)   

        186.6

        0.3

        1.5

        188.4

        RESERVE REPLACEMENT – LIQUIDS

        Drilling Only (h / j) 

        274%

        0%

        0%

        271%

        All-in Total, Net of Revisions and Dispositions (i / j) 

        281%

        -67%

        -420%

        275%

        EOG RESOURCES, INC.

        Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP)

        As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE)

        To Total Costs Incurred in Exploration and Development Activities (GAAP)

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures  (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe.  These statistics provide management and investors with an indication of the results of the current year capital investment program.  Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.  

        For the Twelve Months Ended December 31, 2018

         Total 

        PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe)

        Total Costs Incurred in Exploration and Development Activities (GAAP)

        $       6,419.7

        Less:  Asset Retirement Costs

        (69.7)

                   Acquisition Costs of Unproved Properties

        (487.3)

                   Acquisition Costs of Proved Properties

        (123.7)

        Drillbit Exploration and Development Expenditures (Non-GAAP) (j)

        $       5,739.0

        Total Proved Reserves – Extensions, Discoveries and Other Additions (MMBoe)

        669.7

        Add:   Conversion of Proved Undeveloped Reserves to Proved Developed

        265.7

        Less:  Proved Undeveloped Extensions and Discoveries

        (490.7)

        Proved Developed Reserves – Extensions and Discoveries (MMBoe)

        444.7

        Total Proved Reserves – Revisions (MMBoe)

        (4.7)

        Less:  Proved Undeveloped Reserves – Revisions

        8.2

                  Proved Developed – Revisions Due to Price

        (31.8)

        Proved Developed Reserves – Revisions Other Than Price (MMBoe)

        (28.3)

        Proved Developed Reserves – Extensions and Discoveries plus Revisions Other than Price (MMBoe) (k)

        416.4

        Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k)

        $          13.78

        EOG RESOURCES, INC.

        Quantitative Reconciliation of Total Exploration and Development Expenditures

        For Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP)

        As Used in the Calculation of Reserve Replacement Costs ($ / BOE)

        To Total Costs Incurred in Exploration and Development Activities (GAAP)

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe.  There are numerous ways that industry participants present Reserve Replacement Costs, including « Drilling Only » and « All-In », which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources.  Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program.  Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry.  Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures.  Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs.  EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures.

        2018

        2017

        2016

        2015

        2014

        Total Costs Incurred in Exploration and Development Activities (GAAP)

        $       6,419.7

        $       4,439.4

        $       6,445.2

        $        4,928.3

        $       7,904.8

        Less:  Asset Retirement Costs

        (69.7)

        (55.6)

        19.9

        (53.5)

        (195.6)

                  Non-Cash Acquisition Costs of Unproved Properties

        (290.5)

        (255.7)

        (3,101.8)

        –

        –

                  Acquisition Costs of Proved Properties

        (123.7)

        (72.6)

        (749.0)

        (480.6)

        (139.1)

        Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) (a) 

        $       5,935.8

        $       4,055.5

        $       2,614.3

        $        4,394.2

        $       7,570.1

        Total Costs Incurred in Exploration and Development Activities (GAAP)

        $       6,419.7

        $       4,439.4

        $       6,445.2

        $        4,928.3

        $       7,904.8

        Less:  Asset Retirement Costs

        (69.7)

        (55.6)

        19.9

        (53.5)

        (195.6)

                  Non-Cash Acquisition Costs of Unproved Properties

        (290.5)

        (255.7)

        (3,101.8)

        –

        –

                  Non-Cash Acquisition Costs of Proved Properties

        (70.9)

        (26.2)

        (732.3)

        –

        –

        Total Exploration and Development Expenditures (Non-GAAP) (b) 

        $       5,988.6

        $       4,101.9

        $       2,631.0

        $        4,874.8

        $       7,709.2

        Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe) 

        Revisions Due to Price (c)

        34.8

        154.0

        (100.7)

        (573.8)

        52.2

        Revisions Other Than Price

        (39.5)

        48.0

        252.9

        107.2

        48.4

        Purchases in Place

        11.6

        2.3

        42.3

        56.2

        14.4

        Extensions, Discoveries and Other Additions (d)

        669.7

        420.8

        209.0

        245.9

        519.2

        Total Proved Reserve Additions (e) 

        676.6

        625.1

        403.5

        (164.5)

        634.2

        Sales in Place

        (10.8)

        (20.7)

        (167.6)

        (3.5)

        (36.3)

        Net Proved Reserve Additions From All Sources (f) 

        665.8

        604.4

        235.9

        (168.0)

        597.9

        Production (g) 

        265.0

        224.4

        207.1

        211.2

        219.1

        RESERVE REPLACEMENT COSTS ($ / Boe)

        Total Drilling, Before Revisions (a / d) 

        $           8.86

        $          9.64

        $         12.51

        $         17.87

        $         14.58

        All-in Total, Net of Revisions (b / e)  

        $           8.85

        $          6.56

        $           6.52

        $        (29.63)

        $         12.16

        All-in Total, Excluding Revisions Due to Price (b / (e – c)) 

        $           9.33

        $          8.71

        $           5.22

        $         11.91

        $         13.25

        EOG RESOURCES, INC.

        Crude Oil and Natural Gas Financial Commodity

        Derivative Contracts

        EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method.  Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors.  EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential).  Presented below is a comprehensive summary of EOG’s Midland Differential basis swap contracts through February 19, 2019.  The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

        Midland Differential Basis Swap Contracts

        Weighted

        Average Price

        Volume

        Differential

        (Bbld) 

        ($/Bbl) 

        2018

        January 1, 2018 through December 31, 2018 (closed)

        15,000

        $                 1.063

        2019

        January 1, 2019 through February 28, 2019 (closed)

        20,000

        $                 1.075

        March 1, 2019 through December 31, 2019 

        20,000

        1.075

        EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential).  Presented below is a comprehensive summary of EOG’s Gulf Coast Differential basis swap contracts through February 19, 2019.  The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

        Gulf Coast Differential Basis Swap Contracts

        Weighted

        Average Price

        Volume

        Differential

        (Bbld) 

        ($/Bbl) 

        2018

        January 1, 2018 through September 30, 2018 (closed)

        37,000

        $                 3.818

        October 1, 2018 through December 31, 2018 (closed)

        52,000

        3.911

        2019

        January 1, 2019 through February 28, 2019 (closed) 

        13,000

        $                 5.572

        March 1, 2019 through December 31, 2019 

        13,000

        5.572

        Presented below is a comprehensive summary of EOG’s crude oil price swap contracts through February 19, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl.  

        Crude Oil Price Swap Contracts

        Weighted

        Volume

        Average Price

        (Bbld) 

        ($/Bbl) 

        2018

        January 1, 2018 through November 30, 2018 (closed)

        134,000

        $                 60.04

        On November 20, 2018, EOG entered into crude oil price swap contracts for the period December 1, 2018 through December 31, 2018, with notional volumes of 134,000 Bbld at an average price of $53.75 per Bbl.  These contracts offset the crude oil price swap contracts for the same time period with notional volumes of 134,000 Bbld at an average price of $60.04 per Bbl.  The net cash EOG received for settling these contracts was $26.1 million.  The offsetting contracts are excluded from the above table.

        Presented below is a comprehensive summary of EOG’s natural gas price swap contracts through February 19, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

        Natural Gas Price Swap Contracts

        Weighted

        Volume

        Average Price

        (MMBtud)

        ($/MMBtu)

        2018

        March 1, 2018 through November 30, 2018 (closed)

        35,000

        $                   3.00

        EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts.  The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. 

        In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts.  The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price.  Presented below is a comprehensive summary of EOG’s natural gas call and put option contracts through February 19, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

        Natural Gas Option Contracts

        Call Options Sold

        Put Options Purchased

        Weighted

        Weighted

        Volume

        Average Price

        Volume

        Average Price

        (MMBtud) 

        ($/MMBtu) 

        (MMBtud)

        ($/MMBtu)

        2018

        March 1, 2018 through November 30, 2018 (closed)

        120,000

        $                   3.38

        96,000

        $                   2.94

        Definitions

        Bbld

        Barrels per day

        $/Bbl

        Dollars per barrel

        MMBtud      

        Million British thermal units per day

        $/MMBtu

        Dollars per million British thermal units

        NYMEX

        U.S. New York Mercantile Exchange

        EOG RESOURCES, INC.

        Direct After-Tax Rate of Return (ATROR)

        The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves (« net » to EOG’s interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be).  As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. 

        Direct ATROR

        Based on Cash Flow and Time Value of Money

          – Estimated future commodity prices and operating costs

          – Costs incurred to drill, complete and equip a well, including facilities

        Excludes Indirect Capital

          – Gathering and Processing and other Midstream

          – Land, Seismic, Geological and Geophysical

        Payback ~12 Months on 100% Direct ATROR Wells

        First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured

        Return on Equity / Return on Capital Employed 

        Based on GAAP Accrual Accounting

        Includes All Indirect Capital and Growth Capital for Infrastructure

          – Eagle Ford, Bakken, Permian Facilities

          – Gathering and Processing

        Includes Legacy Gas Capital and Capital from Mature Wells

        EOG RESOURCES, INC.

        Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP),

        Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of Return on Capital

        Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), Net Income

        (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

        2018

        2017

        Return on Capital Employed (ROCE) (Non-GAAP)

        Net Interest Expense (GAAP)

        $

        245

        Tax Benefit Imputed (based on 21%) 

        (51)

        After-Tax Net Interest Expense (Non-GAAP) – (a) 

        $

        194

        Net Income (GAAP) – (b)                                                   

        $

        3,419

        Adjustments to Net Income, Net of Tax (See Accompanying Schedule)

        (201)

        (1)

        Adjusted Net Income (Non-GAAP) – (c)   

        $

        3,218

        Total Stockholders’ Equity – (d)   

        $

        19,364

        $

        16,283

        Average Total Stockholders’ Equity * – (e)   

        $

        17,824

        Current and Long-Term Debt (GAAP) – (f) 

        $

        6,083

        $

        6,387

        Less: Cash                                                       

        (1,556)

        (834)

        Net Debt (Non-GAAP) – (g) 

        $

        4,527

        $

        5,553

        Total Capitalization (GAAP) – (d) + (f)  

        $

        25,447

        $

        22,670

        Total Capitalization (Non-GAAP) – (d) + (g) 

        $

        23,891

        $

        21,836

        Average Total Capitalization (Non-GAAP) * – (h)   

        $

        22,864

        ROCE (GAAP Net Income) – [(a) + (b)] / (h)       

        15.8%

        ROCE (Non-GAAP Adjusted Net Income) – [(a) + (c)] / (h)       

        14.9%

        Return on Equity (ROE)

        ROE (GAAP Net Income) – (b) / (e)

        19.2%

        ROE (Non-GAAP Adjusted Net Income) – (c) / (e)

        18.1%

        * Average for the current and immediately preceding year

        Adjustments to Net Income (GAAP)

        (1) See below schedule for detail of adjustments to Net Income (GAAP) in 2018:

        Year Ended December 31, 2018

         Before 

         Income Tax  

         After 

         Tax 

         Impact 

         Tax 

        Adjustments:

            Add:   Mark-to-Market Commodity Derivative Contracts Impact

        $

        (93)

        $

        20

        $

        (73)

            Add:   Impairments of Certain Assets

        153

        (34)

        119

            Less:   Net Gains on Asset Dispositions

        (175)

        38

        (137)

            Less:  Tax Reform Impact

        –

        (110)

        (110)

        Total

        $

        (115)

        $

        (86)

        $

        (201)

        EOG RESOURCES, INC.

        Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total

        Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest

        Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

        2017

        2016

        2015

        2014

        2013

        Return on Capital Employed (ROCE) (Non-GAAP)

        (Calculated Using GAAP Net Income)

        Net Interest Expense (GAAP)

        $

        274

        $

        282

        $

        237

        $

        201

        $

        235

        Tax Benefit Imputed (based on 35%) 

        (96)

        (99)

        (83)

        (70)

        (82)

        After-Tax Net Interest Expense (Non-GAAP) – (a) 

        $

        178

        $

        183

        $

        154

        $

        131

        $

        153

        Net Income (Loss) (GAAP) – (b)                                                   

        $

        2,583

        $

        (1,097)

        $

        (4,525)

        $

        2,915

        $

        2,197

        Total Stockholders’ Equity – (d)   

        $

        16,283

        $

        13,982

        $

        12,943

        $

        17,713

        $

        15,418

        Average Total Stockholders’ Equity * – (e)   

        $

        15,133

        $

        13,463

        $

        15,328

        $

        16,566

        $

        14,352

        Current and Long-Term Debt (GAAP) – (f) 

        $

        6,387

        $

        6,986

        $

        6,655

        $

        5,906

        $

        5,909

        Less: Cash                                                       

        (834)

        (1,600)

        (719)

        (2,087)

        (1,318)

        Net Debt (Non-GAAP) – (g) 

        $

        5,553

        $

        5,386

        $

        5,936

        $

        3,819

        $

        4,591

        Total Capitalization (GAAP) – (d) + (f)  

        $

        22,670

        $

        20,968

        $

        19,598

        $

        23,619

        $

        21,327

        Total Capitalization (Non-GAAP) – (d) + (g) 

        $

        21,836

        $

        19,368

        $

        18,879

        $

        21,532

        $

        20,009

        Average Total Capitalization (Non-GAAP) * – (h)   

        $

        20,602

        $

        19,124

        $

        20,206

        $

        20,771

        $

        19,365

        ROCE (GAAP Net Income) – [(a) + (b)] / (h)       

        13.4%

        -4.8%

        -21.6%

        14.7%

        12.1%

        Return on Equity (ROE) (GAAP)

        ROE (GAAP Net Income) – (b) / (e)

        17.1%

        -8.1%

        -29.5%

        17.6%

        15.3%

        * Average for the current and immediately preceding year

        EOG RESOURCES, INC.

        Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total

        Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest

        Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

        2012

        2011

        2010

        2009

        2008

        Return on Capital Employed (ROCE) (Non-GAAP)

        (Calculated Using GAAP Net Income)

        Net Interest Expense (GAAP)

        $

        214

        $

        210

        $

        130

        $

        101

        $

        52

        Tax Benefit Imputed (based on 35%) 

        (75)

        (74)

        (46)

        (35)

        (18)

        After-Tax Net Interest Expense (Non-GAAP) – (a) 

        $

        139

        $

        136

        $

        84

        $

        66

        $

        34

        Net Income (Loss) (GAAP) – (b)                                                   

        $

        570

        $

        1,091

        $

        161

        $

        547

        $

        2,437

        Total Stockholders’ Equity – (d)   

        $

        13,285

        $

        12,641

        $

        10,232

        $

        9,998

        $

        9,015

        Average Total Stockholders’ Equity * – (e)   

        $

        12,963

        $

        11,437

        $

        10,115

        $

        9,507

        $

        8,003

        Current and Long-Term Debt (GAAP) – (f) 

        $

        6,312

        $

        5,009

        $

        5,223

        $

        2,797

        $

        1,897

        Less: Cash                                                       

        (876)

        (616)

        (789)

        (686)

        (331)

        Net Debt (Non-GAAP) – (g) 

        $

        5,436

        $

        4,393

        $

        4,434

        $

        2,111

        $

        1,566

        Total Capitalization (GAAP) – (d) + (f)  

        $

        19,597

        $

        17,650

        $

        15,455

        $

        12,795

        $

        10,912

        Total Capitalization (Non-GAAP) – (d) + (g) 

        $

        18,721

        $

        17,034

        $

        14,666

        $

        12,109

        $

        10,581

        Average Total Capitalization (Non-GAAP) * – (h)   

        $

        17,878

        $

        15,850

        $

        13,388

        $

        11,345

        $

        9,351

        ROCE (GAAP Net Income) – [(a) + (b)] / (h)       

        4.0%

        7.7%

        1.8%

        5.4%

        26.4%

        Return on Equity (ROE) (GAAP)

        ROE (GAAP Net Income) – (b) / (e)

        4.4%

        9.5%

        1.6%

        5.8%

        30.5%

        * Average for the current and immediately preceding year

        EOG RESOURCES, INC.

        Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total

        Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest

        Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

        2007

        2006

        2005

        2004

        2003

        Return on Capital Employed (ROCE) (Non-GAAP)

        (Calculated Using GAAP Net Income)

        Net Interest Expense (GAAP)

        $

        47

        $

        43

        $

        63

        $

        63

        $

        59

        Tax Benefit Imputed (based on 35%) 

        (16)

        (15)

        (22)

        (22)

        (21)

        After-Tax Net Interest Expense (Non-GAAP) – (a) 

        $

        31

        $

        28

        $

        41

        $

        41

        $

        38

        Net Income (Loss) (GAAP) – (b)                                                   

        $

        1,090

        $

        1,300

        $

        1,260

        $

        625

        $

        430

        Total Stockholders’ Equity – (d)   

        $

        6,990

        $

        5,600

        $

        4,316

        $

        2,945

        $

        2,223

        Average Total Stockholders’ Equity * – (e)   

        $

        6,295

        $

        4,958

        $

        3,631

        $

        2,584

        $

        1,948

        Current and Long-Term Debt (GAAP) – (f) 

        $

        1,185

        $

        733

        $

        985

        $

        1,078

        $

        1,109

        Less: Cash                                                       

        (54)

        (218)

        (644)

        (21)

        (4)

        Net Debt (Non-GAAP) – (g) 

        $

        1,131

        $

        515

        $

        341

        $

        1,057

        $

        1,105

        Total Capitalization (GAAP) – (d) + (f)  

        $

        8,175

        $

        6,333

        $

        5,301

        $

        4,023

        $

        3,332

        Total Capitalization (Non-GAAP) – (d) + (g) 

        $

        8,121

        $

        6,115

        $

        4,657

        $

        4,002

        $

        3,328

        Average Total Capitalization (Non-GAAP) * – (h)   

        $

        7,118

        $

        5,386

        $

        4,330

        $

        3,665

        $

        3,068

        ROCE (GAAP Net Income) – [(a) + (b)] / (h)       

        15.7%

        24.7%

        30.0%

        18.2%

        15.3%

        Return on Equity (ROE) (GAAP)

        ROE (GAAP Net Income) – (b) / (e)

        17.3%

        26.2%

        34.7%

        24.2%

        22.1%

        * Average for the current and immediately preceding year

        EOG RESOURCES, INC.

        Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total

        Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest

        Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

        (Unaudited; in millions, except ratio data)

        The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation.  EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

        2002

        2001

        2000

        1999

        1998

        Return on Capital Employed (ROCE) (Non-GAAP)

        (Calculated Using GAAP Net Income)

        Net Interest Expense (GAAP)

        $

        60

        $

        45

        $

        61

        $

        62

        Tax Benefit Imputed (based on 35%) 

        (21)

        (16)

        (21)

        (22)

        After-Tax Net Interest Expense (Non-GAAP) – (a) 

        $

        39

        $

        29

        $

        40

        $

        40

        Net Income (Loss) (GAAP) – (b)                                                   

        $

        87

        $

        399

        $

        397

        $

        569

        Total Stockholders’ Equity – (d)   

        $

        1,672

        $

        1,643

        $

        1,381

        $

        1,130

        $

        1,280

        Average Total Stockholders’ Equity * – (e)   

        $

        1,658

        $

        1,512

        $

        1,256

        $

        1,205

        Current and Long-Term Debt (GAAP) – (f) 

        $

        1,145

        $

        856

        $

        859

        $

        990

        $

        1,143

        Less: Cash                                                       

        (10)

        (3)

        (20)

        (25)

        (6)

        Net Debt (Non-GAAP) – (g) 

        $

        1,135

        $

        853

        $

        839

        $

        965

        $

        1,137

        Total Capitalization (GAAP) – (d) + (f)  

        $

        2,817

        $

        2,499

        $

        2,240

        $

        2,120

        $

        2,423

        Total Capitalization (Non-GAAP) – (d) + (g) 

        $

        2,807

        $

        2,496

        $

        2,220

        $

        2,095

        $

        2,417

        Average Total Capitalization (Non-GAAP) * – (h)   

        $

        2,652

        $

        2,358

        $

        2,158

        $

        2,256

        ROCE (GAAP Net Income) – [(a) + (b)] / (h)       

        4.8%

        18.2%

        20.2%

        27.0%

        Return on Equity (ROE) (GAAP)

        ROE (GAAP Net Income) – (b) / (e)

        5.2%

        26.4%

        31.6%

        47.2%

        * Average for the current and immediately preceding year

        EOG RESOURCES, INC.

        Cash Operating Expenses per Barrel of Oil Equivalent (Boe)

        (Unaudited; in thousands, except per Boe amounts)

        Year Ended

        December 31,

        2018

        2017

        2016

        2015

        2014

        Cash Operating Expenses (GAAP)*

        Lease and Well

        $         1,282,678

        $         1,044,847

        $            927,452

        $         1,182,282

        $         1,416,413

        Transportation Costs

        746,876

        740,352

        764,106

        849,319

        972,176

        General and Administrative

        426,969

        434,467

        394,815

        366,594

        402,010

             Cash Operating Expenses

        2,456,523

        2,219,666

        2,086,373

        2,398,195

        2,790,599

        Less:  Legal Settlement – Early Leasehold Termination

        –

        (10,202)

        –

        (19,355)

        –

        Less:  Voluntary Retirement Expense

        –

        –

        (42,054)

        –

        –

        Less:  Acquisition Costs – Yates Transaction

        –

        –

        (5,100)

        –

        –

        Less:  Joint Venture Transaction Costs

        –

        (3,056)

        –

        –

        –

        Less:  Joint Interest Billings Deemed Uncollectible

        –

        (4,528)

        –

        –

        –

             Adjusted Cash Operating Expenses (Non-GAAP) – (a)

        $         2,456,523

        $         2,201,880

        $         2,039,219

        $         2,378,840

        $         2,790,599

        Volume – Thousand Barrels of Oil Equivalent – (b)

        262,516

        222,251

        204,929

        208,862

        217,073

        Adjusted Cash Operating Expenses Per Boe (Non-GAAP) – (a) / (b)

        $                 9.36

        (c)

        $                 9.91

        (d)

        $                 9.95

        (e)

        $                11.39

        (f)

        $               12.86

        (g)

        Adjusted Cash Operating Expenses Per Boe (Non-GAAP) –
           Percentage Decrease

        2018 compared to 2017 – [(c) – (d)] / (d)       

        -6%

        2018 compared to 2016 – [(c) – (e)] / (e)       

        -6%

        2018 compared to 2015 – [(c) – (f)] / (f)       

        -18%

        2018 compared to 2014 – [(c) – (g)] / (g)       

        -27%

        * Includes stock compensation expense and other non-cash items.

        EOG RESOURCES, INC.

        Cost per Barrel of Oil Equivalent (Boe)

        (Unaudited; in thousands, except per Boe amounts)

        Three Months Ended

        March 31,

        June 30,

        September 30,

        December 31,

        2018

        2018

        2018

        2018

        Volume – Thousand Barrels of Oil Equivalent – (a)

        59,394

        63,898

        68,890

        70,334

             Crude Oil and Condensate

        $    2,101,308

        $   2,377,528

        $            2,655,278

        $         2,383,326

             Natural Gas Liquids

        221,415

        286,354

        353,704

        266,037

             Natural Gas

        299,766

        300,845

        311,713

        389,213

        Total Wellhead Revenues – (b)

        $    2,622,489

        $   2,964,727

        $            3,320,695

        $         3,038,576

        Operating Costs

             Lease and Well

        $      300,064

        $      314,604

        $               321,568

        $            346,442

             Transportation Costs

        176,957

        177,797

        196,027

        196,095

             Gathering and Processing Costs

        101,345

        109,169

        114,063

        112,396

             General and Administrative

        94,698

        104,083

        111,284

        116,904

             Taxes Other Than Income

        179,084

        194,268

        209,043

        190,086

             Interest Expense, Net

        61,956

        63,444

        63,632

        56,020

        Total Cash Operating Cost (excluding
          DD&A and Exploration Costs) – (c)

        $      914,104

        $      963,365

        $            1,015,617

        $         1,017,943

             Depreciation, Depletion and Amortization (DD&A)

        748,591

        848,674

        918,180

        919,963

        Total Operating Cost (excluding Exploration
          Costs) – (d)

        $    1,662,695

        $   1,812,039

        $            1,933,797

        $         1,937,906

             Exploration Costs

        $        34,836

        $        47,478

        $                32,823

        $              33,862

             Dry Hole Costs

        –

        4,902

        358

        145

             Impairments

        64,609

        51,708

        44,617

        186,087

             Total Exploration Costs 

        99,445

        104,088

        77,798

        220,094

                  Less:  Impairments (Non-GAAP)

        (20,876)

        –

        –

        (131,795)

             Total Exploration Costs (Non-GAAP)

        $        78,569

        $      104,088

        $                77,798

        $              88,299

        Total Operating Cost (Non-GAAP) (including Exploration
          Costs) – (e)

        $    1,741,264

        $   1,916,127

        $            2,011,595

        $         2,026,205

        Composite Average Wellhead Revenue per Boe – (b) / (a)

        $          44.15

        $         46.40

        $                  48.20

        $                43.20

        Total Cash Operating Cost per Boe 
          (excluding DD&A and Exploration Costs) – (c) / (a)

        $          15.39

        $         15.07

        $                  14.75

        $                14.48

        Composite Average Margin per Boe (excluding
           DD&A and Exploration Costs) – [(b) / (a) – (c) / (a)]

        $          28.76

        $         31.33

        $                  33.45

        $                28.72

        Total Operating Cost per Boe (excluding
          Exploration Costs) – (d) / (a)

        $          27.99

        $         28.35

        $                  28.08

        $                27.56

        Composite Average  Margin per Boe (excluding
           Exploration Costs) – [(b) / (a) – (d) / (a)]

        $          16.16

        $         18.05

        $                  20.12

        $                15.64

        Total Operating Cost per Boe (Non-GAAP) (including
          Exploration Costs) (e) / (a)

        $          29.31

        $         29.98

        $                  29.21

        $                28.82

        Composite Average Margin per Boe (Non-GAAP)
          (including Exploration Costs) – [(b) / (a) – (e) / (a)]

        $          14.84

        $         16.42

        $                  18.99

        $                14.38

        EOG RESOURCES, INC.

        Cost per Barrel of Oil Equivalent (Boe)

        (Unaudited; in thousands, except per Boe amounts)

        Year Ended

        December 31,

        2018

        2017

        2016

        2015

        2014

        Volume – Thousand Barrels of Oil Equivalent – (a)

        262,516

        222,251

        204,929

        208,862

        217,073

             Crude Oil and Condensate

        $    9,517,440

        $   6,256,396

        $            4,317,341

        $         4,934,562

        $    9,742,480

             Natural Gas Liquids

        1,127,510

        729,561

        437,250

        407,658

        934,051

             Natural Gas

        1,301,537

        921,934

        742,152

        1,061,038

        1,916,386

        Total Wellhead Revenues – (b)

        $  11,946,487

        $   7,907,891

        $            5,496,743

        $         6,403,258

        $  12,592,917

        Operating Costs

             Lease and Well

        $    1,282,678

        $   1,044,847

        $               927,452

        $         1,182,282

        $    1,416,413

             Transportation Costs

        746,876

        740,352

        764,106

        849,319

        972,176

             Gathering and Processing Costs

        436,973

        148,775

        122,901

        146,156

        145,800

             General and Administrative

        426,969

        434,467

        394,815

        366,594

        402,010

                  Less:  Voluntary Retirement Expense

        –

        –

        (42,054)

        –

        –

                  Less:  Acquisition Costs

        –

        –

        (5,100)

        –

        –

                  Less:  Legal Settlement – Early Leasehold Termination

        –

        (10,202)

        –

        (19,355)

        –

                  Less:  Joint Venture Transaction Costs

        –

        (3,056)

        –

        –

        –

                  Less:  Joint Interest Billings Deemed Uncollectible

        –

        (4,528)

        –

        –

        –

             General and Administrative (Non-GAAP)

        426,969

        416,681

        347,661

        347,239

        402,010

             Taxes Other Than Income

        772,481

        544,662

        349,710

        421,744

        757,564

             Interest Expense, Net

        245,052

        274,372

        281,681

        237,393

        201,458

        Total Cash Operating Cost (Non-GAAP) (excluding
          DD&A and Exploration Costs) – (c)

        $    3,911,029

        $   3,169,689

        $            2,793,511

        $         3,184,133

        $    3,895,421

             Depreciation, Depletion and Amortization (DD&A)

        3,435,408

        3,409,387

        3,553,417

        3,313,644

        3,997,041

        Total Operating Cost (Non-GAAP) (excluding Exploration
          Costs) – (d)

        $    7,346,437

        $   6,579,076

        $            6,346,928

        $         6,497,777

        $    7,892,462

             Exploration Costs

        $      148,999

        $      145,342

        $               124,953

        $            149,494

        $      184,388

             Dry Hole Costs

        5,405

        4,609

        10,657

        14,746

        48,490

             Impairments

        347,021

        479,240

        620,267

        6,613,546

        743,575

             Total Exploration Costs 

        501,425

        629,191

        755,877

        6,777,786

        976,453

                  Less:  Impairments (Non-GAAP)

        (152,671)

        (261,452)

        (320,617)

        (6,307,593)

        (824,312)

             Total Exploration Costs (Non-GAAP)

        $      348,754

        $      367,739

        $               435,260

        $            470,193

        $      152,141

        Total Operating Cost (Non-GAAP) (including Exploration
          Costs) – (e)

        $    7,695,191

        $   6,946,815

        $            6,782,188

        $         6,967,970

        $    8,044,603

        Composite Average Wellhead Revenue per Boe – (b) / (a)

        $          45.51

        $         35.58

        $                  26.82

        $                30.66

        $          58.01

        Total Cash Operating Cost per Boe (Non-GAAP)
          (excluding DD&A and Exploration Costs) – (c) / (a)

        $          14.90

        $         14.25

        $                  13.64

        $                15.25

        $          17.95

        Composite Average Margin per Boe (Non-GAAP)
           (excluding DD&A and Exploration Costs) – [(b) / (a) – (c) / (a)]

        $          30.61

        $         21.33

        $                  13.18

        $                15.41

        $          40.06

        Total Operating Cost per Boe (Non-GAAP) (excluding
          Exploration Costs) – (d) / (a)

        $          27.99

        $         29.59

        $                  30.98

        $                31.11

        $          36.38

        Composite Average Margin per Boe (Non-GAAP)
           (excluding Exploration Costs) – [(b) / (a) – (d) / (a)]

        $          17.52

        $           5.99

        $                   (4.16)

        $                (0.45)

        $          21.63

        Total Operating Cost per Boe (Non-GAAP) (including
          Exploration Costs) – (e) / (a)

        $          29.32

        $         31.24

        $                  33.10

        $                33.36

        $          37.08

        Composite Average Margin per Boe (Non-GAAP)
          (including Exploration Costs) – [(b) / (a) – (e) / (a)]

        $          16.19

        $           4.34

        $                   (6.28)

        $                (2.70)

        $          20.93

        EOG RESOURCES, INC.

        First Quarter and Full Year 2019 Forecast and Benchmark Commodity Pricing

             (a)  First Quarter and Full Year 2019 Forecast

        The forecast items for the first quarter and full year 2019 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release.  EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.  This forecast, which should be read in conjunction with the accompanying press release and EOG’s related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

             (b)  Capital Expenditures

        The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Exchanges.

             (c)  Benchmark Commodity Pricing

        EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

        EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.

        Estimated Ranges

        (Unaudited)

        1Q 2019

        Full Year 2019

        Daily Sales Volumes

             Crude Oil and Condensate Volumes (MBbld)

                  United States

        426.6

        –

        434.2

        442.6

        –

        458.2

                  Trinidad

        0.4

        –

        0.6

        0.4

        –

        0.6

                  Other International

        0.0

        –

        0.2

        0.0

        –

        0.2

                       Total

        427.0

        –

        435.0

        443.0

        –

        459.0

             Natural Gas Liquids Volumes (MBbld)

                       Total

        115.0

        –

        125.0

        120.0

        –

        140.0

             Natural Gas Volumes (MMcfd)

                  United States

        950

        –

        1,000

        1,030

        –

        1,130

                  Trinidad

        245

        –

        275

        250

        –

        290

                  Other International

        30

        –

        40

        30

        –

        40

                       Total

        1,225

        –

        1,315

        1,310

        –

        1,460

             Crude Oil Equivalent Volumes (MBoed)  

                  United States

        699.9

        –

        725.9

        734.3

        –

        786.5

                  Trinidad

        41.2

        –

        46.4

        42.1

        –

        48.9

                  Other International

        5.0

        –

        6.9

        5.0

        –

        6.9

                       Total

        746.1

        –

        779.2

        781.4

        –

        842.3

        Capital Expenditures ($MM)

        $

        1,750

        –

        $

        1,950

        $

        6,100

        –

        $

        6,500

        Estimated Ranges

        (Unaudited)

        1Q 2019

        Full Year 2019

        Operating Costs

             Unit Costs ($/Boe)

                  Lease and Well

        $

        4.90

        –

        $

        5.30

        $

        4.50

        –

        $

        5.30

                  Transportation Costs

        $

        2.50

        –

        $

        3.00

        $

        2.60

        –

        $

        3.10

                  Depreciation, Depletion and Amortization

        $

        12.50

        –

        $

        13.00

        $

        12.25

        –

        $

        13.25

        Expenses ($MM)

             Exploration and Dry Hole

        $

        35

        –

        $

        45

        $

        155

        –

        $

        195

             Impairment

        $

        55

        –

        $

        65

        $

        190

        –

        $

        230

             General and Administrative

        $

        110

        –

        $

        120

        $

        450

        –

        $

        490

             Gathering and Processing 

        $

        100

        –

        $

        110

        $

        440

        –

        $

        480

             Capitalized Interest

        $

        6

        –

        $

        8

        $

        25

        –

        $

        30

             Net Interest

        $

        54

        –

        $

        56

        $

        190

        –

        $

        200

        Taxes Other Than Income (% of Wellhead Revenue)

        7.2%

        –

        7.6%

        7.2%

        –

        7.6%

        Income Taxes

             Effective Rate 

        20%

        –

        25%

        20%

        –

        25%

             Current Tax (Benefit) / Expense ($MM)

        $

        (55)

        –

        $

        (15)

        $

        (190)

        –

        $

        (110)

        Pricing – (Refer toBenchmark Commodity Pricingin text)

             Crude Oil and Condensate ($/Bbl)

                  Differentials

                       United States – above (below) WTI

        $

        0.25

        –

        $

        1.25

        $

        (1.00)

        –

        $

        1.00

                       Trinidad – above (below) WTI

        $

        (11.00)

        –

        $

        (9.00)

        $

        (11.00)

        –

        $

        (9.00)

                       Other International – above (below) WTI

        $

        5.00

        –

        $

        9.00

        $

        (1.00)

        –

        $

        1.00

             Natural Gas Liquids

                  Realizations as % of WTI

        37%

        –

        43%

        37%

        –

        43%

             Natural Gas ($/Mcf)

                  Differentials

                       United States – above (below) NYMEX Henry Hub

        $

        (0.40)

        –

        $

        0.00

        $

        (0.50)

        –

        $

        0.10

                  Realizations

                       Trinidad

        $

        2.50

        –

        $

        2.90

        $

        2.50

        –

        $

        3.20

                       Other International

        $

        4.30

        –

        $

        4.80

        $

        4.00

        –

        $

        5.00

        Definitions

        $/Bbl         U.S. Dollars per barrel

        $/Boe        U.S. Dollars per barrel of oil equivalent

        $/Mcf         U.S. Dollars per thousand cubic feet

        $MM          U.S. Dollars in millions

        MBbld       Thousand barrels per day

        MBoed      Thousand barrels of oil equivalent per day

        MMcfd       Million cubic feet per day

        NYMEX     U.S. New York Mercantile Exchange

        WTI           West Texas Intermediate

        SOURCE EOG Resources, Inc.

        https://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2018-results-and-announces-2019-capital-program-300802665.html

    • Denbury Reports 2018 Fourth Quarter and Full-Year Results, Year-End 2018 Proved Reserves, 2019 Capital Budget and Estimated Production

      mars 1, 2019

      • PLANO, Texas, Feb. 27, 2019 (GLOBE NEWSWIRE) — Denbury Resources Inc. (NYSE: DNR) (“Denbury” or the “Company”) today announced its fourth quarter and full-year 2018 financial and operating results, along with its 2019 capital budget and currently estimated 2019 production.

        2018 FOURTH QUARTER AND FULL-YEAR HIGHLIGHTS

        Financial

        • Delivered net income of $174 million for 4Q 2018 and $323 million for 2018
          ◦ Adjusted net income(1) (a non-GAAP measure) of $46 million for 4Q 2018 and $220 million for 2018
          ◦ Adjusted EBITDAX(1) (a non-GAAP measure) of $141 million for 4Q 2018 and $584 million for 2018
          ◦ Generated $81 million of free cash flow(1) (a non-GAAP measure) in 2018
        • Incurred $323 million of development capital, within original 2018 capital budget range
        • Reduced debt principal by $243 million in 2018, ending the year with no outstanding borrowings on the Company’s bank credit facility and $39 million of cash on hand, resulting in a total net debt reduction of over $280 million
        • Reduced year-end 2018 ratio of net debt to 2018 Adjusted EBITDAX(1) to 4.2x (including hedge settlements) and 3.3x (excluding hedge settlements), compared to 6.6x and 5.9x, respectively, at year-end 2017
        • PV-10 Value(1) (a non-GAAP measure) increased to $4.0 billion, up 59% from $2.5 billion at year-end 2017
        • Reduced full-year 2018 G&A expenses by $30 million, or 30% from 2017

        Operational and Other

        • Entered into a Definitive Merger Agreement with Penn Virginia Corporation
        • Proved reserves increased to 262 million barrels of oil equivalent (“BOE”), representing 111% replacement of 2018 production
        • Produced 59,867 BOE per day (“BOE/d”) for 4Q 2018, up 1% from 3Q 2018, and 60,341 BOE/d for full-year 2018, up slightly from 2017
        • Drilled seven successful wells during full-year 2018 within the Cedar Creek Anticline exploitation program
        • Sanctioned a major CO2 enhanced oil recovery development project at Cedar Creek Anticline

        2019 BUDGET HIGHLIGHTS

        • 2019 development capital budget range of $240 million to $260 million, 20% to 25% lower than in 2018
        • Current capital program spreads CO2 pipeline extension to CCA over two years, with minimal impact to peak production timing
        • 2019 production expected to average 56,000 to 60,000 BOE/d
        • Expect to generate free cash flow(2) of $50 million to $100 million in 2019 assuming $50 per Bbl WTI oil price

        (1) A non-GAAP measure.  See accompanying schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors.
        (2) Represents currently forecasted cash flow, less development capital, capitalized interest and interest treated as debt reduction.

        2018 FOURTH QUARTER RESULTS

        Sequential and year-over-year comparisons of selected quarterly information are shown in the following table:

        Quarter Ended
        (in millions, except per share and unit data) Dec. 31, 2018 Sept. 30, 2018 Dec. 31, 2017
        Net income $ 174 $ 78 $ 127
        Adjusted net income(1) (non-GAAP measure) 46 59 48
        Net income per diluted share 0.38 0.17 0.31
        Adjusted net income per diluted share(1)(2) (non-GAAP measure) 0.10 0.13 0.12
        Cash flows from operations 136 148 124
        Adjusted cash flows from operations less special items(1) (non-GAAP measure) 133 135 134
        Revenues $ 336 $ 388 $ 321
        Payment on settlements of commodity derivatives (26 ) (62 ) (9 )
        Revenues and commodity derivative settlements combined $ 310 $ 326 $ 312
        Average realized oil price per barrel (excluding derivative settlements) $ 60.50 $ 71.44 $ 57.17
        Average realized oil price per barrel (including derivative settlements) 55.75 59.78 55.49
        Total production (BOE/d) 59,867 59,181 61,144

        2018 FULL-YEAR RESULTS

        Year-over-year comparisons of selected annual information are shown in the following table:

        Year Ended
        (in millions, except per share and unit data) Dec. 31, 2018 Dec. 31, 2017
        Net income $ 323 $ 163
        Adjusted net income(1) (non-GAAP measure) 220 55
        Net income per diluted share 0.71 0.41
        Adjusted net income per diluted share(1)(2) (non-GAAP measure) 0.48 0.14
        Cash flows from operations 530 267
        Adjusted cash flows from operations less special items(1) (non-GAAP measure) 527 329
        Revenues $ 1,454 $ 1,116
        Payment on settlements of commodity derivatives (175 ) (48 )
        Revenues and commodity derivative settlements combined $ 1,279 $ 1,068
        Average realized oil price per barrel (excluding derivative settlements) $ 66.11 $ 50.64
        Average realized oil price per barrel (including derivative settlements) 57.91 48.40
        Total production (BOE/d) 60,341 60,298

        (1) A non-GAAP measure.  See accompanying schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors.
        (2) Calculated using average diluted shares outstanding of 456.7 million, 458.5 million, and 405.8 million for the three months ended December 31, 2018, September 30, 2018 and December 31, 2017, respectively, and 456.2 million and 395.9 million for the years ended December 31, 2018 and 2017, respectively.

        MANAGEMENT COMMENT

        Chris Kendall, Denbury’s CEO, commented, “I am pleased with where Denbury stands today and I continue to be very optimistic about the Company’s future.  Through the hard work, innovative thinking, and dedication of our great employees, in 2018 we set Company records in safety and environmental performance, drove multiple exploitation successes, significantly reduced debt, and sanctioned the EOR development of CCA, setting the path toward unlocking the massive resource and cash flow potential of that great asset.  The resilience of our high margin, low decline asset base continued to shine, and the resourcefulness of our teams in deriving even greater value from those high-quality assets was evident, particularly with the highly successful phase 5 development of the Bell Creek EOR flood.  We drove several new exploitation accomplishments in 2018 with the drilling of seven successful exploitation wells in the Cedar Creek Anticline and a promising Tinsley Field Cotton Valley test, and we continue to identify even more exciting new exploitation opportunities across our portfolio.  While many peer companies are now attempting to live within cash flow, this discipline is the standard at Denbury, as evidenced by over $80 million in free cash generated in 2018.  We also made great progress on our balance sheet during the year, reducing net debt over $280 million and improving our leverage ratio by nearly two and a half turns, ending the year with cash on hand and nothing drawn on our bank line.

        “Considering the uncertainty in the current oil price environment, we developed our 2019 budget based on a $50 oil price, exercising the great flexibility provided by our resilient, low decline assets.  The midpoint of our resulting $240 to $260 million capital budget range is 23% lower than the $323 million of capital we spent in 2018.  Based on a $50 oil price assumption and our current plans and estimates, we expect to generate between $50 million and $100 million of free cash flow in 2019.  This provides us optionality for continuing to improve the balance sheet or to conserve cash for future development capital.

        “A key factor in our 2019 capital plan is the timing of our CO2 pipeline extension to Cedar Creek Anticline.  We have adjusted our plan to now complete pipeline construction in 2020, allowing us to defer roughly $100 million in spending this year with only a minor impact on the overall development plan and the expected tertiary production ramp.

        “Lastly and importantly, we remain highly focused on our merger with Penn Virginia Corporation.  We strongly believe this combination is a great opportunity for the stakeholders of both companies from both a short-term and long-term perspective and over a wide range of oil prices.  Leading up to the planned April 17 shareholder meetings, we look forward to engaging with shareholders of both companies to further discuss the mutual benefits and the great potential created by this merger.”

        REVIEW OF OPERATING AND FINANCIAL RESULTS

        Denbury’s production averaged 59,867 BOE/d during fourth quarter 2018, including 37,764 barrels of oil per day (“Bbls/d”) from tertiary properties and 22,103 BOE/d from non-tertiary properties.  On a sequential-quarter basis, production in fourth quarter 2018 increased by 686 BOE/d, or 1%, from third quarter 2018 (the “prior quarter”), primarily due to continued response from Bell Creek’s CO2 flood expansion and additional drilling in the Company’s Cedar Creek Anticline Mission Canyon drilling program.  On an annual basis, Denbury’s 2018 production averaged 60,341 BOE/d, slightly above 2017 levels.  Further production information is provided on page 19 of this press release.

        Denbury’s average realized oil price, excluding derivative contracts, was $60.50 per Bbl in fourth quarter 2018, compared to $71.44 per Bbl in the prior quarter and $57.17 per Bbl in fourth quarter 2017.  Including derivative settlements, Denbury’s average realized oil price was $55.75 per Bbl in fourth quarter 2018, compared to $59.78 per Bbl in the prior quarter and $55.49 per Bbl in fourth quarter 2017.

        The Company’s average realized oil price in fourth quarter 2018 was $1.69 per Bbl above NYMEX WTI prices, compared to $1.84 per Bbl above NYMEX WTI prices in the prior quarter and $1.70 per Bbl above NYMEX WTI prices in fourth quarter 2017.  The sequential decrease was primarily attributable to softening of the Company’s Rocky Mountain region differentials, partially offset by improvement in LLS index prices relative to NYMEX WTI.  During fourth quarter 2018, the Company sold approximately 60% of its crude oil at prices based on, or partially tied to, the LLS index price, and the balance at prices based on various other indexes tied to NYMEX WTI prices, primarily in the Rocky Mountain region.

        The Company’s total lease operating expenses in fourth quarter 2018 were $128 million, an increase of $6 million, or 5%, on an absolute-dollar basis when compared to the prior quarter and an increase of $24 million, or 22%, compared to fourth quarter 2017.  The sequential and year-over-year increases were impacted by higher CO2 expense and increased workover activity, with the year-over-year increase also impacted by the fourth quarter of 2017 including a $7 million reduction for pricing adjustments of certain industrial-sourced CO2.

        Taxes other than income, which include ad valorem, production and franchise taxes, decreased $5 million from the third quarter of 2018 due to a decrease in oil and natural gas revenues.

        General and administrative expenses were $10 million in fourth quarter 2018, a decrease of $11 million compared to the prior quarter and a decrease of $10 million compared to fourth quarter 2017, mainly due to downward adjustments in estimated performance-based compensation in the current quarter.  On an annual basis, net general and administrative expenses totaled $71 million, a decrease of $30 million, or 30%, from 2017 to 2018, with the decrease primarily from employee-related costs saved due to the August 2017 workforce reductions and a continued focus on cost efficiencies.

        Interest expense, net of capitalized interest, totaled $18 million in fourth quarter 2018, a slight decrease of $1 million from the prior quarter and a decrease of $6 million from fourth quarter 2017.  Interest expense excludes approximately $21 million and $15 million in the fourth quarters of 2018 and 2017, respectively, of interest recorded as a reduction of debt for financial reporting purposes instead of interest expense, due to the accounting associated with debt exchange transactions completed in 2017 and 2018.  A schedule detailing the components of interest expense is included on page 21 of this press release.

        Depletion, depreciation, and amortization (“DD&A”) increased to $60 million during fourth quarter 2018, compared to $53 million in fourth quarter 2017.  The difference was primarily due to an increase in oil and gas property costs and future development costs and accelerated depreciation of leasehold improvement costs due to the sublease of office space.

        Other expenses were $73 million in the fourth quarter of 2018, which includes (1) a $49 million accrued expense associated with a trial court’s unfavorable ruling related to the non-delivery of helium volumes from the Company’s Riley Ridge Unit under a helium supply contract, a matter in which the Company intends to vigorously defend its position and pursue all of its rights, which may include an appeal of the trial court’s ruling, (2) an $18 million impairment for an investment related to a proposed plant in the Gulf Coast that would potentially supply CO2 to Denbury, due to uncertainty that the project will achieve financial close, and (3) $4 million of transaction costs related to the potential merger with Penn Virginia Corporation.

        Denbury’s effective tax rates for the fourth quarter and full-year 2018 were 22% and 21%, respectively, which is lower than the Company’s statutory rate of 25% primarily due to recognized tax benefits for enhanced oil recovery credits, as well as greater tax versus book expense for stock-based compensation.  The Company’s statutory rate decreased from the prior-year rate of 38% due to reduction of the federal income tax rate from 35% to 21% as enacted by the Tax Cut and Jobs Act in December 2017.

        2018 PROVED RESERVES

        The Company’s total estimated proved oil and natural gas reserves at December 31, 2018 were 262 million BOE, consisting of 255 million barrels of crude oil, condensate and natural gas liquids (together, “liquids”), and 43 billion cubic feet (7 million BOE) of natural gas.  Reserves were 97% liquids and 88% proved developed, with 58% of total proved reserves attributable to Denbury’s CO2 tertiary operations.  Total proved reserves increased by 24 million BOE, representing a 111% replacement of 2018 production.  The increase was primarily due to 22 million BOE of positive revisions of previous estimates associated with changes in commodity prices, production timing and performance.

        The following table details changes in the Company’s estimated quantities of proved reserves:

        Oil
        (MMBbl)        		 Gas
        (Bcf)        		 MMBOE

        PV-10 Value(1)
        Balance at December 31, 2017 253 43 260 $ 2.5 billion
        Revisions of previous estimates 21 6 22
        Improved recovery 2 0 2
        2018 production (21 ) (4 ) (22 )
        Sales of minerals or other revisions 0 (2 ) 0
        Balance at December 31, 2018 255 43 262 $ 4.0 billion

        (1) A non-GAAP measure.  See accompanying schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors.

        Year-end 2018 estimated proved reserves and the discounted net present value of Denbury’s proved reserves, using a 10% per annum discount rate (“PV-10 Value”)(1) (a non-GAAP measure), were computed using first-day-of-the-month 12-month average prices of $65.56 per Bbl for oil (based on NYMEX prices) and $3.10 per million British thermal unit (“MMBtu”) for natural gas (based on Henry Hub cash prices), adjusted for prices received at the field.  Comparative prices for 2017 were $51.34 per Bbl of oil and $2.98 per MMBtu for natural gas, adjusted for prices received at the field.  The standardized measure of discounted estimated future net cash flows after income taxes of Denbury’s proved reserves at December 31, 2018 (“Standardized Measure”) was $3.4 billion compared to $2.2 billion at December 31, 2017.  PV-10 Value(1) was $4.0 billion at December 31, 2018, compared to $2.5 billion at December 31, 2017, which represents a 59% year-over-year increase.  See the accompanying schedules for an explanation of the difference between PV-10 Value(1) and the Standardized Measure and the uses of this information.

        Denbury’s estimated proved CO2 reserves at year-end 2018, on a gross or 8/8th’s basis for operated fields, together with its overriding royalty interest in LaBarge Field in Wyoming, totaled 6.1 trillion cubic feet (“Tcf”), slightly lower than CO2 reserves of 6.4 Tcf as of December 31, 2017 due to 2018 production.  Of these total CO2 reserves, 5.0 Tcf are located in the Gulf Coast region and 1.1 Tcf in the Rocky Mountain region.  In addition to these proved CO2 reserves, Denbury is currently purchasing CO2 from two industrial facilities in the Gulf Coast region and a gas processing facility in the Rocky Mountain region, all under long-term contractual agreements.  Although there are no proved CO2 reserves associated with these long-term agreements, they currently supply approximately 80 million cubic feet per day, or roughly 15% of the CO2 Denbury is using for its tertiary operations.

        2019 CAPITAL BUDGET AND PRODUCTION ESTIMATES

        Denbury’s 2019 capital budget, excluding acquisitions and capitalized interest, is between $240 million and $260 million, a decrease of 20% to 25% from the Company’s 2018 capital spending level.  The budget provides for approximate spending as follows:

        • $100 million for tertiary oil field expenditures;
        • $70 million for other areas, primarily non-tertiary oil field expenditures including exploitation projects;
        • $30 million for CO2 sources and pipelines; and
        • $50 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

        In addition, capitalized interest for 2019 is estimated at between $30 million and $40 million.  At this spending level, the Company currently anticipates 2019 production of between 56,000 and 60,000 BOE/d and expects to generate free cash flow of $50 million to $100 million assuming a $50 per Bbl WTI oil price.

        FOURTH QUARTER AND FULL-YEAR 2018 RESULTS CONFERENCE CALL INFORMATION

        Denbury management will host a conference call to review and discuss fourth quarter and full-year 2018 financial and operating results, together with its financial and operating outlook for 2019 and additional information related to the acquisition of Penn Virginia, today, Wednesday, February 27, at 10:00 A.M. (Central).  Members of Penn Virginia management will be available to participate in certain portions of the conference call.  Additionally, Denbury will post presentation materials on its website which will be referenced during the conference call.  Individuals who would like to participate should dial 800.230.1093 or 612.332.0226 ten minutes before the scheduled start time.  To access a live audio webcast of the conference call and accompanying slide presentation, please visit the investor relations section of the Company’s website at www.denbury.com.  The webcast will be archived on the website, and a telephonic replay will be accessible for at least one month after the call by dialing 800.475.6701 or 320.365.3844 and entering confirmation number 426562.

        Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  The Company’s goal is to increase the value of its properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.  For more information about Denbury, please visit www.denbury.com.

        This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties including estimated ranges for 2019 production, capital expenditures and free cash flow, and other risks and uncertainties detailed in the Company’s filings with the Securities and Exchange Commission, including Denbury’s most recent report on Form 10-K.  These risks and uncertainties are incorporated by this reference as though fully set forth herein.  These statements are based on engineering, geological, financial and operating assumptions that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met.  Actual results may vary materially.  In addition, any forward-looking statements represent the Company’s estimates only as of today and should not be relied upon as representing its estimates as of any future date.  Denbury assumes no obligation to update its forward-looking statements.

        No Offer or Solicitation

        This communication relates in part to a proposed business combination transaction (the “Transaction”) between Penn Virginia Corporation (“Penn Virginia”) and the Company.  This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law.  No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act.

        Additional Information and Where to Find It

        In connection with the Transaction, the Company has filed with the Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4 containing a joint proxy statement of the Company and Penn Virginia and a prospectus of the Company.  The Transaction will be submitted to the Company’s stockholders and Penn Virginia’s shareholders for their consideration.  The Company and Penn Virginia intend to file updates of certain information contained in the joint proxy statement/prospectus which is contained in the Form S-4, and may also file other documents with the SEC regarding the Transaction.  A definitive joint proxy statement/prospectus and any updating materials will be sent to the stockholders of the Company and the shareholders of Penn Virginia.  INVESTORS AND SECURITY HOLDERS OF THE COMPANY AND PENN VIRGINIA ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS AND ANY UPDATES OR SUPPLEMENTS THERETO REGARDING THE TRANSACTION, AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS.

        Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus and all other documents filed or that will be filed with the SEC by the Company or Penn Virginia through the website maintained by the SEC at www.sec.gov. Copies of documents filed with the SEC by the Company will be made available free of charge on the Company’s website at www.denbury.com or by directing a request to John Mayer, Director of Investor Relations, Denbury Resources Inc., 5320 Legacy Drive, Plano, TX 75024, Tel. No. (972) 673-2000. Copies of documents filed with the SEC by Penn Virginia will be made available free of charge on Penn Virginia’s website at www.pennvirginia.com, under the heading “SEC Filings,” or by directing a request to Investor Relations, Penn Virginia Corporation, 16285 Park Ten Place, Houston, TX 77084, Suite 500, Tel. No. (713) 722-6500.

        Participants in Solicitation

        The Company, Penn Virginia and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect to the Transaction.

        Information regarding the Company’s directors and executive officers is contained in the proxy statement for the Company’s 2018 Annual Meeting of Stockholders filed with the SEC on April 12, 2018, and certain of its Current Reports on Form 8-K.  You can obtain free copies of these documents at the SEC’s website at www.sec.gov or by accessing the Company’s website at www.denbury.com.  Information regarding Penn Virginia’s executive officers and directors is contained in the proxy statement for Penn Virginia’s 2018 Annual Meeting of Shareholders filed with the SEC on March 28, 2018, and certain of its Current Reports on Form 8-K. You can obtain free copies of these documents at the SEC’s website at www.sec.gov or by accessing Penn Virginia’s website at www.pennvirginia.com.

        Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction.  You may obtain free copies of this document as described above.

        Forward-Looking Statements and Cautionary Statements

        This communication contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements, other than statements of historical fact, included in this communication that address activities, events or developments that the Company or Penn Virginia expects, believes or anticipates will or may occur in the future are forward-looking statements, including estimated 2019 production, capital expenditures and other risks and uncertainties detailed in the Company’s filings with the Securities and Exchange Commission, including Denbury’s most recent report on Form 10-K. These risks and uncertainties are incorporated by this reference as though fully set forth herein. Words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “create,” “intend,” “could,” “may,” “foresee,” “plan,” “will,” “guidance,” “look,” “outlook,” “goal,” “future,” “assume,” “forecast,” “build,” “focus,” “work,” “continue” or the negative of such terms or other variations thereof and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. These forward-looking statements include, but are not limited to, statements regarding Penn Virginia and its properties, margins, EOR potential, or regarding the Transaction, pro forma descriptions of the combined company and its operations, growth, cash flows, integration and transition plans, synergies, opportunities and anticipated future performance. These statements are based on engineering, geological, financial and operating assumptions that Company and Penn Virginia management believes are reasonable based on currently available information; however, managements’ assumptions and the Company’s future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication. These include the expected timing and likelihood of completion of the Transaction, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Transaction that could reduce anticipated benefits or cause the parties to abandon the Transaction, the ability to successfully integrate the businesses, the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement, the possibility that stockholders of the Company may not approve the issuance of new shares of common stock in the Transaction or the amendment of the Company’s charter or that shareholders of Penn Virginia may not approve the merger agreement, the risk that the parties may not be able to satisfy the conditions to the Transaction in a timely manner or at all, the risk that pendency of the Transaction or announcements related thereto could have adverse effects on the market price of the Company’s common stock, the risk that the Transaction could have an adverse effect on the Company’s and Penn Virginia’s operating results and businesses generally, or cause them to incur substantial costs, the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected, the risk that the combined company may be unable to achieve synergies or it may take longer than expected to achieve those synergies and other important factors that could cause actual results to differ materially from those projected. All such factors are difficult to predict and are beyond the Company’s or Penn Virginia’s control, including those detailed in the Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on its website at www.denbury.com and on the SEC’s website at www.sec.gov, and those detailed in Penn Virginia’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on Penn Virginia’s website at www.pennvirginia.com and on the SEC’s website at www.sec.gov. All forward-looking statements are based on assumptions that the Company or Penn Virginia believe to be reasonable but that may not prove to be accurate. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company and Penn Virginia undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof.

        FINANCIAL AND STATISTICAL DATA TABLES AND RECONCILIATION SCHEDULES

        Following are unaudited financial highlights for the comparative three month and annual periods ended December 31, 2018 and 2017 and the three month period ended September 30, 2018.  All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.

        DENBURY RESOURCES INC.
        CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

        The following information is based on GAAP reported earnings, with additional required disclosures included in the Company’s Form 10-K:

        Quarter Ended Year Ended
        December 31, Sept. 30, December 31,
        In thousands, except per-share data 2018 2017 2018 2018 2017
        Revenues and other income
        Oil sales $ 324,337 $ 310,791 $ 377,329 $ 1,412,358 $ 1,079,703
        Natural gas sales 3,038 2,787 2,299 10,231 9,963
        CO2 sales and transportation fees 8,729 7,649 8,149 31,145 26,182
        Other income 2,251 5,362 7,196 19,891 13,938
        Total revenues and other income 338,355 326,589 394,973 1,473,625 1,129,786
        Expenses
        Lease operating expenses 128,453 104,873 122,527 489,720 447,799
        Marketing and plant operating expenses 13,602 12,062 12,427 50,002 51,820
        CO2 discovery and operating expenses 1,146 647 708 2,816 3,099
        Taxes other than income 22,773 24,359 27,344 104,670 87,207
        General and administrative expenses 10,272 20,503 21,579 71,495 101,806
        Interest, net of amounts capitalized of $10,262, $8,545, $9,514, $37,079 and $30,762, respectively 17,714 23,478 18,527 69,688 99,263
        Depletion, depreciation, and amortization 59,738 53,265 51,316 216,449 207,713
        Commodity derivatives expense (income) (210,688 ) 87,288 44,577 (21,087 ) 77,576
        Other expenses 72,700 7,003 1,933 79,941 7,003
        Total expenses 115,710 333,478 300,938 1,063,694 1,083,286
        Income (loss) before income taxes 222,645 (6,889 ) 94,035 409,931 46,500
        Income tax provision (benefit)
        Current income taxes (12,327 ) (2,045 ) (1,888 ) (16,001 ) (20,873 )
        Deferred income taxes 60,493 (131,625 ) 17,504 103,234 (95,779 )
        Net income $ 174,479 $ 126,781 $ 78,419 $ 322,698 $ 163,152
        Net income per common share
        Basic $ 0.39 $ 0.32 $ 0.17 $ 0.75 $ 0.42
        Diluted $ 0.38 $ 0.31 $ 0.17 $ 0.71 $ 0.41
        Weighted average common shares outstanding
        Basic 451,613 392,354 451,256 432,483 390,928
        Diluted 456,665 405,793 458,450 456,169 395,921

        DENBURY RESOURCES INC.
        SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

        Reconciliation of net income (GAAP measure) to adjusted net income (non-GAAP measure)

        Adjusted net income is a non-GAAP measure provided as a supplement to present an alternative net income measure which excludes expense and income items (and their related tax effects) not directly related to the Company’s ongoing operations.  Management believes that adjusted net income may be helpful to investors by eliminating the impact of noncash and/or special items not indicative of the Company’s performance from period to period, and is widely used by the investment community, while also being used by management, in evaluating the comparability of the Company’s ongoing operational results and trends.  Adjusted net income should not be considered in isolation, as a substitute for, or more meaningful than, net income or any other measure reported in accordance with GAAP, but rather to provide additional information useful in evaluating the Company’s operational trends and performance.

        Quarter Ended
        December 31, September 30,
        2018 2017 2018
        In thousands Amount Per Diluted Share Amount Per Diluted Share Amount Per Diluted Share
        Net income (GAAP measure) $ 174,479 $ 0.38 $ 126,781 $ 0.31 $ 78,419 $ 0.17
        Noncash fair value losses (gains) on commodity derivatives(1) (236,198 ) (0.52 ) 78,111 0.19 (17,034 ) (0.04 )
        Accrued expense related to litigation over a helium supply contract (included in other expenses)(2) 49,373 0.11 — — — —
        Impairment of loan receivable and related assets (included in other expenses)(3) 17,805 0.04 — — — —
        Acquisition transaction costs related to potential Penn Virginia transaction (included in other expenses) 4,373 0.01 — — — —
        Other(4) 1,300 0.00 3,251 0.01 1,497 0.00
        Estimated income taxes on above adjustments to net income and other discrete tax items(5) 35,282 0.08 (160,633 ) (0.39 ) (3,886 ) 0.00
        Adjusted net income (non-GAAP measure) $ 46,414 $ 0.10 $ 47,510 $ 0.12 $ 58,996 $ 0.13
        Year Ended
        December 31,
        2018 2017
        In thousands Amount Per Diluted Share Amount Per Diluted Share
        Net income (GAAP measure) $ 322,698 $ 0.71 $ 163,152 $ 0.41
        Noncash fair value losses (gains) on commodity derivatives(1) (196,335 ) (0.43 ) 29,781 0.08
        Accrued expense related to litigation over a helium supply contract (included in other expenses)(2) 49,373 0.11 — —
        Impairment of loan receivable and related assets (included in other expenses)(3) 17,805 0.04 — —
        Acquisition transaction costs related to potential Penn Virginia transaction (included in other expenses) 4,373 0.01 — —
        Severance-related payments included in general and administrative expenses(6) — — 6,807 0.02
        Other(4) 4,846 0.01 3,251 0.01
        Estimated income taxes on above adjustments to net income and other discrete tax items(5) 17,602 0.03 (147,541 ) (0.38 )
        Adjusted net income (non-GAAP measure) $ 220,362 $ 0.48 $ 55,450 $ 0.14

        (1) The net change between periods of the fair market values of open commodity derivative positions, excluding the impact of settlements on commodity derivatives during the period.
        (2) Expense associated with a trial court’s unfavorable ruling related to the non-delivery of helium volumes from the Company’s Riley Ridge Unit under a helium supply contract.  The accrual represents the aggregate cap of contractual liquidated damages the Company would be required to pay of $46 million, plus other costs associated with the settlement of approximately $3 million through December 31, 2018.
        (3) Impairment of an outstanding loan receivable and related assets related to the development of a proposed plant in the Gulf Coast that would potentially supply CO2 to Denbury, due to uncertainty that the project will achieve financial close.
        (4) Other adjustments include (a) $1 million of costs related to the Company’s land sales during the three months ended December 31, 2018, (b) a reduction in a contingent consideration liability related to a prior acquisition and transaction costs related to the Company’s privately negotiated debt exchanges during the three months and year ended December 31, 2017, (c) $2 million write-off of debt issuance costs associated with the Company’s reduction and extension of the senior secured bank credit facility and $1 million accrual for litigation matters, partially offset by a $1 million gain on land sales during the three months ended September 30, 2018, and (d) $3 million gain on land sales, offset by a similar amount of other expense accrued for litigation matters and $2 million of transaction costs related to the Company’s privately negotiated debt exchanges during the year ended December 31, 2018.
        (5) The estimated income tax impacts on adjustments to net income are generally computed based upon a statutory rate of 25% and 38% for 2018 and 2017, respectively, with the exception of (1) the tax impact of a (benefit) shortfall on the stock-based compensation deduction which totaled ($0.1) million, ($0.3) million and ($2) million during the three months ended December 31, 2018, December 30, 2017 and September 30, 2018, respectively, and ($2) million and $6 million for the years ended December 31, 2018 and 2017, respectively, and (2) tax benefits for enhanced oil recovery income tax credits of $5 million, $2 million and $5 million during for the three months ended December 31, 2018, December 31, 2017 and September 30, 2017, respectively, and $11 million and $11 million for the years ended December 31, 2018 and 2017.  In addition to these items, the Company recorded a one-time deferred tax benefit of $132 million reflecting the re-measurement of our deferred tax assets and liabilities resulting from the reduction of the federal income tax rate from 35% to 21% as enacted by the Tax Cut and Jobs Act, as well as valuation allowances totaling $6 million and $15 million during the three and twelve months ended December 31, 2017, respectively, all of which have been adjusted in this table.
        (6) Severance-related payments associated with the Company’s August-2017 workforce reduction.

        DENBURY RESOURCES INC.
        SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

        Reconciliation of cash flows from operations (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) to adjusted cash flows from operation less special items (non-GAAP measure) to adjusted cash flows from operations less special items and interest treated as debt reduction (non-GAAP measure) and free cash flow (deficit) (non-GAAP measure)

        Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows.  Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables.  Adjusted cash flows from operations less special items and adjusted cash flows from operations less special items and interest treated as debt reduction are additional non-GAAP measures that remove interest associated with the Company’s senior secured second lien notes and convertible senior notes not reflected as interest expense for financial reporting purposes and other special items.  Free cash flow is a non-GAAP measure that represents adjusted cash flows from operations less special items and interest treated as debt reduction items less development capital expenditures and capitalized interest but before acquisitions.  Management believes that it is important to consider these additional measures, along with cash flows from operations, as it believes the non-GAAP measures can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period.

        Quarter Ended Year Ended
        In thousands December 31, Sept. 30, December 31,
        2018 2017 2018 2018 2017
        Net income (GAAP measure) $ 174,479 $ 126,781 $ 78,419 $ 322,698 $ 163,152
        Adjustments to reconcile to adjusted cash flows from operations
        Depletion, depreciation, and amortization 59,738 53,265 51,316 216,449 207,713
        Deferred income taxes 60,493 (131,625 ) 17,504 103,234 (95,779 )
        Stock-based compensation 3,240 2,939 3,559 11,951 15,154
        Noncash fair value losses (gains) on commodity derivatives (236,198 ) 78,111 (17,034 ) (196,335 ) 29,781
        Other 3,607 4,614 753 1,521 9,303
        Adjusted cash flows from operations (non-GAAP measure)(1) 65,359 134,085 134,517 459,518 329,324
        Net change in assets and liabilities relating to operations 70,796 (9,801 ) 13,387 70,167 (62,181 )
        Cash flows from operations (GAAP measure) $ 136,155 $ 124,284 $ 147,904 $ 529,685 $ 267,143
        Adjusted cash flows from operations (non-GAAP measure)(1) $ 65,359 $ 134,085 $ 134,517 $ 459,518 $ 329,324
        Accrued expense related to litigation over a helium supply contract 49,373 — — 49,373 —
        Impairment of loan receivable and related assets 17,805 — — 17,805 —
        Adjusted cash flows from operations less special items (non-GAAP measure) $ 132,537 $ 134,085 $ 134,517 $ 526,696 $ 329,324
        Interest payments treated as debt reduction (21,262 ) (14,712 ) (21,186 ) (86,111 ) (52,473 )
        Adjusted cash flows from operations less special items and interest treated as debt reduction (non-GAAP measure) 111,275 119,373 113,331 440,585 276,851
        Development capital expenditures (107,451 ) (60,028 ) (85,999 ) (322,670 ) (240,826 )
        Capitalized interest (10,262 ) (8,545 ) (9,514 ) (37,079 ) (30,762 )
        Free cash flow (deficit) (non-GAAP measure) $ (6,438 ) $ 50,800 $ 17,818 $ 80,836 $ 5,263

        (1) For the year ended December 31, 2017, includes severance-related payments associated with the 2017 workforce reduction of approximately $7 million.

        DENBURY RESOURCES INC.
        SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

        Reconciliation of commodity derivatives income (expense) (GAAP measure) to noncash fair value gains (losses) on commodity derivatives (non-GAAP measure)

        Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represents only the net change between periods of the fair market values of open commodity derivative positions, and excludes the impact of settlements on commodity derivatives during the period.  Management believes that noncash fair value gains (losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” because the GAAP measure also includes settlements on commodity derivatives during the period; the non-GAAP measure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants.

        Quarter Ended Year Ended
        December 31, Sept. 30, December 31,
        In thousands 2018 2017 2018 2018 2017
        Payment on settlements of commodity derivatives $ (25,510 ) $ (9,177 ) $ (61,611 ) $ (175,248 ) $ (47,795 )
        Noncash fair value gains (losses) on commodity derivatives (non-GAAP measure) 236,198 (78,111 ) 17,034 196,335 (29,781 )
        Commodity derivatives income (expense) (GAAP measure) $ 210,688 $ (87,288 ) $ (44,577 ) $ 21,087 $ (77,576 )

        DENBURY RESOURCES INC.
        SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

        Reconciliation of net income (GAAP measure) to Adjusted EBITDAX (non-GAAP measure)

        Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not identical to) a financial covenant related to “Consolidated EBITDAX” in the Company’s senior secured bank credit facility, which excludes certain items that are included in net income, the most directly comparable GAAP financial measure.  Items excluded include interest, income taxes, depletion, depreciation, and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring.  Management believes Adjusted EBITDAX may be helpful to investors in order to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis.  It is also commonly used by third parties to assess the Company’s leverage and ability to incur and service debt and fund capital expenditures.  Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income, cash flows from operations, or any other measure reported in accordance with GAAP.  The Company’s Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX, EBITDAX, or EBITDA in the same manner.  The following table presents a reconciliation of our net income to Adjusted EBITDAX.

        Quarter Ended Year Ended
        In thousands December 31, Sept. 30, December 31,
        2018 2017 2018 2018 2017
        Net income (GAAP measure) $ 174,479 $ 126,781 $ 78,419 $ 322,698 $ 163,152
        Adjustments to reconcile to Adjusted EBITDAX
        Interest expense 17,714 23,478 18,527 69,688 99,263
        Income tax expense (benefit) 48,166 (133,670 ) 15,616 87,233 (116,652 )
        Depletion, depreciation, and amortization 59,738 53,265 51,316 216,449 207,713
        Noncash fair value losses (gains) on commodity derivatives (236,198 ) 78,111 (17,034 ) (196,335 ) 29,781
        Stock-based compensation 3,240 2,939 3,559 11,951 15,154
        Accrued expense related to litigation over a helium supply contract 49,373 — — 49,373 —
        Impairment of loan receivable and related assets 17,805 — — 17,805 —
        Noncash, non-recurring and other(1) 6,643 6,473 (2,155 ) 5,504 23,358
        Adjusted EBITDAX (non-GAAP measure) $ 140,960 $ 157,377 $ 148,248 $ 584,366 $ 421,769

        (1) Excludes pro forma adjustments related to qualified acquisitions or dispositions under the Company’s senior secured bank credit facility.

        DENBURY RESOURCES INC.
        SUPPLEMENTAL NON-GAAP FINANCIAL MEASURE (UNAUDITED)

        Reconciliation of the standardized measure of discounted estimated future net cash flows after income taxes (GAAP measure) to PV-10 Value (non-GAAP measure)

        PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  Denbury’s 2018 and 2017 year-end estimated proved oil and natural gas reserves and proved CO2 reserves quantities were prepared by the independent reservoir engineering firm of DeGolyer and MacNaughton.  The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  Management believes PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis.  Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties.  PV-10 Value is commonly used by management and others in the industry to evaluate properties that are bought and sold, to assess the potential return on investment in the Company’s oil and natural gas properties, and to perform impairment testing of oil and natural gas properties.  PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure.  PV-10 Value and the Standardized Measure do not purport to represent the fair value of the Company’s oil and natural gas reserves.

        December 31,
        In thousands 2018 2017
        Standardized Measure (GAAP measure) $ 3,351,385 $ 2,232,429
        Discounted estimated future income tax 673,756 301,369
        PV-10 Value (non-GAAP measure) $ 4,025,141 $ 2,533,798

        DENBURY RESOURCES INC.
        OPERATING HIGHLIGHTS (UNAUDITED)

        Quarter Ended Year Ended
        December 31, Sept. 30, December 31,
        2018 2017 2018 2018 2017
        Production (daily – net of royalties)
        Oil (barrels) 58,266 59,086 57,410 58,532 58,410
        Gas (mcf) 9,603 12,351 10,623 10,854 11,329
        BOE (6:1) 59,867 61,144 59,181 60,341 60,298
        Unit sales price (excluding derivative settlements)
        Oil (per barrel) $ 60.50 $ 57.17 $ 71.44 $ 66.11 $ 50.64
        Gas (per mcf) 3.44 2.45 2.35 2.58 2.41
        BOE (6:1) 59.44 55.74 69.73 64.59 49.51
        Unit sales price (including derivative settlements)
        Oil (per barrel) $ 55.75 $ 55.49 $ 59.78 $ 57.91 $ 48.40
        Gas (per mcf) 3.44 2.45 2.35 2.58 2.41
        BOE (6:1) 54.81 54.11 58.41 56.63 47.34
        NYMEX differentials
        Gulf Coast region
        Oil (per barrel) $ 5.34 $ 3.00 $ 3.21 $ 2.94 $ 0.22
        Gas (per mcf) 0.24 (0.04 ) 0.06 0.09 (0.04 )
        Rocky Mountain region
        Oil (per barrel) $ (4.31 ) $ (0.76 ) $ (0.54 ) $ (1.50 ) $ (1.39 )
        Gas (per mcf) (0.85 ) (0.86 ) (1.05 ) (1.06 ) (1.15 )
        Total company
        Oil (per barrel) $ 1.69 $ 1.70 $ 1.84 $ 1.30 $ (0.32 )
        Gas (per mcf) (0.29 ) (0.46 ) (0.51 ) (0.49 ) (0.61 )

        DENBURY RESOURCES INC.
        OPERATING HIGHLIGHTS (UNAUDITED)

        Quarter Ended Year Ended
        December 31, Sept. 30, December 31,
        Average Daily Volumes (BOE/d) (6:1) 2018 2017 2018 2018 2017
        Tertiary oil production
        Gulf Coast region
        Delhi 4,526 4,906 4,383 4,368 4,869
        Hastings 5,480 5,747 5,486 5,596 4,830
        Heidelberg 4,269 4,751 4,376 4,355 4,851
        Oyster Bayou 4,785 4,868 4,578 4,843 5,007
        Tinsley 5,033 6,241 5,294 5,530 6,430
        Other 375 7 240 205 13
        Mature properties(1) 6,748 6,763 6,612 6,702 7,078
        Total Gulf Coast region 31,216 33,283 30,969 31,599 33,078
        Rocky Mountain region
        Bell Creek 4,421 3,571 3,970 4,113 3,313
        Salt Creek 2,107 2,172 2,274 2,109 1,115
        Other 20 — 6 7 —
        Total Rocky Mountain region 6,548 5,743 6,250 6,229 4,428
        Total tertiary oil production 37,764 39,026 37,219 37,828 37,506
        Non-tertiary oil and gas production
        Gulf Coast region
        Mississippi 1,023 721 1,038 960 981
        Texas 4,319 4,617 4,533 4,546 4,493
        Other 457 472 421 424 478
        Total Gulf Coast region 5,799 5,810 5,992 5,930 5,952
        Rocky Mountain region
        Cedar Creek Anticline 14,961 14,302 14,208 14,837 14,754
        Other 1,343 1,533 1,409 1,431 1,537
        Total Rocky Mountain region 16,304 15,835 15,617 16,268 16,291
        Total non-tertiary production 22,103 21,645 21,609 22,198 22,243
        Total continuing production 59,867 60,671 58,828 60,026 59,749
        Property sale
        Lockhart Crossing(2) — 473 353 315 549
        Total production 59,867 61,144 59,181 60,341 60,298

        (1) Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields.
        (2) Includes production from Lockhart Crossing Field sold in the third quarter of 2018, the majority of which was previously included in ‘Mature properties’ in the Gulf Coast region.

        DENBURY RESOURCES INC.
        PER-BOE DATA (UNAUDITED)

        Quarter Ended Year Ended
        December 31, Sept. 30, December 31,
        2018 2017 2018 2018 2017
        Oil and natural gas revenues $ 59.44 $ 55.74 $ 69.73 $ 64.59 $ 49.51
        Payment on settlements of commodity derivatives (4.63 ) (1.63 ) (11.32 ) (7.96 ) (2.17 )
        Lease operating expenses (23.32 ) (18.64 ) (22.50 ) (22.24 ) (20.35 )
        Production and ad valorem taxes (3.78 ) (3.85 ) (4.66 ) (4.39 ) (3.60 )
        Marketing expenses, net of third-party purchases, and plant operating expenses (1.86 ) (1.75 ) (1.81 ) (1.78 ) (1.80 )
        Production netback 25.85 29.87 29.44 28.22 21.59
        CO2 sales, net of operating and exploration expenses 1.37 1.24 1.37 1.28 1.05
        General and administrative expenses (1.87 ) (3.64 ) (3.96 ) (3.25 ) (4.63 )
        Interest expense, net (3.22 ) (4.17 ) (3.40 ) (3.16 ) (4.51 )
        Other (10.26 ) 0.53 1.26 (2.23 ) 1.47
        Changes in assets and liabilities relating to operations 12.85 (1.74 ) 2.46 3.19 (2.83 )
        Cash flows from operations 24.72 22.09 27.17 24.05 12.14
        DD&A (10.85 ) (9.47 ) (9.43 ) (9.83 ) (9.44 )
        Deferred income taxes (10.98 ) 23.40 (3.21 ) (4.69 ) 4.35
        Noncash fair value gains (losses) on commodity derivatives 42.88 (13.89 ) 3.13 8.92 (1.35 )
        Other noncash items (14.09 ) 0.41 (3.26 ) (3.80 ) 1.71
        Net income $ 31.68 $ 22.54 $ 14.40 $ 14.65 $ 7.41

        CAPITAL EXPENDITURE SUMMARY (UNAUDITED)(1)

        Quarter Ended Year Ended
        December 31, Sept. 30, December 31,
        In thousands 2018 2017 2018 2018 2017
        Capital expenditures by project
        Tertiary oil fields $ 35,427 $ 30,661 $ 43,047 $ 142,560 $ 129,458
        Non-tertiary fields 53,097 12,624 18,975 104,811 53,647
        Capitalized internal costs(2) 12,572 14,884 11,280 46,599 52,616
        Oil and natural gas capital expenditures 101,096 58,169 73,302 293,970 235,721
        CO2 pipelines, sources and other 6,355 1,859 12,697 28,700 5,105
        Capital expenditures, before acquisitions and capitalized interest 107,451 60,028 85,999 322,670 240,826
        Acquisitions of oil and natural gas properties 391 (2,238 ) 129 541 88,777
        Capital expenditures, before capitalized interest 107,842 57,790 86,128 323,211 329,603
        Capitalized interest 10,262 8,545 9,514 37,079 30,762
        Capital expenditures, total $ 118,104 $ 66,335 $ 95,642 $ 360,290 $ 360,365

        (1) Capital expenditure amounts include accrued capital.
        (2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

        DENBURY RESOURCES INC.
        INTEREST AND FINANCING EXPENSES (UNAUDITED)

        Quarter Ended Year Ended
        December 31, Sept. 30, December 31,
        In thousands 2018 2017 2018 2018 2017
        Cash interest(1) $ 47,972 $ 45,345 $ 46,515 $ 186,632 $ 176,307
        Interest not reflected as expense for financial reporting purposes (1) (21,262 ) (14,712 ) (21,186 ) (86,111 ) (52,473 )
        Noncash interest expense 1,266 1,390 2,712 6,246 6,191
        Less: capitalized interest (10,262 ) (8,545 ) (9,514 ) (37,079 ) (30,762 )
        Interest expense, net $ 17,714 $ 23,478 $ 18,527 $ 69,688 $ 99,263

        (1) Cash interest is presented on an accrual basis and includes interest which is paid semiannually on the Company’s 9% Senior Secured Second Lien Notes due 2021, 9¼% Senior Secured Second Lien Notes due 2022, 5% Convertible Senior Notes due 2023, and 3½% Convertible Senior Notes due 2024, most of which is accounted for as a reduction of debt and therefore not reflected as interest for financial reporting purposes.

        SELECTED BALANCE SHEET AND CASH FLOW DATA (UNAUDITED)(1)

        December 31,
        In thousands 2018 2017
        Cash and cash equivalents $ 38,560 $ 58
        Total assets 4,723,222 4,471,299
        Borrowings under senior secured bank credit facility $ — $ 475,000
        Borrowings under senior secured second lien notes (principal only)(1) 1,520,587 996,487
        Borrowings under senior convertible notes (principal only)(1)(2) — 84,650
        Borrowings under senior subordinated notes (principal only) 826,185 1,000,527
        Financing and capital leases 185,435 218,727
        Total debt (principal only) $ 2,532,207 $ 2,775,391
        Total stockholders’ equity $ 1,141,777 $ 648,165

        (1) Excludes $250 million and $317 million of future interest payable on the notes as of December 31, 2018 and December 31, 2017, respectively, accounted for as debt for financial reporting purposes.
        (2) During the second quarter of 2018, all $85 million principal balance outstanding of the Company’s 3½% Convertible Senior Notes due 2024 and $59 million principal balance outstanding of the Company’s 5% Convertible Senior Notes due 2023 were converted into approximately 55 million shares of the Company’s common stock.

        https://globenewswire.com/news-release/2019/02/27/1743250/0/en/Denbury-Reports-2018-Fourth-Quarter-and-Full-Year-Results-Year-End-2018-Proved-Reserves-2019-Capital-Budget-and-Estimated-Production.html

        Year Ended
        December 31,
        In thousands 2018 2017
        Cash provided by (used in)
        Operating activities $ 529,685 $ 267,143
        Investing activities (333,276 ) (356,814 )
        Financing activities (157,452 ) 88,613

    • Oasis Petroleum Inc. Announces Quarter and Year Ending December 31, 2018 Earnings and Provides an Operational Update and 2019 Outlook

      mars 1, 2019

      • HOUSTON, Feb. 26, 2019 /PRNewswire/ — Oasis Petroleum Inc. (NYSE: OAS) (« Oasis » or the « Company ») today announced financial and operational results for the quarter and year ended December 31, 2018 and provided its 2019 outlook.

        Highlights

        • Increased production guidance twice in 2018, adjusted for divestitures. Production volumes averaged 88.3 thousand barrels of oil equivalent per day (« MBoepd ») (76.2% oil) in the fourth quarter of 2018, in-line with midpoint guidance. Production volumes averaged 82.5 MBoepd (76.5% oil) for the year ended December 31, 2018.
        • Lowered lease operating expenses (« LOE ») per barrels of oil equivalent (« Boe ») by over 12% year over year to $6.44 per Boe for the year ended December 31, 2018.
        • Completed and placed on production 121 gross (85.3 net) operated wells, including 114 gross (79.0 net) operated wells in the Williston Basin and 7 gross (6.3 net) operated wells in the Delaware Basin, while investing $942.2 million of exploration and production capital expenditures (« E&P CapEx »), which excludes acquisitions, other capital and midstream capital, during 2018.
        • Closed and integrated the acquisition of approximately 22,000 net core acres in the over-pressured oil window of the Delaware Basin (the « Permian Basin Acquisition »). Additionally, Oasis purchased adjacent acreage at attractive pricing, bringing its total position to over 23,000 net acres in the Delaware Basin.
        • Oasis’s midstream subsidiary, Oasis Midstream Partners LP (« OMP »), completed the construction and startup of a second natural gas plant in Wild Basin, making Oasis the second largest natural gas processor in North Dakota.
        • Successfully executed a divestiture « dropdown » of additional interests in midstream subsidiaries to OMP for $251.4 million, which increased Oasis’s holdings of OMP common units and reduced debt.
        • High-graded the portfolio since announcing the Permian Basin Acquisition including non-strategic divestitures of approximately $360 million, which helped reduce financial leverage.
        • Net cash provided by operating activities was $996.4 million for the year ended December 31, 2018 and $234.4 million for the fourth quarter of 2018. Adjusted EBITDA, a non-GAAP financial measure, was $958.7 million for the year ended December 31, 2018 and $214.1 million for the fourth quarter of 2018. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) including non-controlling interests and net cash provided by operating activities, see « Non-GAAP Financial Measures » below.

        « 2018 was a successful year for Oasis, » said Thomas B. Nusz, Oasis’s Chairman and Chief Executive Officer. « We focused on development of our core Williston asset, which drove full-year oil production up 20% vs. 2017, adjusted for the Delaware acquisitions and Bakken divestitures. Also in the Williston, OMP successfully started its new 200 million cubic feet per day plant in December which puts us in a great position to capture and realize the full value of our gas production in North Dakota. Separately, we continue to integrate our new Delaware asset and prepare for full-field development. Our technical learnings have validated the quality of this acreage, first year financial performance exceeded expectations, and we expect to realize exceptional returns and value creation in coming years. »

        « Additionally, throughout 2018 we high-graded our asset base through a series of non-core divestitures. Operationally, our team continues to do a tremendous job optimizing our cost structure. On the resource delineation side, in the Williston Basin, several strong well results at Painted Woods and Montana in the west and Cottonwood in the east heighten our confidence in the competitive position of these areas. At year-end 2018, Oasis had over 2,000 gross operated locations in the Williston and Delaware with breakeven pricing below $45 per barrel WTI. At our current completions pace, this represents over 20 years of development. While prices have weakened considerably since 2018, we have the asset quality, inventory depth, financial strength, midstream capabilities, and services to succeed at low prices. »

        « Oasis has an enviable asset base. We are in a formidable position to generate significant free cash flow in 2019 through prudent capital spending reductions and operating efficiencies. Free cash flow generation from the Williston is expected to fund growth at our core Delaware asset and reduce corporate debt. Consistent with our dedication to generating free cash flow, we entered into a capital expenditures arrangement with OMP for Bobcat DevCo’s 2019 expansion capital expenditures that permits us to minimize midstream spending at the Oasis level. We are poised to succeed in the current environment. Oasis has the strategic, operating, and financial capabilities to drive capital efficiency, generate strong free cash flow, and deliver for our shareholders. »

        Midstream Update

        OMP completed its new 200 MMscfpd natural gas processing plant in early December and has gradually ramped up volumes through February. OMP is now the second largest natural gas processor in the Williston Basin. OMP’s gas plant is currently running at approximately 60% utilization, and now expects utilization to increase to over 90% by year-end 2019 consisting of both Oasis and third-party volumes. In late 2018, OMP successfully signed additional third-party agreements, which diversifies the revenue base and provides financial resiliency. OMP continues to pursue additional opportunities with third-parties to further increase the utilization of its gas gathering and processing infrastructure.

        On February 22, 2019, Oasis entered into a capital expenditures arrangement (the « Capital Expenditures Arrangement ») with OMP, allowing OMP to fund growth capital for Bobcat DevCo. As a result of this arrangement, Oasis’s ownership in Bobcat DevCo is expected to decline from 75% to between approximately 64% and 66% by the end of the 2019 calendar year. The Company believes this arrangement is mutually beneficial to both Oasis and OMP, as it significantly reduces Oasis’s midstream spending and OMP can accretively increase its leverage to Bobcat DevCo. Additionally, in 2019, Oasis is planning capital expenditures related to its retained interest in Williston Basin infrastructure of approximately $11 million to $13 million and midstream capital expenditures of approximately $8 million in the Delaware Basin.

        The terms of the Capital Expenditures Arrangement were approved by the Board of Directors of the general partner of OMP following a unanimous recommendation for approval from the conflicts committee of the Board of Directors of the general partner of OMP, which consists entirely of independent directors. The conflicts committee was advised by Baird on financial matters and Richards, Layton & Finger, P.A. on legal matters. Oasis was advised by Vinson and Elkins L.L.P. on legal matters.

        2019 Plan

        Oasis constructed its 2019 plan based on being free cash flow positive at $50 WTI. In order to achieve this objective, the total E&P and Other CapEx plan has been reduced by approximately 40% year over year and is expected to range between $540 million and $560 million. Oasis is directing approximately 75% of its capital to the Williston Basin and approximately 25% to the Delaware Basin. The Company expects 85% of its E&P and Other CapEx to be invested in drilling and completions activities, including:

        • Completing approximately 70 gross operated wells with a working interest of approximately 65% in the Williston Basin;
        • Completing 9 to 11 gross operated wells with a working interest of approximately 90% in the Delaware Basin; and
        • Cash flow from the Williston asset is expected to fund a small Delaware outspend in 2019. Oasis produced 88.3 MBoepd in the fourth quarter of 2018, and expects first quarter production to be essentially flat quarter over quarter.

        Metric

        Range

        Production (Boepd)(1)

        Full Year 2019

        86,000 to 91,000

        Full Year Financial Metrics

        LOE ($ per Boe)

        $7.00 to $8.00

        Marketing, transportation and gathering (« MT&G ») ($ per Boe)(2)

        $1.50 to $3.50

        E&P Cash G&A ($ in millions)(3)

        $77 – $81

        Production taxes (% of oil and gas revenue)

        8.1% to 8.4%

        2019 CapEx Plan ($ in millions)

        E&P & Other CapEx(4)

        $540 – $560

        Midstream CapEx

        150 – 170

        Midstream CapEx attributable to Oasis (included in Midstream CapEx above)

        19 – 21

        __________________

        (1)

        Average oil production percentage of 72% in 2019.

        (2)

        Excludes the effect of non-cash valuation charges.

        (3)

        Cash E&P G&A represents general and administrative (« G&A ») expenses less non-cash equity-based compensation expense included in our exploration and production segment. Total cash G&A for Oasis estimated at $92 million to $96 million, which excludes non-cash amortization of equity-based compensation of approximately $41 million to $45 million. See « Non-GAAP Financial Measures » below.

        (4)

        Other CapEx includes OWS and administrative capital and excludes capitalized interest of approximately $15 million.

        Operational and Financial Update

        Select operational and financial statistics are included in the following table for the periods presented:

        Quarter Ended

        Year Ended

        12/31/2018

        9/30/2018

        12/31/2018

        12/31/2017

        Production data:

        Oil (Bopd)

        67,266

        65,870

        63,151

        51,557

        Natural gas (Mcfpd)

        126,135

        117,182

        116,246

        87,522

        Total production (Boepd)

        88,288

        85,400

        82,525

        66,144

        Percent Oil

        76.2

        %

        77.1

        %

        76.5

        %

        77.9

        %

        Average sales prices:

        Oil, without derivative settlements ($ per Bbl)

        $

        52.01

        $

        68.33

        $

        61.84

        $

        48.51

        Differential to WTI ($ per Bbl)

        6.79

        1.16

        2.88

        2.62

        Oil, with derivative settlements ($ per Bbl)(1)(2)

        44.14

        57.50

        52.65

        47.99

        Oil derivative settlements – net cash payments ($ in millions)(2)

        (48.7)

        (65.6)

        (211.7)

        (9.8)

        Natural gas, without derivative settlements ($ per Mcf)(3)

        4.27

        3.72

        3.88

        3.81

        Natural gas, with derivative settlements ($ per Mcf)(1)(2)(3)

        4.02

        3.76

        3.84

        3.86

        Natural gas derivative settlements – net cash receipts (payments) ($ in millions)(2)

        (2.9)

        0.4

        (1.8)

        1.5

        Selected financial data ($ in millions):

        Revenues:

        Oil revenues(4)

        $

        321.8

        $

        414.1

        $

        1,425.4

        $

        912.8

        Natural gas revenues

        49.6

        40.1

        164.6

        121.8

        Purchased oil and gas sales(4)

        183.1

        173.0

        551.8

        133.5

        Midstream revenues

        30.6

        31.2

        119.0

        72.8

        Well services revenues

        14.7

        16.3

        61.1

        52.8

        Total revenues

        $

        599.8

        $

        674.7

        $

        2,321.9

        $

        1,293.7

        Net cash provided by operating activities

        $

        234.4

        $

        230.0

        $

        996.4

        $

        507.9

        Adjusted EBITDA

        $

        214.1

        $

        270.4

        $

        958.7

        $

        707.7

        Select operating expenses:

        LOE

        $

        56.5

        $

        48.5

        $

        193.9

        $

        177.1

        Midstream operating expenses

        7.6

        8.7

        31.9

        17.6

        Well services operating expenses

        8.8

        11.4

        41.2

        37.2

        MT&G(5)

        28.9

        30.1

        102.9

        56.6

        Non-cash valuation charges

        3.8

        0.6

        4.3

        (0.8)

        Purchased oil and gas expenses(4)

        179.9

        174.3

        554.3

        134.6

        Production taxes

        29.9

        38.7

        133.7

        88.1

        Depreciation, depletion and amortization (« DD&A »)

        170.5

        163.0

        636.3

        530.8

        Total select operating expenses

        $

        485.9

        $

        475.3

        $

        1,698.5

        $

        1,041.2

        Select operating expenses data:

        LOE ($ per Boe)

        $

        6.95

        $

        6.18

        $

        6.44

        $

        7.34

        MT&G ($ per Boe)(5)

        3.55

        3.84

        3.41

        2.34

        DD&A ($ per Boe)

        20.99

        20.74

        21.12

        21.99

        E&P G&A ($ per Boe)

        3.08

        3.88

        3.40

        3.21

        E&P Cash G&A ($ per Boe)(6)

        2.18

        2.97

        2.48

        2.16

        Production taxes (% of oil and gas revenue)

        8.1

        %

        8.6

        %

        8.4

        %

        8.5

        %

        __________________

        (1)

        Realized prices include gains or losses on cash settlements for commodity derivatives, which do not qualify for or were not designated as hedging instruments for accounting purposes.

        (2)

        Cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

        (3)

        Natural gas prices include the value for natural gas and natural gas liquids.

        (4)

        For the quarter ended September 30, 2018 and the year ended December 31, 2017, oil revenues, purchased oil and gas sales and purchased oil and gas expenses have been revised as described in Revision of Prior Period Financial Statements below.

        (5)

        Excludes non-cash valuation charges on pipeline imbalances of $3.8 million and $0.6 million for the quarters ended December 31, 2018 and September 30, 2018, respectively, and $4.3 million and a credit of $0.8 million for the years ended December 31, 2018 and 2017, respectively.

        (6)

        Cash E&P G&A, a non-GAAP measure, represents G&A expenses less non-cash equity-based compensation expense included in the Company’s exploration and production segment. See « Non-GAAP Financial Measures » below for a reconciliation of the Company’s E&P G&A to Cash E&P G&A.

        G&A expenses for the fourth quarter of 2018 totaled $30.3 million, and for the year ended December 31, 2018, G&A totaled $121.3 million. Amortization of equity-based compensation, which is included in G&A expenses, was $7.7 million, or $0.95 per Boe, for the fourth quarter of 2018 and $29.3 million, or $0.97 per Boe, for the full year of 2018. G&A expenses for the Company’s E&P segment totaled $25.1 million for the fourth quarter of 2018 and $102.5 million for the full year of 2018. Total Cash E&P G&A expenses, excluding non-cash equity-based compensation expenses, were $2.18 per Boe for the fourth quarter of 2018 and $2.48 per Boe for the full year of 2018.

        Interest expense was $41.5 million for the fourth quarter of 2018 and $159.1 million for the full year of 2018. Capitalized interest totaled $4.0 million for the fourth quarter of 2018 and $17.2 million for the full year of 2018. Cash Interest (non-GAAP) totaled $40.5 million for the fourth quarter of 2018 and $157.6 million for the full year of 2018. For a definition of Cash Interest and a reconciliation of interest expense to Cash Interest, see « Non-GAAP Financial Measures » below.

        For the three months ended December 31, 2018, the Company recorded an income tax expense of $69.5 million, resulting in an effective tax rate of 23.5% as a percentage of its pre-tax income for the quarter. The Company’s income tax benefit for the year ended December 31, 2018 was recorded at $5.8 million, or 23.1% of its pre-tax loss.

        The Company reported net income attributable to Oasis of $222.0 million in the fourth quarter of 2018. For the full year of 2018, Oasis reported net loss attributable to Oasis of $35.3 million. Excluding certain non-cash items and their tax effect in the fourth quarter of 2018, Adjusted Net Loss Attributable to Oasis (non-GAAP) was $7.3 million, or $0.02 per diluted share, and in the full year of 2018, Adjusted Net Income Attributable to Oasis (non-GAAP) was $79.6 million, or $0.26 per diluted share, respectively. For a definition of Adjusted Net Income (Loss) Attributable to Oasis and a reconciliation of net income (loss) attributable to Oasis to Adjusted Net Income (Loss) Attributable to Oasis, see « Non-GAAP Financial Measures » below.

        The Company completed and placed on production 121 gross (85.3 net) operated wells during 2018 and 30 gross (21.7 net) operated wells during the fourth quarter of 2018.

        The Company sells a significant amount of its crude oil production through gathering systems connected to multiple pipeline and rail facilities, which allows it to shift volumes between pipeline and rail markets in order to optimize price realizations. For the first three quarters of 2018, the Company’s oil price differentials improved to less than $2.00 per barrel discount to WTI. Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased to optimize transportation costs or for blending at the Company’s crude oil terminal, increased $418.3 million to $551.8 million for the year ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due to higher volumes purchased and sold driven by increased market opportunities in the Williston Basin and in the Delaware Basin. Purchased oil and gas expenses increased $419.7 million to $554.3 million for the year ended December 31, 2018 as compared to December 31, 2017.

        Revision of Prior Period Financial Statements. In connection with the preparation of the Company’s consolidated financial statements for the year ended December 31, 2018, the Company identified errors in its previously issued 2017 annual consolidated financial statements and in each of the interim periods within 2018 and 2017. These prior period errors related to the presentation of certain crude oil purchase and sale arrangements. Specifically, although the Company previously presented the transactions on a net basis in oil and gas revenues, the Company was required to present these purchase and sale arrangements on a gross basis in purchased oil and gas expenses and purchased oil and gas sales. In addition, the Company identified certain assets and liabilities related to these arrangements that were reported on a net basis in accounts receivable on the balance sheet, but did not meet all of the criteria for a right of setoff. The correction of these errors had no effect on the reported consolidated net income (loss) attributable to Oasis or earnings (loss) attributable to Oasis per share data for the year ended December 31, 2017 or for any of the interim periods within 2018 and 2017 or to Oasis share of stockholders’ equity at December 31, 2017. Based on an analysis of quantitative and qualitative factors, the Company determined the related impact was not material to its consolidated financial statements, and therefore, amendments of previously filed reports are not required.

        For the quarter ended December 31, 2017, the Company revised the Consolidated Statements of Operations by increasing purchased oil and gas sales and purchased oil and gas expenses by $30.5 million and $30.4 million, respectively, and decreasing oil and gas revenues by $0.1 million. For the year ended December 31, 2017, the Company revised the Consolidated Statements of Operations by increasing purchased oil and gas sales and purchased oil and gas expenses by $45.6 million and $45.3 million, respectively, and decreasing oil and gas revenues by $0.3 million. For the quarter ended September 30, 2018, the Company revised the Consolidated Statements of Operations by increasing oil and gas revenues, purchased oil and gas sales and purchased oil and gas expenses by $1.6 million, $126.6 million and $128.2 million, respectively. As of December 31, 2017, the Company revised the Consolidated Balance Sheets by increasing both accounts receivable and accrued liabilities by $7.8 million. The amounts presented herein reflect the impact of this revision.

        As a result of the errors noted above, the Company has identified a material weakness in its internal control over financial reporting. Accordingly, management will disclose in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018 that its internal control over financial reporting and its disclosure controls and procedures are not effective as of December 31, 2018 and will receive an adverse opinion on internal control over financial reporting as of December 31, 2018 from PricewaterhouseCoopers LLP. In response to the material weakness identified, management has developed a plan to remediate the material weakness, and has begun working on that remediation plan. In addition, management performed additional analyses and procedures in order to conclude that the Company’s consolidated financial statements for the year ended December 31, 2018 are fairly presented, in all material respects, in accordance with generally accepted accounting principles.

        Capital Expenditures

        The following table depicts the Company’s CapEx for the year ended December 31, 2018:

        2018

        CapEx ($ in millions)

        E&P (excluding acquisitions)

        $

        942.2

        Well Services

        7.8

        Other(1)

        24.0

        Total CapEx before acquisitions and midstream

        974.0

        Midstream(2)

        277.6

        Total CapEx before acquisitions

        1,251.6

        Acquisitions

        951.9

        Total CapEx(3)

        $

        2,203.5

        __________________

        (1)

        Other CapEx includes such items as administrative capital and capitalized interest.

        (2)

        Midstream CapEx attributable to OMP was $116.6 million for the year ended December 31, 2018.

        (3)

        Total CapEx (including acquisitions) reflected in the table above differs from the amounts shown in the statements of cash flows in the Company’s consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for CapEx, while the amounts presented in the statements of cash flows are presented on a cash basis. In addition, for the year ended December 31, 2018, capital expenditures (including acquisitions) reflected in the table above includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition.

        Estimated Net Proved Reserves

        The Company’s estimated net proved reserves and related PV-10 are based on reports prepared by DeGolyer and MacNaughton, independent reserve engineers. The table below summarizes the Company’s estimated net proved reserves and related PV-10 at December 31, 2018:

        December 31, 2018

        Net Estimated Reserves
        (MMBoe)

        PV-10(1)

        (in millions)

        Proved Developed

        201.1

        $

        3,573.6

        Undeveloped

        119.4

        1,100.7

        Total Proved

        320.5

        $

        4,674.3

        __________________

        (1)

        PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows.

        Liquidity and Balance Sheet

        As of December 31, 2018, Oasis had cash and cash equivalents of $22.2 million, total elected commitments under the Oasis Credit Facility of $1,350.0 million and a borrowing base under the OMP Credit Facility of $400.0 million. In addition, Oasis had $468.0 million of borrowings and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility and $318.0 million of borrowings under the OMP Credit Facility, resulting in an unused borrowing base capacity of $950.0 million for both revolving credit facilities as of December 31, 2018.

        Hedging Activity

        The Company’s crude oil contracts will settle monthly based on the average NYMEX WTI for fixed price swaps and two-way and three-way costless collars. The Company’s basis swaps for crude oil will either settle monthly based on the fixed basis differential from NYMEX WTI to Intercontinental Exchange, Inc. Brent crude oil index price (« ICE Brent ») or Argus WTI Midland crude oil index price (« Midland ») to NYMEX WTI or Argus WTI Houston crude oil index price (« Houston« ) to NYMEX WTI. The Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (« NYMEX HH ») for fixed price swaps. The Company’s basis swaps for natural gas will settle monthly based on the fixed basis differential from Inside FERC Northern Natural Gas Ventura (« IF NNG Ventura ») to NYMEX HH. As of February 26, 2019, the Company had the following outstanding commodity derivative contracts:

        Three Months Ending

        Six Months Ending

        December 31, 2018

        June 30, 2019

        December 31, 2019

        June 30, 2020

        Crude oil (Volume in MBopd)

        Fixed Price Swaps

        Volume

        43.2

        13.0

        13.0

        —

        Price

        $

        53.95

        $

        53.47

        $

        53.47

        $

        —

        Collars

        Volume

        8.5

        13.0

        12.0

        —

        Floor

        $

        62.47

        $

        57.46

        $

        58.08

        $

        —

        Ceiling

        $

        68.40

        $

        74.49

        $

        76.05

        $

        —

        3-way

        Volume

        —

        12.0

        12.0

        3.0

        Sub-Floor

        $

        —

        $

        40.83

        $

        40.00

        $

        40.00

        Floor

        $

        —

        $

        51.25

        $

        51.57

        $

        57.24

        Ceiling

        $

        —

        $

        68.59

        $

        65.40

        $

        58.04

        Total Crude Oil Volume

        51.7

        38.0

        37.0

        3.0

        Basis Swaps (NYMEX WTI-ICE Brent)

        Volume

        2.0

        2.0

        —

        —

        Price

        $

        (9.68)

        $

        (9.68)

        $

        —

        $

        —

        Basis Swaps (Midland-NYMEX WTI)

        Volume

        1.3

        3.8

        —

        —

        Price

        $

        (7.50)

        $

        (6.77)

        $

        —

        $

        —

        Basis Swaps (Houston-NYMEX WTI)

        Volume

        —

        1.5

        1.5

        —

        Price

        $

        —

        $

        4.55

        $

        4.55

        $

        —

        Total Crude Oil Basis Volume

        3.3

        7.3

        1.5

        —

        Natural Gas (Volume in MMBtupd)

        Fixed Price Swaps

        Volume

        41,315

        30,475

        20,000

        —

        Price

        $

        3.03

        $

        3.20

        $

        2.90

        $

        —

        Total Natural Gas Volume

        41,315

        30,475

        20,000

        —

        Basis Swaps (IF NNG Ventura-NYMEX HH)

        Volume

        19,946

        26,630

        —

        —

        Price

        $

        0.01

        $

        0.05

        $

        —

        $

        —

        Total Natural Gas Basis Volume

        19,946

        26,630

        —

        —

        The December 2018 crude oil derivative contracts settled at a net $10.6 million received in January 2019 and will be included in the Company’s first quarter of 2019 derivative settlements.

        Conference Call Information

        Investors, analysts and other interested parties are invited to listen to the conference call:

        Date:

        Wednesday, February 27, 2019

        Time:

        10:00 a.m. Central Time

        Live Webcast:

        https://www.webcaster4.com/Webcast/Page/1052/29262

        OR:

        Dial-in:

        888-317-6003

        Intl. Dial in:

        412-317-6061

        Conference ID:

        8270035

        Website:

        www.oasispetroleum.com

        A recording of the conference call will be available beginning at 12:00 p.m. Central Time on the day of the call and will be available until Wednesday, March 6, 2019 by dialing:

        Replay dial-in:

        877-344-7529

        Intl. replay:

        412-317-0088

        Replay code:

        10128589

        The conference call will also be available for replay for approximately 30 days at www.oasispetroleum.com.

        Forward-Looking Statements

        This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company’s drilling program, production, derivatives activities, capital expenditure levels and other guidance included in this press release. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as the Company’s ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.

        Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

        About Oasis Petroleum Inc.

        Oasis is an independent exploration and production company focused on the acquisition and development of onshore, unconventional oil and natural gas resources in the United States. For more information, please visit the Company’s website at www.oasispetroleum.com.

        Oasis Petroleum Inc. Financial Statements

        OASIS PETROLEUM INC.

        CONSOLIDATED BALANCE SHEETS

        (Unaudited)

        December 31,

        2018

        2017

        (In thousands, except share data)

        ASSETS

        Current assets

        Cash and cash equivalents

        $

        22,190

        $

        16,720

        Accounts receivable, net

        387,602

        371,379

        Inventory

        33,128

        19,367

        Prepaid expenses

        10,997

        7,631

        Derivative instruments

        99,930

        344

        Intangible assets, net

        125

        —

        Other current assets

        183

        193

        Total current assets

        554,155

        415,634

        Property, plant and equipment

        Oil and gas properties (successful efforts method)

        8,912,189

        7,838,955

        Other property and equipment

        1,151,772

        868,746

        Less: accumulated depreciation, depletion, amortization and impairment

        (3,036,852)

        (2,534,215)

        Total property, plant and equipment, net

        7,027,109

        6,173,486

        Derivative instruments

        6,945

        9

        Long-term inventory

        12,260

        12,200

        Other assets

        25,673

        21,600

        Total assets

        $

        7,626,142

        $

        6,622,929

        LIABILITIES AND STOCKHOLDERS’ EQUITY

        Current liabilities

        Accounts payable

        $

        20,166

        $

        13,370

        Revenues and production taxes payable

        216,695

        213,995

        Accrued liabilities

        331,651

        244,279

        Accrued interest payable

        38,040

        38,963

        Derivative instruments

        84

        115,716

        Advances from joint interest partners

        5,140

        4,916

        Other current liabilities

        —

        40

        Total current liabilities

        611,776

        631,279

        Long-term debt

        2,735,276

        2,097,606

        Deferred income taxes

        300,055

        305,921

        Asset retirement obligations

        52,384

        48,511

        Derivative instruments

        20

        19,851

        Other liabilities

        7,751

        6,182

        Total liabilities

        3,707,262

        3,109,350

        Commitments and contingencies

        Stockholders’ equity

        Common stock, $0.01 par value: 900,000,000 and 450,000,000 shares authorized at December 31, 2018 and December 31, 2017, respectively; 320,469,049 shares issued and 318,377,161 shares outstanding at December 31, 2018 and 270,627,014 shares issued and 269,295,466 shares outstanding at December 31, 2017

        3,157

        2,668

        Treasury stock, at cost: 2,091,888 and 1,331,548 shares at December 31, 2018 and December 31, 2017, respectively

        (29,025)

        (22,179)

        Additional paid-in capital

        3,077,755

        2,677,217

        Retained earnings

        682,689

        717,985

        Oasis share of stockholders’ equity

        3,734,576

        3,375,691

        Non-controlling interests

        184,304

        137,888

        Total stockholders’ equity

        3,918,880

        3,513,579

        Total liabilities and stockholders’ equity

        $

        7,626,142

        $

        6,622,929

         

        OASIS PETROLEUM INC.

        CONSOLIDATED STATEMENTS OF OPERATIONS

        (Unaudited)

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        (In thousands, except per share data)

        Revenues

        Oil and gas revenues

        $

        371,385

        $

        330,290

        $

        1,590,024

        $

        1,034,634

        Purchased oil and gas sales

        183,050

        61,547

        551,808

        133,542

        Midstream revenues

        30,589

        23,813

        119,040

        72,752

        Well services revenues

        14,731

        19,225

        61,075

        52,791

        Total revenues

        599,755

        434,875

        2,321,947

        1,293,719

        Operating expenses

        Lease operating expenses

        56,456

        43,263

        193,912

        177,134

        Midstream operating expenses

        7,587

        6,698

        31,912

        17,589

        Well services operating expenses

        8,848

        13,370

        41,200

        37,228

        Marketing, transportation and gathering expenses

        32,634

        17,722

        107,193

        55,740

        Purchased oil and gas expenses

        179,865

        62,043

        554,307

        134,615

        Production taxes

        29,948

        27,811

        133,696

        88,133

        Depreciation, depletion and amortization

        170,477

        146,556

        636,296

        530,802

        Exploration expenses

        3,731

        7,590

        27,432

        11,600

        Impairment

        —

        866

        384,228

        6,887

        General and administrative expenses

        30,317

        24,627

        121,346

        91,797

        Total operating expenses

        519,863

        350,546

        2,231,522

        1,151,525

        Gain (loss) on sale of properties

        (10,236)

        1,774

        28,587

        1,774

        Operating income

        69,656

        86,103

        119,012

        143,968

        Other income (expense)

        Net gain (loss) on derivative instruments

        268,402

        (123,954)

        28,457

        (71,657)

        Interest expense, net of capitalized interest

        (41,469)

        (36,289)

        (159,085)

        (146,837)

        Loss on extinguishment of debt

        (150)

        —

        (13,848)

        —

        Other income (expense)

        (25)

        (577)

        121

        (1,332)

        Total other income (expense)

        226,758

        (160,820)

        (144,355)

        (219,826)

        Income (loss) before income taxes

        296,414

        (74,717)

        (25,343)

        (75,858)

        Income tax benefit (expense)

        (69,548)

        202,834

        5,843

        203,304

        Net income (loss) including non-controlling interests

        226,866

        128,117

        (19,500)

        127,446

        Less: Net income attributable to non-controlling interests

        4,889

        3,500

        15,796

        3,650

        Net income (loss) attributable to Oasis

        $

        221,977

        $

        124,617

        $

        (35,296)

        $

        123,796

        Earnings (loss) per share:

        Basic

        $

        0.71

        $

        0.52

        $

        (0.11)

        $

        0.53

        Diluted

        0.70

        0.52

        (0.11)

        0.52

        Weighted average shares outstanding:

        Basic

        313,260

        240,143

        307,480

        234,986

        Diluted

        315,098

        241,960

        307,480

        237,875

         

        OASIS PETROLEUM INC.

        SELECTED FINANCIAL AND OPERATIONAL STATS

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        Operating results ($ in thousands):

        Revenues

        Oil revenues(1)

        $

        321,834

        $

        289,392

        $

        1,425,409

        $

        912,806

        Natural gas revenues

        49,551

        40,898

        164,615

        121,828

        Purchased oil and gas sales(1)

        183,050

        61,547

        551,808

        133,542

        Midstream revenues

        30,589

        23,813

        119,040

        72,752

        Well services revenues

        14,731

        19,225

        61,075

        52,791

        Total revenues

        $

        599,755

        $

        434,875

        $

        2,321,947

        $

        1,293,719

        Production data:

        Oil (MBbls)

        6,188

        5,266

        23,050

        18,818

        Natural gas (MMcf)

        11,604

        8,815

        42,430

        31,946

        Oil equivalents (MBoe)

        8,122

        6,735

        30,122

        24,143

        Average daily production (Boepd)

        88,288

        73,207

        82,525

        66,144

        Average sales prices:

        Oil, without derivative settlements (per Bbl)

        $

        52.01

        $

        54.95

        $

        61.84

        $

        48.51

        Oil, with derivative settlements (per Bbl)(2)

        44.14

        53.40

        52.65

        47.99

        Natural gas, without derivative settlements (per Mcf)(3)

        4.27

        4.64

        3.88

        3.81

        Natural gas, with derivative settlements (per Mcf)(2)(3)

        4.02

        4.72

        3.84

        3.86

        Costs and expenses (per Boe of production):

        Lease operating expenses

        $

        6.95

        $

        6.42

        $

        6.44

        $

        7.34

        Marketing, transportation and gathering expenses(4)

        3.55

        2.83

        3.41

        2.34

        Production taxes

        3.69

        4.13

        4.44

        3.65

        Depreciation, depletion and amortization

        20.99

        21.76

        21.12

        21.99

        General and administrative expenses

        3.73

        3.66

        4.03

        3.80

        __________________

        (1)

        For the quarter and year ended December 31, 2017, oil revenues, purchased oil and gas sales and purchased oil and gas expenses have been revised. Refer to Revision of Prior Period Financial Statements for further details.

        (2)

        Realized prices include gains or losses on cash settlements for commodity derivatives, which do not qualify for or were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

        (3)

        Natural gas prices include the value for natural gas and natural gas liquids.

        (4)

        Excludes non-cash valuation charges on pipeline imbalances.

         

        OASIS PETROLEUM INC.

        CONSOLIDATED STATEMENTS OF CASH FLOWS

        (Unaudited)

        Year Ended December 31,

        2018

        2017

        (In thousands)

        Cash flows from operating activities:

        Net income (loss) including non-controlling interests

        $

        (19,500)

        $

        127,446

        Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities:

        Depreciation, depletion and amortization

        636,296

        530,802

        Loss on extinguishment of debt

        13,848

        —

        Gain on sale of properties

        (28,587)

        (1,774)

        Impairment

        384,228

        6,887

        Deferred income taxes

        (5,866)

        (202,884)

        Derivative instruments

        (28,457)

        71,657

        Equity-based compensation expenses

        29,273

        26,534

        Deferred financing costs amortization and other

        29,057

        18,311

        Working capital and other changes:

        Change in accounts receivable, net

        (23,508)

        (166,386)

        Change in inventory

        (14,346)

        (2,501)

        Change in prepaid expenses

        (2,354)

        (838)

        Change in other current assets

        10

        148

        Change in long-term inventory and other assets

        (144)

        (12,143)

        Change in accounts payable, interest payable and accrued liabilities

        26,116

        123,107

        Change in other current liabilities

        (40)

        (10,450)

        Change in other liabilities

        395

        (40)

        Net cash provided by operating activities

        996,421

        507,876

        Cash flows from investing activities:

        Capital expenditures

        (1,148,961)

        (647,349)

        Acquisitions

        (581,650)

        (61,874)

        Proceeds from sale of properties

        333,229

        5,774

        Costs related to sale of properties

        (2,850)

        (366)

        Derivative settlements

        (213,528)

        (8,264)

        Advances from joint interest partners

        224

        (2,681)

        Net cash used in investing activities

        (1,613,536)

        (714,760)

        Cash flows from financing activities:

        Proceeds from Revolving Credit Facilities

        3,224,000

        1,162,000

        Principal payments on Revolving Credit Facilities

        (2,586,000)

        (1,377,000)

        Repurchase of senior unsecured notes

        (423,340)

        —

        Proceeds from issuance of senior unsecured notes

        400,000

        —

        Deferred financing costs

        (13,862)

        (2,714)

        Proceeds from sale of common stock, net of offering costs

        —

        302,191

        Proceeds from sale of Oasis Midstream common units, net of offering costs

        44,503

        134,185

        Purchases of treasury stock

        (6,846)

        (6,229)

        Distributions to non-controlling interests

        (14,114)

        —

        Other

        (1,756)

        (55)

        Net cash provided by financing activities

        622,585

        212,378

        Increase in cash and cash equivalents

        5,470

        5,494

        Cash and cash equivalents:

        Beginning of period

        16,720

        11,226

        End of period

        $

        22,190

        $

        16,720

        Supplemental cash flow information:

        Cash paid for interest, net of capitalized interest

        $

        141,196

        $

        129,463

        Cash paid for income taxes

        38

        12

        Cash received for income tax refunds

        25

        281

        Supplemental non-cash transactions:

        Change in accrued capital expenditures

        $

        68,946

        $

        83,508

        Change in asset retirement obligations

        3,880

        (789)

        Installment notes from acquisition

        —

        4,875

        Issuance of shares in connection with the Permian Basin Acquisition

        371,220

        —

        Non-GAAP Financial Measures

        E&P Cash G&A Reconciliation

        E&P Cash G&A is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines E&P Cash G&A as the total general and administrative expenses included in our exploration and production segment less non-cash equity-based compensation expense included in our exploration and production segment. E&P Cash G&A is not a measure of general and administrative expenses as determined by United States generally accepted accounting principles, or GAAP.

        The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses included in our exploration and production segment to the non-GAAP financial measure of E&P Cash G&A for the periods presented:

        Exploration and Production

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        (In thousands)

        General and administrative expenses

        $

        25,057

        $

        19,739

        $

        102,482

        $

        77,560

        Equity-based compensation expenses

        (7,345)

        (5,695)

        (27,910)

        (25,436)

        E&P Cash G&A

        $

        17,712

        $

        14,044

        $

        74,572

        $

        52,124

        Cash Interest Reconciliation

        Cash Interest is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP.

        The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented:

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        (In thousands)

        Interest expense

        $

        41,469

        $

        36,289

        $

        159,085

        $

        146,837

        Capitalized interest

        4,017

        4,024

        17,226

        12,797

        Amortization of deferred financing costs

        (2,079)

        (1,779)

        (7,590)

        (6,907)

        Amortization of debt discount

        (2,919)

        (2,654)

        (11,120)

        (10,080)

        Cash Interest

        $

        40,488

        $

        35,880

        $

        157,601

        $

        142,647

        Adjusted EBITDA and Free Cash Flow Reconciliations

        Adjusted EBITDA and Free Cash Flow are supplemental non-GAAP financial measures that are used by management and external users of the Company’s financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion, amortization, exploration expenses and other similar non-cash or non-recurring charges. The Company defines Free Cash Flow as Adjusted EBITDA less Cash Interest and CapEx, excluding capitalized interest. Adjusted EBITDA and Free Cash Flow are not measures of net income (loss) or cash flows as determined by GAAP.

        The following table presents reconciliations of the GAAP financial measures of net income (loss) including non-controlling interests and net cash provided by (used in) operating activities to the non-GAAP financial measures of Adjusted EBITDA and Free Cash Flow for the periods presented:

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        (In thousands)

        Net income (loss) including non-controlling interests

        $

        226,866

        $

        128,117

        $

        (19,500)

        $

        127,446

        (Gain) loss on sale of properties

        10,236

        (1,774)

        (28,587)

        (1,774)

        Loss on extinguishment of debt

        150

        —

        13,848

        —

        Net (gain) loss on derivative instruments

        (268,402)

        123,954

        (28,457)

        71,657

        Derivative settlements(1)

        (51,515)

        (7,460)

        (213,528)

        (8,264)

        Interest expense, net of capitalized interest

        41,469

        36,289

        159,085

        146,837

        Depreciation, depletion and amortization

        170,477

        146,556

        636,296

        530,802

        Impairment

        —

        866

        384,228

        6,887

        Exploration expenses

        3,731

        7,590

        27,432

        11,600

        Equity-based compensation expenses

        7,687

        6,083

        29,273

        26,534

        Income tax (benefit) expense

        69,548

        (202,834)

        (5,843)

        (203,304)

        Other non-cash adjustments

        3,878

        (1,236)

        4,435

        (745)

        Adjusted EBITDA

        214,125

        236,151

        958,682

        707,676

        Adjusted EBITDA attributable to non-controlling interests

        7,094

        3,714

        21,703

        3,904

        Adjusted EBITDA attributable to Oasis

        207,031

        232,437

        936,979

        703,772

        Cash Interest

        (40,488)

        (35,880)

        (157,601)

        (142,647)

        Capital expenditures(2)

        (305,348)

        (313,060)

        (2,203,453)

        (836,204)

        Capitalized interest

        4,017

        4,024

        17,226

        12,797

        Free Cash Flow

        $

        (134,788)

        $

        (112,479)

        $

        (1,406,849)

        $

        (262,282)

        Net cash provided by operating activities

        $

        234,420

        $

        209,139

        $

        996,421

        $

        507,876

        Derivative settlements(1)

        (51,515)

        (7,460)

        (213,528)

        (8,264)

        Interest expense, net of capitalized interest

        41,469

        36,289

        159,085

        146,837

        Exploration expenses

        3,731

        7,590

        27,432

        11,600

        Deferred financing costs amortization and other

        (8,983)

        (5,645)

        (29,057)

        (18,311)

        Current tax expense

        (4)

        (421)

        23

        (421)

        Changes in working capital

        (8,871)

        (2,105)

        13,871

        69,104

        Other non-cash adjustments

        3,878

        (1,236)

        4,435

        (745)

        Adjusted EBITDA

        214,125

        236,151

        958,682

        707,676

        Adjusted EBITDA attributable to non-controlling interests

        7,094

        3,714

        21,703

        3,904

        Adjusted EBITDA attributable to Oasis

        207,031

        232,437

        936,979

        703,772

        Cash Interest

        (40,488)

        (35,880)

        (157,601)

        (142,647)

        Capital expenditures(2)

        (305,348)

        (313,060)

        (2,203,453)

        (836,204)

        Capitalized interest

        4,017

        4,024

        17,226

        12,797

        Free Cash Flow

        $

        (134,788)

        $

        (112,479)

        $

        (1,406,849)

        $

        (262,282)

        ____________________

        (1)

        Cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

        (2)

        CapEx (including acquisitions) reflected in the table above differs from the amounts shown in the statement of cash flows in the Company’s consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis. Acquisitions totaled $1.8 million and $951.9 million for the fourth quarter and full year 2018, respectively, and $48.2 million and $54.0 million for the fourth quarter and full year 2017, respectively. Additionally, CapEx (including acquisitions) reflected in the table includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition for the year ended December 31, 2018.

        Segment Adjusted EBITDA Reconciliations

        The following tables present reconciliations of the GAAP financial measure of income (loss) before income taxes including non-controlling interests to the non-GAAP financial measure of Adjusted EBITDA for the Company’s three reportable business segments on a gross basis for the periods presented:

        Exploration and Production

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        (In thousands)

        Income (loss) before income taxes including non-controlling interests

        $

        256,177

        $

        (107,130)

        $

        (167,292)

        $

        (179,129)

        (Gain) loss on sale of properties

        10,226

        (1,774)

        (38,188)

        (1,774)

        Loss on extinguishment of debt

        150

        —

        13,848

        —

        Net (gain) loss on derivative instruments

        (268,402)

        123,954

        (28,457)

        71,657

        Derivative settlements(1)

        (51,515)

        (7,460)

        (213,528)

        (8,264)

        Interest expense, net of capitalized interest

        39,734

        36,289

        156,742

        146,818

        Depreciation, depletion and amortization

        165,319

        143,033

        618,402

        519,853

        Impairment

        —

        866

        384,228

        6,887

        Exploration expenses

        3,731

        7,590

        27,432

        11,600

        Equity-based compensation expenses

        7,345

        5,695

        27,910

        25,436

        Other non-cash adjustments

        3,774

        (1,303)

        4,331

        (812)

        Adjusted EBITDA

        $

        166,539

        $

        199,760

        $

        785,428

        $

        592,272

        ____________________

        (1)

        Cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

         

        Midstream Services

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        (In thousands)

        Income before income taxes including non-controlling interests

        $

        40,248

        $

        33,294

        $

        141,001

        $

        102,340

        Loss on sale of properties

        31

        —

        9,622

        —

        Interest expense, net of capitalized interest

        1,735

        —

        2,343

        19

        Depreciation, depletion and amortization

        8,380

        4,625

        29,282

        15,999

        Equity-based compensation expenses

        325

        357

        1,547

        1,461

        Other non-cash adjustments

        —

        —

        —

        —

        Adjusted EBITDA

        $

        50,719

        $

        38,276

        $

        183,795

        $

        119,819

         

        Well Services

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        (In thousands)

        Income before income taxes including non-controlling interests

        $

        5,708

        $

        5,897

        $

        31,023

        $

        15,091

        Depreciation, depletion and amortization

        4,138

        3,522

        15,698

        12,939

        Equity-based compensation expenses

        439

        249

        1,588

        1,264

        Other non-cash adjustments

        104

        67

        104

        67

        Adjusted EBITDA

        $

        10,389

        $

        9,735

        $

        48,413

        $

        29,361

        Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share

        Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share are supplemental non-GAAP financial measures that are used by management and external users of the Company’s financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted Net Income (Loss) Attributable to Oasis as net income (loss) after adjusting for (1) the impact of certain non-cash and non-recurring items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash and non-recurring charges, (2) the impact of net income attributable to non-controlling interests and (3) the non-cash and non-recurring items’ impact on taxes based on the Company’s effective tax rate applicable to those adjusting items, excluding net income attributable to non-controlling interests, in the same period. Adjusted Net Income (Loss) Attributable to Oasis is not a measure of net income (loss) as determined by GAAP. The Company defines Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share as Adjusted Net Income (Loss) Attributable to Oasis divided by diluted weighted average shares outstanding. Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share is not a measure of diluted earnings (loss) as determined by GAAP.

        The following table presents reconciliations of the GAAP financial measure of net income (loss) attributable to Oasis to the non-GAAP financial measure of Adjusted Net Income (Loss) Attributable to Oasis and the GAAP financial measure of diluted earnings (loss) attributable to Oasis per share to the non-GAAP financial measure of Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share for the periods presented:

        Three Months Ended December 31,

        Year Ended December 31,

        2018

        2017

        2018

        2017

        (In thousands, except per share data)

        Net income (loss) attributable to Oasis

        $

        221,977

        $

        124,617

        $

        (35,296)

        $

        123,796

        Tax reform rate change adjustments

        —

        (171,900)

        —

        (171,900)

        (Gain) loss on sale of properties

        10,236

        (1,774)

        (28,587)

        (1,774)

        Loss on extinguishment of debt

        150

        —

        13,848

        —

        Net (gain) loss on derivative instruments

        (268,402)

        123,954

        (28,457)

        71,657

        Derivative settlements(1)

        (51,515)

        (7,460)

        (213,528)

        (8,264)

        Impairment

        —

        866

        384,228

        6,887

        Amortization of deferred financing costs

        2,079

        1,779

        7,591

        6,907

        Amortization of debt discount

        2,919

        2,654

        11,120

        10,080

        Other non-cash adjustments

        3,878

        (1,236)

        4,435

        (745)

        Tax impact(2)

        71,365

        (44,425)

        (35,759)

        (31,696)

        Adjusted Net Income (Loss) Attributable to Oasis

        $

        (7,313)

        $

        27,075

        $

        79,595

        $

        4,948

        Diluted earnings (loss) attributable to Oasis per share

        $

        0.70

        $

        0.52

        $

        (0.11)

        $

        0.52

        Tax reform rate change adjustments

        —

        (0.71)

        —

        (0.72)

        (Gain) loss on sale of properties

        0.03

        (0.01)

        (0.09)

        (0.01)

        Loss on extinguishment of debt

        —

        —

        0.04

        —

        Net (gain) loss on derivative instruments

        (0.85)

        0.51

        (0.09)

        0.30

        Derivative settlements(1)

        (0.16)

        (0.03)

        (0.69)

        (0.03)

        Impairment

        —

        —

        1.24

        0.03

        Amortization of deferred financing costs

        0.01

        0.01

        0.02

        0.03

        Amortization of debt discount

        0.01

        0.01

        0.04

        0.04

        Other non-cash adjustments

        0.01

        (0.01)

        0.01

        —

        Tax impact(2)

        0.23

        (0.17)

        (0.11)

        (0.14)

        Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share

        $

        (0.02)

        $

        0.12

        $

        0.26

        $

        0.02

        Diluted weighted average shares outstanding(3)

        313,260

        241,960

        310,860

        237,875

        Effective tax rate applicable to adjustment items

        23.7

        %

        37.4

        %

        23.7

        %

        37.4

        %

        ____________________

        (1)

        Cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

        (2)

        The tax impact is computed utilizing the Company’s effective tax rate applicable to the adjustments for certain non-cash and non-recurring items. The tax impact was not computed for the tax reform rate change adjustments.

        (3)

        The Company included 3,379,000 of unvested stock awards for the year ended December 31, 2018 and 1,817,513 and 2,889,000 of unvested stock awards for the three months ended and the year ended December 31, 2017, respectively, in computing Adjusted Diluted Income Attributable to Oasis Per Share due to the dilutive effect under the treasury stock method. No unvested stock awards were included in computing Adjusted Diluted Loss Attributable to Oasis Per Share for the three months ended December 31, 2018 because the effect was anti-dilutive due to Adjusted Net Loss Attributable to Oasis.

         

        Cision View original content:http://www.prnewswire.com/news-releases/oasis-petroleum-inc-announces-quarter-and-year-ending-december-31-2018-earnings-and-provides-an-operational-update-and-2019-outlook-300802735.html

        SOURCE Oasis Petroleum Inc.

    • Callon Petroleum Company Announces Fourth Quarter 2018 Results

      mars 1, 2019

      • HOUSTON, Feb. 26, 2019 /PRNewswire/ — Callon Petroleum Company (NYSE: CPE) (« Callon » or the « Company ») today reported results of operations for the three months and full-year ended December 31, 2018.

        Presentation slides accompanying this earnings release are available on the Company’s website at www.callon.com located on the « Presentations » page within the Investors section of the site.

        2018 Highlights

        • Full-year 2018 production of 32.9 Mboe/d (79% oil), an increase of 44% over 2017 volumes and at the top of the 2018 guidance range with a higher oil cut
        • Year-end proved reserves of 238.5 MMboe (76% oil), a year-over-year increase of 74% combined with an oil content that has remained consistently over 75% since commencing horizontal development in 2012
        • Proved reserve additions replaced 690% of 2018 production at a « drill-bit » finding and development cost (i) of $7.03 per Boe and a proved developed finding and development cost(i) of $13.40 per Boe
        • Generated an operating margin of $40.16 per Boe reflecting our high level of oil volumes, proactive investments in infrastructure and offtake relationships, and cost structure improvements
        • Realized net income of $300.4 million and generated Adjusted EBITDA(i) of $432.5 million relative to cash drilling and completion capital expenditures of $403.5 million
        • Completed the acquisition of 34,523 net working interest acres and 1,530 net mineral acres within our core operating areas, more than doubling our Delaware footprint since 2017, and also traded 4,420 net acres to further long-lateral development
        • Divested 3,540 net acres as part of ongoing initiatives to monetize non-core assets and enhance returns on capital
        • Executed firm transportation and marketing agreements that are expected to transition 25 MBbl/d of our gross oil production to a combination of Gulf Coast, Brent and waterborne pricing January 2020

        Fourth Quarter 2018 Highlights

        • Fourth quarter 2018 production of 41.1 Mboe/d (81% oil), an increase of 55% over fourth quarter 2017 volumes and a sequential increase of 18%
        • Generated $151.6 million of cash provided by operating activities, exceeding cash used in investing activities for operational capital additions of $127.8 million in the development of oil and natural gas properties
        • Began building an inventory of drilled, uncompleted wells to support our transition to larger scale development in the Delaware Basin in 2019

        Joe Gatto, President and Chief Executive Officer commented, « The past year represented a significant inflection point in the maturity of our Permian operations and progression to a development model that will drive increased capital efficiency and corporate returns. The critical steps we took this past year will assist in our transition to full-field development, employing larger pad concepts as part of an integrated technical and operational approach to multi-zone resource monetization. We enter 2019 with a substantial proved reserve base approaching 250 million BOE that has consistently carried one of the highest percentages of oil across our peer group since we commenced horizontal development. As part of the maturation of our business, our corporate decline rates have also moderated over the last few years, setting the stage for decreasing capital intensity as more capital will contribute to incremental production growth and less capital will be needed for replacement. This dynamic, combined with the impact of larger scale program development in the Delaware Basin that will emerge around mid-year, provides a solid foundation for quality growth in 2019 and beyond. » He continued, « As the industry landscape evolves, operators are faced with the choice of pursuing short-term benefits at the expense of future reinvestment opportunities, capital efficiency and longer-term growth trajectory. We remain steadfast in our long-term value focus, employing resource development concepts and pace of activity that will keep us on a path to sustainable free cash flow generation at WTI prices in the low $50s from repeatable investments in our high quality asset base. »

        Operations Update

        At December 31, 2018, we had 466 gross (364 net) horizontal wells producing from eight established flow units in the Permian Basin. Net daily production for the three months ended December 31, 2018 grew 55% to 41.1 Mboe/d (81% oil) as compared to the same period of 2017. Full year production for 2018 averaged 32.9 Mboe/d (79% oil) reflecting growth of 44% over 2017 volumes.

        For the three months ended December 31, 2018, we drilled 17 gross (15.3 net) horizontal wells, and placed a combined 19 gross (17.2 net) horizontal wells on production. Wells placed on production during the quarter totaled approximately 106,000 net lateral feet and were completed in the upper and lower intervals of the Lower Spraberry, Wolfcamp A and Wolfcamp B within the Midland Basin and the Lower Wolfcamp A within the Delaware Basin.

        Midland Basin

        We brought nine gross wells online in the Monarch area in the fourth quarter achieving an average peak 24-hour rate of 235 Boe per thousand lateral feet with an average oil cut of 86%. More recent wells in the Monarch area demonstrate consistency in our well results across multiple zones with the Casselman 40 pad, a Wolfcamp A and B co-development project, averaging approximately 150 barrels of oil per thousand lateral feet in early time flowback. Additional multi-interval pad development projects targeting both upper and lower flow units in the Lower Spraberry, coupled with a Middle Spraberry well, are currently flowing back with encouraging early time results relative to offsetting wells.

        In the WildHorse area in Howard County, we placed on production a three-well pad which produced an average of approximately 190 Boe  (90% oil) per day per thousand lateral feet per well through the first 30 days. During the first quarter of 2019, we will be completing a five-well pad developing the Wolfcamp A on 10-well spacing, building upon our successful pilot test in the Fairway area of WildHorse last year.

        The previously disclosed outage at a third party gas processing facility in Martin County has persisted into the first quarter as the plant is brought back on a gradual basis. We expect a normalized level of gas processing to resume during the month of March. We estimate lost natural gas and NGL volumes during the fourth quarter of approximately 9,800 Mcfe/d, with no impact to our oil volumes. We currently expect an impact of approximately 4,000 Mcfe/d in the first quarter of 2019.

        Delaware Basin

        At our Spur area in Ward County, we placed on production six gross wells with an average completed lateral length of just under 8,000 feet. A two-well development including the Teewinot A1 04LA and A2 05LA wells have demonstrated strong performance since being turned to production in December. The two wells averaged approximately 390 Boe (85% oil) per day per thousand lateral feet through the first 70 days of production resulting in total production of nearly 260,000 Boe in just over two months. The Rock Garden A 08 LA and 01 LA wells, which were completed separately and brought on production during the third and latter part of the fourth quarter respectively, have each averaged approximately 1,300 Boe (88% oil) per day over their first 60 days. Additionally, the Limber Pine A2 05LA and A1 01LA wells, brought on production in November and December respectively, have each also averaged approximately 1,175 Boe (85% oil) per day through their first 60 days on production.

        We continue to build an inventory of drilled, uncompleted wells at Spur in preparation for larger pad development projects which are slated for completion during the second half of the year and are expected to provide meaningful production growth into year-end 2019 and early 2020. As part of our increased scale of planned development, we continue to enhance our field operations through an addition to our existing recycling facility. The addition will bring our total recycling capacity to 60,000 barrels of water per day, reducing our sourcing and disposal costs on a go forward basis while also reducing our environmental impact in the regional area.

        Following the acquisition of a significant producing asset base in September 2018, we have advanced several initiatives to improve operational reliability and reduce operating costs. We will be accelerating our maintenance and field optimization projects over the next three months, requiring a voluntary shut-in of production during that time. We expect this deferral of production will impact our productive capacity by roughly 1,000 Boe/d during the first quarter with a decreased impact in the second quarter as the project is expected to be completed in April.

        Capital Expenditures

        For the twelve months ended December 31, 2018, we incurred $546.1 million in cash operational capital expenditures (including other items) of $127.8 million in the fourth quarter, which represented a $21.7 million decrease from the third quarter. In the fourth quarter, we spent approximately $92.4 million on drilling and completion and $35.4 million on facilities, equipment, and other items on a cash basis. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):

        Three Months Ended December 31, 2018

        Operational

        Capitalized

        Capitalized

        Total Capital

        Capital (a)

        Interest

        G&A

        Expenditures

        Cash basis (b)

        $

        127,823

        $

        20,159

        $

        7,839

        $

        155,821

        Timing adjustments (c)

        13,354

        (2,659)

        —

        10,695

        Non-cash items

        —

        —

        353

        353

           Accrual basis

        $

        141,177

        $

        17,500

        $

        8,192

        $

        166,869

        (a)

        Includes seismic, land and other items.

        (b)

        Cash basis is presented here to help users of financial information reconcile amounts from the cash flow statement to the balance sheet by accounting for timing related changes in working capital that align with our development pace and rig count.

        (c)

        Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period.

         

        Operating and Financial Results

        The following table presents summary information for the periods indicated:

        Three Months Ended,

        December 31, 2018

        September 30, 2018

        December 31, 2017

        Net production

        Oil (MBbls)

        3,076

        2,521

        1,936

        Natural gas (MMcf)

        4,225

        4,144

        3,018

           Total (Mboe)

        3,780

        3,212

        2,439

        Average daily production (Boe/d)

        41,087

        34,913

        26,511

           % oil (Boe basis)

        81

        %

        78

        %

        79

        %

        Oil and natural gas revenues (in thousands)

           Oil revenue

        $

        150,398

        $

        142,601

        $

        104,132

           Natural gas revenue (a)

        11,497

        18,613

        14,081

              Total operating revenues

        161,895

        161,214

        118,213

           Impact of settled derivatives

        (1,594)

        (9,239)

        (4,501)

              Adjusted Total Revenue (i)

        $

        160,301

        $

        151,975

        $

        113,712

        Average realized sales price

        (excluding impact of settled derivatives)

           Oil (Bbl)

        $

        48.89

        $

        56.57

        $

        53.79

           Natural gas (Mcf)

        2.72

        4.49

        4.67

           Total (Boe)

        42.83

        50.19

        48.47

        Average realized sales price

        (including impact of settled derivatives)

           Oil (Bbl)

        $

        48.52

        $

        52.87

        $

        51.28

           Natural gas (Mcf)

        2.62

        4.51

        4.78

           Total (Boe)

        42.41

        47.31

        46.62

        Additional per Boe data

           Sales price (b)

        $

        42.83

        $

        50.19

        $

        48.47

              Lease operating expense (c)

        6.47

        5.77

        4.84

              Gathering and treating expense (a)

        —

        —

        0.57

              Production taxes

        2.51

        3.20

        2.55

           Operating margin

        $

        33.85

        $

        41.22

        $

        40.51

           Depletion, depreciation and amortization

        $

        15.74

        $

        15.02

        $

        14.98

           Adjusted G&A (d)

              Cash component (e)

        $

        2.03

        $

        2.17

        $

        2.46

              Non-cash component

        0.50

        0.57

        0.54

        (a)

        On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the three and twelve months ended December 31, 2018 were accounted for as a reduction to revenue.

        (b)

        Excludes the impact of settled derivatives.

        (c)

        Excludes gathering and treating expense.

        (d)

        Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

        (e)

        Excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization.

        Total Revenue. For the quarter ended December 31, 2018, Callon reported total revenue of $161.9 million and total revenue including settled derivatives (« Adjusted Total Revenue, » a non-GAAP financial measure(i)) of $160.3 million, including the impact of a $1.6 million loss from the settlement of derivative contracts. The table above reconciles Adjusted Total Revenue to the related GAAP measure of the Company’s total operating revenue. Average daily production for the quarter was 41.1 Mboe/d compared to average daily production of 34.9 Mboe/d in the third quarter of 2018. Average realized prices, including and excluding the effects of hedging, are detailed above.

        Hedging impacts. For the quarter ended December 31, 2018, Callon recognized the following hedging-related items (in thousands, except per unit data):

        Three Months Ended December 31, 2018

        In Thousands

        Per Unit

        Oil derivatives

        Net loss on settlements

        $

        (1,157)

        $

        (0.37)

        Net gain on fair value adjustments

        101,693

           Total gain on oil derivatives

        $

        100,536

        Natural gas derivatives

        Net loss on settlements

        $

        (437)

        $

        (0.10)

        Net gain on fair value adjustments

        3,819

           Total gain on natural gas derivatives

        $

        3,382

        Total oil & natural gas derivatives

        Net loss on settlements

        $

        (1,594)

        $

        (0.42)

        Net gain on fair value adjustments

        105,512

           Total gain on total oil & natural gas derivatives

        $

        103,918

        Lease Operating Expenses, including workover (« LOE »). LOE per Boe for the three months ended December 31, 2018 was $6.47 per Boe, compared to LOE of $5.77 per Boe in the third quarter of 2018. The increase in this metric resulted primarily from an increase in costs associated with recently acquired assets that reflect a higher historical operating cost.

        Production Taxes, including ad valorem taxes. Production taxes were $2.51 per Boe for the three months ended December 31, 2018, representing approximately 6% of total revenue before the impact of derivative settlements.

        Depreciation, Depletion and Amortization (« DD&A »). DD&A for the three months ended December 31, 2018 was $15.74 per Boe compared to $15.02 per Boe in the third quarter of 2018. The increase on a per unit basis was primarily attributable to greater increases in our depreciable asset base and assumed future development costs related to undeveloped proved reserves as compared to the estimated total proved reserve base.

        General and Administrative (« G&A »). G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, (« Adjusted G&A », a non-GAAP measure(i)) was $9.6 million, or $2.53 per Boe, for the three months ended December 31, 2018 compared to $8.8 million, or $2.74 per Boe, for the third quarter of 2018. The cash component of Adjusted G&A was $7.7 million, or $2.03 per Boe, for the three months ended December 31, 2018 compared to $7.0 million, or $2.17 per Boe, for the third quarter of 2018.

        For the three months ended December 31, 2018, G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands):

        Three Months Ended
        December 31, 2018

        Total G&A expense

        $

        8,514

           Change in the fair value of liability share-based awards (non-cash)

        1,069

        Adjusted G&A – total

        9,583

           Restricted stock share-based compensation (non-cash)

        (1,802)

           Corporate depreciation & amortization (non-cash)

        (94)

        Adjusted G&A – cash component

        $

        7,687

        Income tax expense. Callon provides for income taxes at a statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls and shortfalls, and state income taxes. We recorded an income tax expense of $5.6 million for the three months ended December 31, 2018 which relates to deferred federal and State of Texas gross margin tax. As of December 31, 2017, the valuation allowance was $60,919. During 2018, the Company’s tax position transitioned from a net deferred tax asset position to a net deferred tax liability position, thereby unwinding the valuation allowance balance to $0 as of December 31, 2018. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision of $30.3 million (or $0.13 per diluted share) for the quarter as if the valuation allowance did not exist.

        Proved Reserves

        DeGolyer and MacNaughton prepared estimates of Callon’s reserves as of December 31, 2018.

        As of December 31, 2018, our estimated net proved reserves grew 74% from prior year-end, totaling 238.5 MMboe and included 180.1 MMBbls of oil and 350.5 Bcf of natural gas with a standardized measure of discounted future net cash flows of $2.9 billion. Oil constituted approximately 76% of our total estimated equivalent net proved reserves and approximately 72% of our total estimated equivalent proved developed reserves. We added 85.0 MMboe of new reserves in extensions and discoveries through our development efforts in our operating areas, where we drilled a total of 70 gross (57.5 net) wells. We purchased reserves in place of 39.7 MMboe in a significant Delaware acquisition as well as bolt-on acquisitions completed within the Permian Basin and reduced our estimated net proved reserves through net revisions of previous estimates of 2.0 MMboe and reclassifications of 9.1 MMboe to probable reserves. Our net revisions of previous estimates were primarily related to technical revisions of proved undeveloped reserves. We reclassified 19 proved undeveloped (« PUD ») locations to probable reserves, primarily due to acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking. The changes in our proved reserves are as follows (in Mboe):

        Proved reserves:

        Reserves at December 31, 2017

        136,974

        Extensions and discoveries

        84,955

        Purchase of reserves in place

        39,683

        Revisions to previous estimates

        (2,021)

        Reclassifications due to changes in development plan

        (9,065)

        Production

        (12,018)

        Reserves at December 31, 2018

        238,508

        Callon replaced 690% of 2018 production as calculated by the sum of reserve extensions and discoveries, divided by annual production (« Organic reserve replacement ratio, » a non-GAAP financial measure(i)). The Company’s finding and development costs from extensions and discoveries (« Drill-bit F&D costs per Boe, » a non-GAAP financial measure(i)) were $7.03 per Boe calculated as accrual costs incurred for exploration and development divided by the reserves (in barrels of oil equivalent) added from extensions and discoveries. In addition, the Company had proved developed finding and development costs (« PD F&D costs per Boe, » a non-GAAP financial measure(i)) of $13.40 per Boe.

        Senior Management Promotions

        As part of Callon’s focus on leadership development to support the execution of our strategy, Michol Ecklund has been promoted to the role Senior Vice President, General Counsel and Corporate Secretary. In this new role, Michol will leverage her prior experience in human resources, environmental, social and governance (ESG) matters, and philanthropy, while continuing to provide legal advice to Callon. In addition, Liam Kelly has been promoted to the role of Vice President of Corporate Development, continuing to lead our business development efforts as well as manage our corporate planning team.

        2019 Guidance

        Full Year

        Full Year

        2018 Actual

        2019 Guidance

        Total production (Mboe/d)

        32.9

        39.5 – 41.5

        % oil

        79%

        77% – 78%

        Income statement expenses (per Boe)

        LOE, including workovers

        $5.76

        $5.50 – $6.50

        Production taxes, including ad valorem (% unhedged revenue)

        6%

        7%

           Adjusted G&A: cash component (a)

        $2.35

        $2.00 – $2.50

           Adjusted G&A: non-cash component (b)

        $0.55

        $0.50 – $1.00

           Cash interest expense (c)

        $0.00

        $0.00

        Effective income tax rate

        22%

        22%

        Capital expenditures ($MM, accrual basis)

        Total operational (d)

        $583

        $500 – $525

        Capitalized interest and G&A expenses

        $84

        $100 – $105

        Net operated horizontal wells placed on production

        54

        47 – 49

        (a)

        Excludes stock-based compensation and corporate depreciation and amortization. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

        (b)

        Excludes certain non-recurring expenses and non-cash valuation adjustments. Adjusted G&A is a non-GAAP financial measure; see the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense.

        (c)

        All interest expense anticipated to be capitalized.

        (d)

        Includes facilities, equipment, seismic, land and other items. Excludes capitalized expenses.

         

        Hedge Portfolio Summary

        The following table summarizes our open derivative positions as of December 31, 2018 for the periods indicated:

        For the Full Year of

        For the Full Year of

        Oil contracts (WTI)

        2019

        2020

        Puts

        Total volume (Bbls)

        912,500

        —

        Weighted average price per Bbl

        $

        65.00

        $

        —

        Put spreads

        Total volume (Bbls)

        912,500

        —

        Weighted average price per Bbl

          Floor (long put)

        $

        65.00

        $

        —

          Floor (short put)

        $

        42.50

        $

        —

        Collar contracts combined with short puts (three-way collars)

        Total volume (Bbls)

        4,564,000

        —

        Weighted average price per Bbl

        Ceiling (short call)

        $

        67.62

        $

        —

        Floor (long put)

        $

        56.60

        $

        —

        Floor (short put)

        $

        43.60

        $

        —

        Oil contracts (Midland basis differential)

        Swap contracts

        Total volume (Bbls)

        4,746,500

        4,024,000

        Weighted average price per Bbl

        $

        (4.72)

        $

        (1.51)

        Natural gas contracts (Henry Hub)

        Collar contracts (two-way collars)

        Total volume (MMBtu)

        8,282,500

        —

        Weighted average price per MMBtu

        Ceiling (short call)

        $

        3.46

        $

        —

        Floor (long put)

        $

        2.91

        $

        —

        Natural gas contracts (Waha basis differential)

        Swap contracts

           Total volume (MMBtu)

        11,321,000

        4,758,000

           Weighted average price per MMBtu

        $

        (1.23)

        $

        (1.12)

        Income (Loss) Available to Common Shareholders. The Company reported net income available to common shareholders of $154.4 million for the three months ended December 31, 2018 and Adjusted Income available to common shareholders of $39.9 million, or $0.17 per diluted share. Adjusted Income per fully diluted common share, a non-GAAP financial measure(i), adjusts our income available to common stockholders to reflect our theoretical tax provision for the quarter as if the valuation allowance did not exist. The following tables reconcile to the related GAAP measure the Company’s income available to common stockholders to Adjusted Income and the Company’s net income to Adjusted EBITDA (in thousands):

        Three Months Ended

        Adjusted Income per fully diluted common share:

        December 31, 2018

        September 30, 2018

        December 31, 2017

        Income available to common stockholders

        $

        154,370

        $

        36,108

        $

        21,001

           Net (gain) loss on derivatives, net of settlements

        (105,512)

        25,100

        26,037

           Change in the fair value of liability share-based awards

        (1,053)

        879

        865

        Tax effect on adjustments above

        22,379

        (5,456)

        (9,416)

           Change in valuation allowance

        (30,281)

        (8,323)

        (8,285)

        Adjusted Income

        $

        39,903

        $

        48,308

        $

        30,202

        Adjusted Income per fully diluted common share

        $

        0.17

        $

        0.21

        $

        0.15

        Three Months Ended

        Adjusted EBITDA:

        December 31, 2018

        September 30, 2018

        December 31, 2017

        Net income

        $

        156,194

        $

        37,931

        $

        22,824

           Net (gain) loss on derivatives, net of settlements

        (105,512)

        25,100

        26,037

           Non-cash stock-based compensation expense

        770

        2,587

        2,101

           Acquisition expense

        1,333

        1,435

        (112)

           Income tax expense

        5,647

        1,487

        248

           Interest expense

        735

        711

        461

           Depreciation, depletion and amortization

        60,301

        48,977

        37,222

           Accretion expense

        248

        202

        154

        Adjusted EBITDA

        $

        119,716

        $

        118,430

        $

        88,935

        Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the three months ended December 31, 2018 was $118.3 million and is reconciled to operating cash flow in the following table (in thousands):

        Three Months Ended

        December 31, 2018

        September 30, 2018

        December 31, 2017

        Cash flows from operating activities:

        Net income

        $

        156,194

        $

        37,931

        $

        22,824

        Adjustments to reconcile net income to cash provided by operating activities:

           Depreciation, depletion and amortization

        60,301

        48,977

        37,222

           Accretion expense

        248

        202

        154

           Amortization of non-cash debt related items

        734

        708

        455

           Deferred income tax expense

        5,647

        1,487

        247

           (Gain) loss on derivatives, net of settlements

        (105,512)

        25,100

        26,037

           Gain on sale of other property and equipment

        (64)

        (102)

        —

           Non-cash expense related to equity share-based awards

        1,823

        1,708

        1,240

           Change in the fair value of liability share-based awards

        (1,053)

        879

        865

        Discretionary cash flow

        $

        118,318

        $

        116,890

        $

        89,044

           Changes in working capital

        33,710

        (347)

        $

        (8,642)

           Payments to settle asset retirement obligations

        (389)

        (507)

        (216)

        Net cash provided by operating activities

        $

        151,639

        $

        116,036

        $

        80,186

        PV-10: Pre-tax PV-10, a non-GAAP measure(i), as of December 31, 2018 is reconciled below to the standardized measure of discounted future net cash flows (in thousands):

        As of December 31, 2018

        Standardized measure of discounted future net cash flows

        $

        2,941,293

           Add: 10 percent annual discount, net of income taxes

        3,716,571

           Add: future undiscounted income taxes

        782,470

        Undiscounted future net cash flows

        7,440,334

           Less: 10 percent annual discount without tax effect

        (4,291,127)

        Total Proved Reserves – Pre-tax PV-10

        3,149,207

        Total Proved Developed Reserves – Pre-tax PV-10

        2,222,049

        Total Proved Undeveloped Reserves – Pre-tax PV-10

        $

        927,158

        F&D and Reserve Replacement: The following table reconciles Drill-bit finding and development costs per boe(i) (« Drill-bit F&D per boe), Proved Developed finding and developed costs per boe(i) (PD F&D), Organic Reserve Replacement Ratio(i), and All-sources reserve replacement ratio(i); all of which are non-GAAP measures:

        Calculation

        2018

        Parameters

        Metrics

        Production (Mboe)

         (A)

        12,018

        Proved reserve data

        Proved reserves (Mboe)

        Total Proved extensions, discoveries, and other additions

         (B)

        84,955

        Proved Undeveloped extensions, discoveries, and other additions, net of revisions

         (C)

        52,526

        Proved Undeveloped transfers to Proved Developed

         (D)

        11,075

        Total Proved additions, net of revisions and reclassifications

         (E)

        113,552

        Total Proved extensions, discoveries, and other additions, net of revisions

         (F)

        82,934

        Costs Incurred:

        Acquisition costs:

           Evaluated properties

        $           347,305

           Unevaluated properties

        466,816

        Development costs

         (G)

        259,410

        Exploration costs

         (H)

        323,458

           Total costs incurred

        $        1,396,989

        Drill-bit F&D costs per Boe (two-stream)

        (G + H) / (F)

        $7.03

        PD F&D per Boe (two-stream)

        (G + H) / (B – C + D)

        $13.40

        Organic reserve replacement ratio

        (F) / (A)

        690%

        All-sources reserve replacement ratio

        (E) / (A)

        945%

         

        Callon Petroleum Company

        Consolidated Balance Sheets

        (in thousands, except par and per share values and share data)

        December 31, 2018

        December 31, 2017

        ASSETS

        Current assets:

        Cash and cash equivalents

        $

        16,051

        $

        27,995

        Accounts receivable

        131,720

        114,320

        Fair value of derivatives

        65,114

        406

        Other current assets

        9,740

        2,139

        Total current assets

        222,625

        144,860

        Oil and natural gas properties, full cost accounting method:

        Evaluated properties

        4,585,020

        3,429,570

        Less accumulated depreciation, depletion, amortization and impairment

        (2,270,675)

        (2,084,095)

        Net evaluated oil and natural gas properties

        2,314,345

        1,345,475

        Unevaluated properties

        1,404,513

        1,168,016

        Total oil and natural gas properties, net

        3,718,858

        2,513,491

        Other property and equipment, net

        21,901

        20,361

        Restricted investments

        3,424

        3,372

        Deferred tax asset

        —

        52

        Deferred financing costs

        6,087

        4,863

        Acquisition deposit

        —

        900

        Other assets, net

        6,278

        5,397

        Total assets

        $

        3,979,173

        $

        2,693,296

        LIABILITIES AND STOCKHOLDERS’ EQUITY

        Current liabilities:

        Accounts payable and accrued liabilities

        $

        261,184

        $

        162,878

        Accrued interest

        24,665

        9,235

        Cash-settleable restricted stock unit awards

        1,390

        4,621

        Asset retirement obligations

        3,887

        1,295

        Fair value of derivatives

        10,480

        27,744

        Other current liabilities

        13,310

        —

        Total current liabilities

        314,916

        205,773

        Senior secured revolving credit facility

        200,000

        25,000

        6.125% senior unsecured notes due 2024

        595,788

        595,196

        6.375% senior unsecured notes due 2026

        393,685

        —

        Asset retirement obligations

        10,405

        4,725

        Cash-settleable restricted stock unit awards

        2,067

        3,490

        Deferred tax liability

        9,564

        1,457

        Fair value of derivatives

        7,440

        1,284

        Other long-term liabilities

        100

        405

        Total liabilities

        1,533,965

        837,330

        Commitments and contingencies

        Stockholders’ equity:

        Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 shares outstanding

        15

        15

        Common stock, $0.01 par value, 300,000,000 shares authorized; 227,582,575 and 201,836,172 shares outstanding, respectively

        2,276

        2,018

        Capital in excess of par value

        2,477,278

        2,181,359

        Accumulated deficit

        (34,361)

        (327,426)

        Total stockholders’ equity

        2,445,208

        1,855,966

        Total liabilities and stockholders’ equity

        $

        3,979,173

        $

        2,693,296

         

        Callon Petroleum Company

        Consolidated Statements of Operations

        (in thousands, except per share data)

        Three Months Ended December 31,

        Twelve Months Ended December 31,

        2018

        2017

        2018

        2017

        Operating revenues:

        Oil sales

        $

        150,398

        $

        104,132

        $

        530,898

        $

        322,374

        Natural gas sales

        11,497

        14,082

        56,726

        44,100

        Total operating revenues

        161,895

        118,214

        587,624

        366,474

        Operating expenses:

        Lease operating expenses

        24,475

        13,201

        69,180

        49,907

        Production taxes

        9,490

        6,228

        35,755

        22,396

        Depreciation, depletion and amortization

        59,502

        36,543

        181,909

        115,714

        General and administrative

        8,514

        8,172

        35,293

        27,067

        Settled share-based awards

        —

        —

        —

        6,351

        Accretion expense

        248

        154

        874

        677

        Acquisition expense

        1,333

        (112)

        5,083

        2,916

        Total operating expenses

        103,562

        64,186

        328,094

        225,028

        Income from operations

        58,333

        54,028

        259,530

        141,446

        Other (income) expenses:

        Interest expense, net of capitalized amounts

        735

        461

        2,500

        2,159

        (Gain) loss on derivative contracts

        (103,918)

        30,536

        (48,544)

        18,901

        Other income

        (325)

        (41)

        (2,896)

        (1,311)

        Total other (income) expense

        (103,508)

        30,956

        (48,940)

        19,749

        Income before income taxes

        161,841

        23,072

        308,470

        121,697

        Income tax (benefit) expense

        5,647

        248

        8,110

        1,273

        Net income

        156,194

        22,824

        300,360

        120,424

        Preferred stock dividends

        (1,824)

        (1,823)

        (7,295)

        (7,295)

        Income available to common stockholders

        $

        154,370

        $

        21,001

        $

        293,065

        $

        113,129

        Income per common share:

        Basic

        $

        0.68

        $

        0.10

        $

        1.35

        $

        0.56

        Diluted

        $

        0.68

        $

        0.10

        $

        1.35

        $

        0.56

        Shares used in computing income per common share:

        Basic

        227,580

        201,835

        216,941

        201,526

        Diluted

        228,191

        202,426

        217,596

        202,102

         

        Callon Petroleum Company

        Consolidated Statements of Cash Flows

        (in thousands)

        Three Months Ended December 31,

        Twelve Months Ended December 31,

        2018

        2017

        2018

        2017

        Cash flows from operating activities:

        Net income (loss)

        $

        156,194

        $

        22,824

        $

        300,360

        $

        120,424

        Adjustments to reconcile net income to net cash provided by operating activities:

          Depreciation, depletion and amortization

        60,301

        37,222

        184,731

        118,051

          Accretion expense

        248

        154

        874

        677

          Amortization of non-cash debt related items

        734

        455

        2,483

        2,150

          Deferred income tax (benefit) expense

        5,647

        247

        8,110

        1,273

          Net (gain) loss on derivatives, net of settlements

        (105,512)

        26,037

        (75,816)

        10,429

          (Gain) loss on sale of other property and equipment

        (64)

        —

        (144)

        62

          Non-cash expense related to equity share-based awards

        1,823

        1,240

        6,289

        8,254

          Change in the fair value of liability share-based awards

        (1,053)

        865

        375

        3,288

          Payments to settle asset retirement obligations

        (389)

        (216)

        (1,469)

        (2,047)

          Payments for cash-settled restricted stock unit awards

        —

        —

        (4,990)

        (13,173)

          Changes in current assets and liabilities:

            Accounts receivable

        37,033

        (32,347)

        (17,351)

        (44,495)

            Other current assets

        (5,936)

        444

        (7,601)

        108

            Current liabilities

        9,510

        23,413

        74,311

        30,947

            Other long-term liabilities

        (6,065)

        —

        (278)

        121

            Other assets, net

        (832)

        (152)

        (2,230)

        (1,528)

            Other

        —

        —

        —

        (4,650)

            Net cash provided by operating activities

        151,639

        80,186

        467,654

        229,891

        Cash flows from investing activities:

        Capital expenditures

        (155,821)

        (152,621)

        (611,173)

        (419,839)

        Acquisitions

        (122,809)

        (3,952)

        (718,793)

        (718,456)

        Acquisition deposit

        —

        (900)

        —

        45,238

        Proceeds from sales of assets

        683

        20,525

        9,009

        20,525

        Additions to other assets

        (3,100)

        —

        (3,100)

        —

            Net cash used in investing activities

        (281,047)

        (136,948)

        (1,324,057)

        (1,072,532)

        Cash flows from financing activities:

        Borrowings on senior secured revolving credit facility

        230,000

        25,000

        500,000

        25,000

        Payments on senior secured revolving credit facility

        (95,000)

        —

        (325,000)

        —

        Issuance of 6.125% senior unsecured notes due 2024

        —

        —

        —

        200,000

        Premium on the issuance of 6.125% senior unsecured notes due 2024

        —

        —

        —

        8,250

        Issuance of 6.375% senior unsecured notes due 2026

        —

        —

        400,000

        —

        Payment of deferred financing costs

        530

        (28)

        (9,430)

        (7,194)

        Issuance of common stock

        (376)

        —

        287,988

        —

        Payment of preferred stock dividends

        (1,824)

        (1,824)

        (7,295)

        (7,295)

        Tax withholdings related to restricted stock units

        —

        —

        (1,804)

        (1,118)

            Net cash provided by financing activities

        133,330

        23,148

        844,459

        217,643

        Net change in cash and cash equivalents

        3,922

        (33,614)

        (11,944)

        (624,998)

          Balance, beginning of period

        12,129

        61,609

        27,995

        652,993

          Balance, end of period

        16,051

        27,995

        $

        16,051

        $

        27,995

        Non-GAAP Financial Measures and Reconciliations

        This news release refers to non-GAAP financial measures such as « Discretionary Cash Flow, » « Adjusted G&A, » « Adjusted Income, » « Adjusted EBITDA » and « Adjusted Total Revenue. » These measures, detailed below, are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

        • Callon believes that the non-GAAP measure of discretionary cash flow is a comparable metric against other companies in the industry and is a widely accepted financial indicator of an oil and natural gas company’s ability to generate cash for the use of internally funding their capital development program and to service or incur debt. Discretionary cash flow is defined by Callon as net cash provided by operating activities before changes in working capital and payments to settle asset retirement obligations and vested liability share-based awards. Callon has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements, which the Company may not control and the cash flow effect may not be reflected the period in which the operating activities occurred. Discretionary cash flow is not a measure of a company’s financial performance under GAAP and should not be considered as an alternative to net cash provided by operating activities (as defined under GAAP), or as a measure of liquidity, or as an alternative to net income.
        • Adjusted general and administrative expense (« Adjusted G&A ») is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans, as well as non-cash corporate depreciation and amortization expense. Callon believes that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table here within details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.
        • Callon believes that the non-GAAP measure of Adjusted Income available to common shareholders (« Adjusted Income ») and Adjusted Income per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided here within.
        • Callon calculates adjusted earnings before interest, income taxes, depreciation, depletion and amortization (« Adjusted EBITDA ») as Adjusted Income plus interest expense, income tax expense (benefit) and depreciation, depletion and amortization expense. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, the Company believes that Adjusted EBITDA provides additional information with respect to our performance or ability to meet our future debt service, capital expenditures and working capital requirements. Because Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDA presented may not be comparable to similarly titled measures of other companies.
        • Callon believes that the non-GAAP measure of Adjusted Total Revenue is useful to investors because it provides readers with a revenue value more comparable to other companies who engage in price risk management activities through the use of commodity derivative instruments and reflects the results of derivative settlements with expected cash flow impacts within total revenues.
        • We believe « Drill-Bit F&D costs per Boe, » « PD F&D costs per Boe », « Organic reserve replacement ratio », and « All-sources reserve replacement ratio » are non-GAAP metrics commonly used by Callon and other companies in our industry, as well as analysts and investors, to measure and evaluate the cost of replenishing annual production and adding proved reserves. The Company’s definitions of « Drill-Bit F&D costs per Boe, » « PD F&D costs per Boe » and « Organic reserve replacement ratio » and « All-sources reserve replacement ratio » may differ significantly from definitions used by other companies to compute similar measures and as a result may not be comparable to similar measures provided by other companies. Consequently, we provided the detail of our calculation within the included tables.
        • Year-end pre-tax PV-10 value is a non-GAAP financial measure as defined by the SEC. Callon believes that the presentation of pre-tax PV-10 value is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account future corporate income taxes and the Company’s current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies. The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows (« Standardized Measure »). Pre-tax PV-10 is calculated using the Standardized Measure before deducting future income taxes, discounted at 10 percent. The 12-month average benchmark pricing used to estimate proved reserves in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (« SEC ») and pre-tax PV-10 value for crude oil and natural gas was $65.56 per Bbl of WTI crude oil and $3.10 per MMBtu of natural gas at Henry Hub before differential adjustments. After differential adjustments, the Company’s SEC pricing realizations for year-end 2018 were $58.40 per Bbl of oil and $3.64 per Mcf of natural gas.

        Earnings Call Information

        The Company will host a conference call on Wednesday, February 27, 2019, to discuss fourth quarter 2018 financial and operating results.

        Please join Callon Petroleum Company via the Internet for a webcast of the conference call:

        Date/Time:

        Wednesday, February 27, 2019, at 8:00 a.m. Central Time (9:00 a.m. Eastern Time)

        Webcast:

        Select « IR Calendar » under the « Investors » section of the Company’s website: www.callon.com.

        Alternatively, you may join by telephone using the following numbers:

        Domestic:

        1-888-317-6003

        Canada:

        1-866-284-3684

        International:

        1-412-317-6061

        Access code:

        6127927

        An archive of the conference call webcast will also be available at www.callon.com under the « Investors » section of the website.

        About Callon Petroleum

        Callon Petroleum Company is an independent energy company focused on the acquisition, development, exploration, and operation of oil and natural gas properties in the Permian Basin in West Texas.

        Cautionary Statement Regarding Forward Looking Statements

        This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; the Company’s 2019 production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; and the implementation of the Company’s business plans and strategy, as well as statements including the words « believe, » « expect, » « plans », « may », « will », « should », « could » and words of similar meaning. These statements reflect the Company’s current views with respect to future events and financial performance based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, cost and availability of equipment and labor, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on our website or the SEC’s website at www.sec.gov.

        Contact information

        Mark Brewer
        Director of Investor Relations
        Callon Petroleum Company
        ir@callon.com
        1-281-589-5200

        (i)

        See « Non-GAAP Financial Measures and Reconciliations » included within this release for related disclosures and calculations

         

        Cision View original content:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-fourth-quarter-2018-results-300802580.html

        SOURCE Callon Petroleum Company

    • Ecopetrol increased its proven reserves to 1,727 million barrels equivalent

      février 22, 2019

      • Ecopetrol (BVC: ECOPETROL, NYSE: EC) today announced its proven reserves of oil, condensate and natural gas (reserves 1P), including its participation in subsidiaries and subsidiaries, on December 31, 2018.

        The reserves were estimated based on the standards and methodology of the Securities and Exchange Commission (SEC) of the United States. 99% of the reserves were audited by four recognized independent specialist firms (Ryder Scott Company, DeGolyer and MacNaughton, Gaffney, Cline & Associates and Sproule International Limited).

        At the end of 2018, the net proved reserves of the Ecopetrol Group were 1,727 million barrels of oil equivalent (Mbpe). The reserve replacement index was 129% and the average life of reserves equals 7.2 years.

        Of the total balance of reserves, 70% is crude and 30% corresponds to gas. On the other hand, the average life of crude oil and gas reserves is equivalent to 6.3 years and 11.1 years, respectively.

        98% of the total balance of proved reserves is in Colombia. It should be noted that Ecopetrol SA has an average reserve life of 7.4 years.

        In 2018, the Ecopetrol Group incorporated 307 Mbpe of proven reserves, continuing the positive trend of incorporation of reserves in 2017. The cumulative total production of the year was 239 million barrels of oil equivalent.

        The price defined by the SEC used for the valuation of the 2018 reserves was US $ 72.2 per Brent barrel compared to US $ 54.93 in 2017. Ecopetrol estimates that due to the effect of a higher price, approximately 47 Mbpe was recovered. On the other hand, about 260 million barrels of oil equivalent are the product of the technical management and economic optimization of the assets.

        It is important to highlight the record increase in proven reserves associated with the results of the recovery factor increase program (129 Mbps), whose main achievements have been in fields such as Chichimene, Castilla y Teca. Also, the incorporation of 57 Mbpe for extensions and discoveries, the largest addition for this concept in the last 5 years.

        The increase in reserves achieved in 2018 is one of the pillars of the Ecopetrol Group strategy that seeks to guarantee its long-term sustainability.

        This Ecopetrol release was published using an automatic translation system.

        http://www.bnamericas.com/en/news/oilandgas/ecopetrol-increased-its-proven-reserves-to-1727-million-barrels-equivalent/

    • Russian Gazprom Neft raises 2018 output on year to 1.286 mil b/d

      février 22, 2019

      • Moscow — Russia’s Gazprom Neft increased its 2018 liquids production « insignificantly » to 1.286 million b/d in 2018 amid output restrictions under the OPEC/non-OPEC production deal, the company said Thursday.

        Gazprom Neft, a leader in the country’s crude production growth before Russia entered production cut deal with OPEC, saw only a 0.9% increase year on year in 2018. To compare, its production grew by 4% in 2016, before the deal came in force.

        The slowdown in production growth came as the company was to limit its operations, including drilling, at a number of assets, in line with its production cut quota, it said in the financial and operational report for the fourth quarter and full year 2018.

        Gazprom Neft expects its crude production to grow 2% year on year in 2019, taking into account the current OPEC-led agreement on production limits, which is set to be in place for the first six months of the year, CEO Alexander Dyukov said last week.

        In 2018, the increase in production came mainly from its northern Novy Port, East-Messoyakha and Prirazlomnoye greenfields as well as from Iraqi projects, the company said in the report.

        Gazprom Neft’s production at the Badra project in Iraq as well as its projects in Kurdistan amounted to 1.61 million mt, or around 32,332 b/d, in 2018, up nearly 24% year on year, according to the company.

        The company’s total hydrocarbons’ production rose by 3.8% year on year to 1.89 million barrels of oil equivalent. This is largely due to the 9.4% year on year increase in gas production to 1.314 trillion cubic feet, it said.

        Refining throughput rose by 7% year on year to 42.91 million mt or 861,729 b/d, on low base of 2017 when the company carried out maintenance work at a number of its refineries.

        Net income jumped 48.7% year on year to Rb376.667 billion ($5.7 billion) as earnings rose by 28.7% on year to Rb2.5 trillion, due to oil prices growth and an increase in the sales of oil products, it said.

        RESERVES RISE

        The company has significantly expanded its reserves base through exploration and purchases of new licenses in 2018.

        Its total proved reserves grew by 2.9% year on year to 11.607 billion barrels of oil equivalent, including 7.038 billion boe of liquids and 27.415 trillion cubic feet of gas, the company said, citing the evaluation by DeGolyer & MacNaughton under PRMS standards.

        The figures do not include major recent findings in the Okhotsk Sea, Neptun (with resources in place estimated at 415.8 million mtoe or 3 billion boe) and Triton (up to 137 million mtoe).

        Gazprom Neft plans to continue exploration at its shaping up Sakhalin cluster through 2021, targeting crude production launch in the area for 2025-2026, Dyukov said last week in Sochi.

        — Nadia Rodova, nadia.rodova@spglobal.com

        — Edited by Ikhhlaq Singh Aujla, newsdesk@spglobal.com

        https://www.spglobal.com/platts/en/market-insights/latest-news/oil/022119-russian-gazprom-neft-raises-2018-output-on-year-to-1286-mil-b-d

    • D&M confirms independent assessment of reserves in Saudi Arabia for the Saudi Arabian Oil Company

      février 12, 2019

    • Rosneft Increased Its Proven Hydrocarbon Reserves By 4% In 2018

      février 12, 2019

      • As of 31.12.2018, Rosneft SEC proven hydrocarbon reserves were 41,431 mmboe (5,597 mmtoe)*. The hydrocarbon reserves increased by 1,524 mmboe (202 mln toe) versus reserves as of 2017 end or by 4%. The reserves audit to estimate the reserves through the end of fields commercial life was performed by DeGolyer & MacNaughton.

        As of 2018 end the SEC proven reserves life is more than 20 years. The SEC proven hydrocarbon reserves replacement ratio was 173% in 2018. **

        For a number of years now Rosneft has been taking by far the leading position among the largest public oil and gas companies with regard to SEC proven reserves-to-production rate and reserves replacement ratio. Along with this Rosneft is showing the lowest hydrocarbon exploration and production costs among the global energy companies.

        In PRMS (Petroleum Resources Management System) according to DeGolyer & MacNaughton classification as of 31.12.2018, 1Р hydrocarbon reserves were 47 045 mmboe. (6 368 mln toe), 2Р – 84 094 mln boe. (11 388 mln toe), 3Р category – 121 165 mln boe (16 426 mln toe).

        2018 reserves growth was due to successful exploration operations, the start of development of new field areas as well as improvement of development performance both in the traditional production regions (Yuganskneftegaz, Nyaganneftegaz) and the new projects (East Siberia fields).

        For many years now Rosneft has consistently ensured high levels of current production replacement with addition of reserves. In 2019-2022, the Company intends to replace a minimum of 100% of the produced hydrocarbons. Along with this accelerated reserves development is expected as well as speeding up of preparation of projects, conversion of resources to reserves taking into account their profitability, improvement of success rate of exploration drilling in the Russian Federation. In the medium term enhancement of production at mature fields and active development of new promising oil and gas projects, including Vankor cluster, Erginsky cluster, Rospan International fields, Russkoe, Kharampurskoe, North-Komsomolskoe, North-Danilovskoe, Yurubcheno-Takhomskoe will enable increase of the Company’s production through organic growth.

        * including fuel gas

        ** The replacement ratio has been estimated in tons of oil equivalent. In barrels of oil equivalent the replacement ratio is 175%.

        SOURCE: Rosneft

        https://www.oilandgasonline.com/doc/rosneft-increased-proven-hydrocarbon-reserves-0001

    • Callon Petroleum Company Provides 2019 Outlook and Year End Proved Reserves

      février 12, 2019

      • HOUSTON, Feb. 12, 2019 /PRNewswire/ — Callon Petroleum Company (NYSE: CPE) (« Callon » or the « Company ») today announced its 2019 capital expenditure budget, reflecting a combination of financial discipline and capital efficiency gains.

        • 2019 forecasted annual production of 39.5 – 41.5 MBoe/d (77% – 78% oil), representing growth of over 20% compared to current « street » consensus of 32.7 MBoe/d for 2018
        • Planned sequential decrease in 2019 operational capital expenditures to a range of $500 to $525 million
        • Running an average of five drilling rigs to support larger and more efficient, multi-well pad development
        • Plan to place 47 – 49 net wells on production with an increase of approximately 15% in average net lateral length over the 2018 program
        • Year-end 2018 proved reserves of 238.5 MMBoe (54% proved developed and 76% oil), an annual increase in total proved reserves of 74% and proved developed reserves of 85%
        • Year-end 2018 PV-10 value1 of $3.1 billion

        Joe Gatto, President and Chief Executive Officer of Callon, stated, « Our 2019 capital program highlights our commitment to generate free cash flow in the near-term as we transition to scaled development of our high quality asset base. Strong cash operating margins underpin our plan and are complemented by capital efficiency improvements resulting from multi-well pad development in the Delaware Basin, increasing lateral lengths across our portfolio and a significant reduction in facilities spending. Even under our flat $50/Bbl WTI oil price assumption, we expect to be free cash flow positive in the fourth quarter of 2019 with a full year outspend that is almost half of our 2018 projection. In addition, although our production growth rate will be lower than previous years, the combination of a well-established Midland Basin operation and the emerging impact of large pad development in the Delaware Basin positions us for a sustained trajectory over the longer term with capital expenditures within or below internal cash flows. » He continued, « Our tremendous progress maturing the business in recent years now allows us to benefit from repeatable well investments that will drive improved corporate-level returns due to scale efficiencies, reduced facilities needs and shallower production decline rates on a consolidated basis. Any improvement in commodity prices would further enhance that return on capital profile, as we have no plans to increase capital investment in 2019 with higher oil prices. »

        2019 Capital Expenditures Budget

        Callon expects operational capital expenditures to range between $500 and $525 million in 2019, with infrastructure and facilities capital comprising approximately 15% of operational capital. The percentage of operational expenditures allocated to the Delaware Basin is planned to increase to approximately 60% of the total with a transition to larger pad development in our Spur area as the year progresses to capture additional capital efficiencies and optimize development of our multi-zone resource base. Specifically, our average pad size in the Spur area is expected to more than double relative to our 2018 activity. As a result, completion activity will be primarily focused on the Midland Basin in the first half of the year and shift to a high proportion of multi-well pads in the Delaware Basin in the second half of 2019, accelerating production growth into year-end while maximizing capital efficiency. The program is also designed to optimize production and resource recovery from multiple zones through various co-development concepts that are tailored to specific operating areas. As a result, we will target seven discrete flow units in 2019, but the largest amount of wells are scheduled for the Wolfcamp A (upper and lower intervals).

        Importantly, our plan also incorporates a 15% increase in lateral length to approximately 8,400 feet as our highly contiguous Delaware Basin position enters program development, enabling us to place more net lateral feet on production in 2019 despite a decrease in net wells placed on line (47 to 49 wells) relative to 2018. Based upon this level of activity and associated allocation of capital, we are guiding to an average daily production rate range of 39.5 to 41.5 MBoe/d with an associated oil cut of 77% to 78%.

        We are currently operating six rigs and one dedicated completion crew. We expect to reduce the number of active rigs from six to four by mid-year after building a sufficient inventory of wells awaiting completion to provide operational flexibility for an increased proportion of larger pad concepts. We began 2019 with one dedicated completion crew and intend to reactivate a second crew to reduce cycle times on large development pads once the necessary drilling activity has been completed.

        In addition to operational capital expenditures, we forecast 2019 capitalized general & administrative expenses (cash component) of approximately $25 to $30 million and expect to capitalize 100% of cash interest expense that would otherwise be reflected on the income statement. Based upon current market interest rates, we estimate an applicable weighted average interest rate on our total average debt balances to be approximately 6%. In total, we forecast total capital expenditures (including estimated total capitalized expenses) of $615 million at the midpoint for 2019. This amount also includes land and seismic expenditures associated with the execution of our operational program. To the extent we identify accretive « bolt-on » land acquisition opportunities, we expect that these non-organic capital costs would be funded by divestitures of non-core properties or monetization of infrastructure investments.

        2018 Proved Reserves

        The Company recently completed the reserve audit for the year ended December 31, 2018 with its independent reserve auditor, DeGolyer and MacNaughton. As of December 31, 2018, Callon’s estimated total proved reserves were 238.5 MMBoe, a 74% increase over the previous year-end. The proved reserves estimate is comprised of 76% oil and 54% proved developed estimated volumes. The PV-10 value1 of proved reserves at year-end 2018 was $3.1 billion, with a proved developed producing reserves value of $2.2 billion.

        Callon Petroleum Company is an independent energy company focused on the acquisition, development, exploration and operation of oil and gas properties in the Permian Basin in West Texas.

        This news release is posted on the company’s website at www.callon.com, and will be archived for subsequent review under the « News » link on the top of the homepage.

        Non-GAAP Disclosure

        PV-10

        Year-end pre-tax PV-10 value is a non-GAAP financial measure as defined by the SEC. Callon believes that the presentation of pre-tax PV-10 value is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account future corporate income taxes and the Company’s current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies.

        The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows (« Standardized Measure »). Pre-tax PV-10 is calculated using the Standardized Measure before deducting future income taxes, discounted at 10%. The Company expects to include a full reconciliation of pre-tax PV-10 to the GAAP financial measure of Standardized Measure in its Earnings Press Release on Form 8-K for the fourth quarter 2018 financial and operating results, which it intends to file with the SEC on February 26, 2019.

        Cautionary Statement Regarding Forward Looking Statements

        This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; the Company’s 2019 production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; anticipated returns and financial position; and the implementation of the Company’s business plans and strategy, as well as statements including the words « believe, » « expect, » « may, » « will, » « forecast, » « plans » and words of similar meaning. These statements reflect the Company’s current views with respect to future events and financial performance based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and natural gas prices, ability to drill and complete wells, operational, regulatory and environment risks, cost and availability of equipment and labor, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, available on our website or the SEC’s website at www.sec.gov.

        For further information contact
        Mark Brewer
        Director of Investor Relations
        1-281-589-5200

        1 A non-GAAP financial measure: The 12-month average benchmark pricing used to estimate proved reserves in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (« SEC ») and pre-tax PV-10 value for crude oil and natural gas was $65.56 per Bbl of WTI crude oil and $3.10 per MMBtu of natural gas at Henry Hub before differential adjustments. After differential adjustments, the Company’s SEC pricing realizations for year-end 2018 were $58.40 per Bbl of oil and $3.64 per Mcf of natural gas. Please refer to the Non-GAAP Disclosure at the end of this release for information regarding pre-tax PV-10.

        SOURCE Callon Petroleum Company

        Related Links

        https://www.callon.com

        https://www.prnewswire.com/news-releases/callon-petroleum-company-provides-2019-outlook-and-year-end-proved-reserves-300793544.html

    • DNO Announces 100 Percent Reserves Replacement in 2018

      février 12, 2019

      • Oslo, 11 February 2019 – DNO ASA, the Norwegian oil and gas operator, today announced it replaced 2018 production through additions to reserves, marking the second consecutive year in which the Company’s replacement of proven reserves reached or exceeded 100 percent of production.

        « DNO’s stellar record of reserves replacement through the drill bit is a result of stepped up spending on our portfolio of quality assets coupled with rapid-fire execution, » said Bijan Mossavar-Rahmani, DNO’s Executive Chairman. « And the barrels we continue to add are among the lowest cost in the industry, anywhere, » he expounded.

        Yearend 2018 Company Working Interest (CWI) proven (1P) reserves stood at 240 million barrels of oil (MMbbls), unchanged from yearend 2017 after adjusting for production and technical revisions. On a CWI proven and probable (2P) reserves basis, DNO replaced 98 percent of its 2018 production, exiting the year with CWI 2P reserves of 376 MMbbls (384 MMbbls in 2017).

        At 2018 production rates, DNO’s 1P reserves life is 8.2 years and its 2P reserves life is 12.9 years.

        Significantly, the Company’s 1P reserves replacement ratio (RRR) has reached or exceeded 100 percent in eight of the past ten years.

        On a gross basis, at the Tawke license in the Kurdistan region of Iraq containing the Tawke and Peshkabir fields, yearend 2018 1P reserves stood at 348 MMbbls, unchanged from 2017 after adjusting for production of 41 MMbbls and upward technical revisions of 41 MMbbls. Tawke license 2P reserves stood at 502 MMbbls (513 MMbbls in 2017) and proven, probable and possible (3P) reserves at 697 MMbbls (880 MMbbls in 2017).

        Broken down by field, Tawke field gross 1P reserves stood at 294 MMbbls (335 MMbbls in 2017), 2P reserves at 376 MMbbls (438 MMbbls in 2017) and 3P reserves at 477 MMbbls (588 MMbbls in 2017). Peshkabir field gross 1P reserves stood 54 MMbbls (13 MMbbls in 2017), 2P reserves at 126 MMbbls (75 MMbbls in 2017) and 3P reserves at 220 MMbbls (292 MMbbls in 2017).

        International petroleum consultants DeGolyer and MacNaughton carried out the annual independent assessment of the Tawke license. The Company internally assessed the remaining licenses in its portfolio.

        The 2018 Annual Statement of Reserves and Resources, prepared and published in accordance with Oslo Stock Exchange listing and disclosure requirements (Circular No. 1/2013), is attached and is also available on the Company’s website at www.dno.no.

        —

        For further information, please contact:
        Media: media@dno.no
        Investors: investor.relations@dno.no
        Tel: +47 911 57 197

        —

        DNO ASA is a Norwegian oil and gas operator focused on the Middle East and the North Sea. Founded in 1971 and listed on the Oslo Stock Exchange, the Company holds stakes in onshore and offshore licenses at various stages of exploration, development and production in the Kurdistan region of Iraq, Norway, the United Kingdom and Yemen.

        —

        This information is subject to the disclosure requirements pursuant to section 5-12 of the Norwegian Securities Trading Act.

    • Genel Energy PLC: Tawke PSC reserves update

      février 11, 2019

      • Genel Energy PLC (GENL)
        Genel Energy PLC: Tawke PSC reserves update11-Feb-2019 / 07:00 GMT/BST
        Dissemination of a Regulatory Announcement, transmitted by EQS Group.
        The issuer is solely responsible for the content of this announcement.

        11February 2019Genel Energy plcTawke PSC reserves updateGenel Energy plc (‘Genel’) notes that DNO ASA, as operator of the Tawke PSC (Genel 25% working interest), has today issued an update on forecast reserves on the licencein the Kurdistan region of Iraq:According to international petroleum consultants DeGolyer and MacNaughton, who carried out the annual independent assessment of the Tawke PSC,on a gross basis year-end 2018 1P reserves stood at 348 MMbbls, unchanged from 2017 after adjusting for production of 41 MMbbls and upward technical revisions of 41 MMbbls. Tawke licence 2P reserves stood at 502 MMbbls (513 MMbbls in 2017) and proven, probable and possible (3P) reserves at 697 MMbbls (880 MMbbls in 2017). Broken down by field, Tawke field gross 1P reserves stood at 294 MMbbls (335 MMbbls in 2017), 2P reserves at 376 MMbbls (438 MMbbls in 2017) and 3P reserves at 477 MMbbls (588 MMbbls in 2017). Peshkabir field gross 1P reserves stood at 54 MMbbls (13 MMbbls in 2017), 2P reserves at 126 MMbbls (75 MMbbls in 2017) and 3P reserves at 220 MMbbls (292 MMbbls in 2017).-ends-For further information, please contact: Genel EnergyAndrew Benbow, Head of Communications+44 20 7659 5100Vigo CommunicationsPatrick d’Ancona+44 20 7390 0230Notes to editors:Genel Energy is an independent oil and gas exploration and production company listed on the main market of the London Stock Exchange (GENL)(lei:549300IVCJDWC3LR8F94).). The Company, with headquarters in London and offices in Ankara and Erbil, is one of the largest London-listed independent oil producers, and is the largest holder of reserves and resources in the Kurdistan Region of Iraq.Genel has highly cash-generative oil production from the Taq Taq and Tawke licences, with material growth potential from other assets in the portfolio. Genel also continues to pursue further growth opportunities. For further information, please refer to www.genelenergy.com.
        ISIN: JE00B55Q3P39
        Category Code: MSCM
        TIDM: GENL
        LEI Code: 549300IVCJDWC3LR8F94
        Sequence No.: 7429
        EQS News ID: 774223
        End of Announcement EQS News Servicehttps://www.marketwatch.com/press-release/genel-energy-plc-tawke-psc-reserves-update-2019-02-11

    • GeoPark Announces 2018 Certified Oil and Gas Reserves

      février 5, 2019

      • BOGOTA, Colombia–(BUSINESS WIRE)–GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Peru, Argentina, Brazil and Chile, today announced its independent oil and gas reserves assessment, certified by DeGolyer and MacNaughton Corp. (D&M), under PRMS methodology, as of December 31, 2018.

        All figures are expressed in US Dollars. Definitions of terms are provided in the Glossary on page [12].

        Year-End 2018 D&M Certified Oil and Gas Reserves and Highlights:

        • Higher Per Share Value:

        After consolidated capital expenditures of $2.9 per share in 2018:

        • Net debt-adjusted 2P NPV10 increase of $10.9 per share (3.8 times higher) to $40.1 per share, from $29.2 per share in 2017
        • Significant increase in Colombia’s net debt adjusted 2P NPV10 by 64% to $25.9 per share, from $15.8 per share in 2017, with capital expenditures of $1.6 per share
        • Accretive acquisition of LGI’s equity interest in GeoPark’s Colombian and Chilean subsidiaries for $2 per share, with a 2018 estimated 2P NPV10 of $4 per share
        • PDP Reserves:
          • Net proven developed producing (“PDP”) reserves increased 55% (by 15.7 mmboe) to 44.2 mmboe
          • PDP reserve life index (“RLI”) of 3.3 years
          • PDP reserve replacement ratio (« RRR ») of 218%
        • 1P Reserves:
          • Net proven (“1P”) reserves increased 17% (by 16.9 mmboe) to 113.9 mmboe
          • 1P RLI of 8.6 years
          • 1P RRR of 229%
          • 1P NPV10 increased by $268 million (up 17%) to $1.8 billion
        • 2P Reserves:
          • Net proven and probable (“2P”) reserves increased 15% (by 24.5 mmboe) to 183.7 mmboe
          • 2P RLI of 13.9 years
          • 2P RRR of 285%
          • 2P NPV10 increased by $454 million (up 20%) to $2.7 billion
        • Colombia 2P and 3P Reserves:
          • Net 2P reserves in Colombia increased 26% (by 23.0 mmboe) to 111.2 mmboe
          • 2P RLI of 10.7 years
          • 2P RRR of 321%
          • 2P NPV10 in Colombia increased by $491 million (up 35%) to $1.9 billion
          • Net 3P reserves in Colombia increased 43% (by 43.9 mmboe) to 145.6 mmboe
        • Peru 3P Reserves:
          • Gross 3P reserves in Peru increased 139% (by 115.3 mmbbl) to 198.3 mmbbl demonstrating the significant potential of the Situche Cntral field in the Morona block – with net 3P reserves of 131.2 mmbbl
          • 3P NPV10 in Peru increased by $1.1 billion (up 145%) to $1.9 billion
        • F&D Cost:
          • Finding and Development Cost (F&D Cost) for 2018 was $3.6 per boe on a 2P basis
          • F&D Cost for Colombia of $2.9 per boe on a 2P basis
          • Including the acquisition in Argentina, consolidated Finding, Development and Acquisition Cost (FD&A Cost) for 2018 was $3.6 per boe on a 2P basis

        James F. Park, Chief Executive Officer of GeoPark, said: “Again, our team did its job. Find, prove-up, develop and produce oil and gas – safely, cleanly and economically. The reserve certification is an important independent scorecard of an upstream company’s performance – and all elements of our report show major improvements across the board through 2018. Impressive growing oil and gas reserve volumes – strong reserve replacement metrics – large asset value increases – cheap Finding and Development Cost – and big bottom-line ‘per share’ value growth. Our Colombian Llanos 34 prize keeps getting more massive with even more opportunity for expansion. Furthermore, every category of reserve was certified with significant increases – demonstrating GeoPark’s short, medium and long-term depth, stability and potential. The report also highlights GeoPark’s unique oil and gas and regional asset platform – which is made real by our relentless 16-year performance growth track record – showing our team has, can and will continue to deliver results, meet challenges, and adapt and grow to capture our abundant opportunity set. Congratulations and many thanks to the women and men of GeoPark – the most dynamic oil and gas team in Latin America today.”

        Net Present Value per Share by Country

        The table below presents GeoPark’s net present value after tax and non-controlling interest, discounted at a 10% rate per share, by country, of 2P reserves as of December 31, 2018 and 2017.

        2018 Net Present Value per Share Colombia Peru Chile Argentina Brazil Total
        2P Reserves (mmboe) 111.2 30.3 24.7 14.2 3.2 183.7
        2P NPV10 2018 ($ mm) 1,884 410 306 93 52 2,745
        Shares Outstanding (mm) 60.5 60.5 60.5 60.5 60.5 60.5
        ($/share) 31.2 6.8 5.1 1.5 0.9 45.4

        The table below illustrates the details of the net debt adjusted 2P NPV10 per share which increased by 37% to $40.1 from $29.2 in 2017.

        Net Debt Adjusted 2P NPV10 per Share

        Total
        2018

        Total
        2017

        %
        Change
        2P NPV10 ($ mm) 2,745 2,291
        Non-controlling Interesta ($ mm) – -228
        Subtotal ($ mm) 2,745 2,063
        Shares Outstanding (mm) 60.5 60.6
        Subtotal ($/share) 45.4 34.0 34%
        Net Debtb/Share ($/share) -5.3 -4.8
        Net Debt Adjusted 2P NPV10 /Share ($/share) 40.1 29.2 37%
        a) Non-controlling interest refers to LGI participation in Chilean and Colombian subsidiaries. In November 2018, GeoPark acquired all outstanding LGI participation for $111 million plus three contingent payments of $5 million each that could be payable over the next three years, subject to certain production thresholds being exceeded.
        b) Net debt adjusted 2P NPV10 per share is shown on a consolidated basis. As of December 31, 2018, net debt is calculated considering unaudited financial debt of $446.7 million, less unaudited $127.7 million of cash and cash equivalents.

        Consolidated Reserve Life Index and Replacement Ratio

        Reserves Category December 2018 December 2017
        Consolidated (years)
        RLI PDP 3.3 2.8
        RLI 1P 8.6 9.5
        RLI 2P 13.9 15.6
        RLI 3P 26.2 23.7
        RRR PDP 218% 189%
        RRR 1P 229% 284%
        RRR 2P 285% 261%
        RRR 3P 899% 166%

        2018 Year-End Reserves Summary

        GeoPark engaged D&M to carry out an independent appraisal of reserves as of December 31, 2018, covering 100% of the current assets in Colombia, Chile, Brazil, Peru and Argentina. Following oil and gas production of 13.2 mmboe in 2018, D&M certified 2P net reserves of 183.7 mmboe (85% oil and 15% gas) as of December 31, 2018. By country, the reserves were: 61% in Colombia, 17% in Peru, 13% in Chile, 7% in Argentina and 2% in Brazil.

        Reserves Summary by Country and Category

        Country

        Reserves
        Category

        December 2018
        (mmboe)

        		 % Oil

        December 2017
        (mmboe)

        		 % Change
        Colombiaa PDP 34.7 99% 21.6 61%
        1P 79.5 100% 66.1 20%
        2P 111.2 100% 88.2 26%
        3P 145.6 100% 101.7 43%
        Peru PDP – 100% – N/A
        1P 18.5 100% 18.7 -1%
        2P 30.3 100% 31.5 -4%
        3P 131.2 100% 62.2 111%
        Chile PDP 2.8 25% 2.6 9%
        1P 7.2 48% 7.9 -9%
        2P 24.7 39% 34.0 -27%
        3P 37.9 40% 66.6 -43%
        Argentina PDP 3.5 62% 0.0 N/A
        1P 5.7 63% 0.0 N/A
        2P 14.2 44% 1.1 1191%
        3P 28.9 47% 6.4 352%
        Brazil PDP 3.1 2% 4.3 -28%
        1P 3.1 2% 4.3 -28%
        2P 3.2 2% 4.4 -27%
        3P 3.4 2% 4.6 -26%
        Total (D&M Certified) PDP 44.2 85% 28.5 55%
        1P 113.9 92% 97.0 17%
        2P 183.7 85% 159.2 15%
        3P 347.0 88% 241.6 44%
        a)

        GeoPark signed an agreement to divest the La Cuerva and Yamu blocks. The table above includes 1.1 mmboe, 2.3 mmboe, 5.3 mmboe and 7.9 mmboe of PDP, 1P, 2P and 3P reserves as of December 31, 2018, respectively in the La Cuerva and Yamu blocks.

        Analysis by Business Segment

        Colombia

        After record production of 10.8 mmbbl in 2018 (an increase of 30% over 2017), GeoPark’s 2P D&M certified reserves increased by 26% to 111.2 mmbbl compared to 2017. Net additions of 33.4 mmbbl of 2P reserves resulted from strong reservoir performance and continued successful exploration, development and appraisal drilling in the Llanos 34 block (GeoPark operated, 45% WI).

        For each barrel of oil extracted in Colombia, GeoPark added 2.3 barrels of 1P reserves, the equivalent of a 1P RRR of 229%. Similarly, for each barrel of oil extracted, GeoPark added 3.2 barrels of 2P reserves, resulting in a 2P RRR of 321%.

        The 1P RLI was 7.6 years, while the 2P RLI was 10.7 years.

        As of December 31, 2018, the Llanos 34 block included approximately 80-90 future development drilling locations (2P, gross, including the Mirador and Guadalupe formations). The Llanos 34 block represented 95% of GeoPark Colombia 2P D&M certified reserves as of December 31, 2018.

        In November 2018, GeoPark signed an agreement with Perenco Oil and Gas to divest the La Cuerva and Yamu blocks for $18 million plus a contingent payment of $2 million based on future oil prices. GeoPark will continue operating the La Cuerva and Yamu blocks until the closing of this transaction, expected in the first months of 2019. Reserves corresponding to the La Cuerva and Yamu blocks include 2.3 mmboe of 1P (1.1 mmboe PD and 1.2 mmboe PUD), 5.3 mmboe of 2P and 7.9 mmboe of 3P reserves as of December 31, 2018.

        Peru

        GeoPark completed the preparation of the Environmental Impact Assessment (EIA) to initiate operations in the Situche Central oil field in the Morona block (GeoPark operated, 75% WI). The EIA was submitted to the Servicio Nacional de Certificacion Ambiental (SENACE) on July 2, 2018. The Company is currently waiting for additional comments from SENACE, which is the final step of the EIA approval process.

        During 2018, D&M updated its review of the Situche Central field, including a reinterpretation of the 3D seismic, structural geology, trapping and oil migration model. Following this evaluation, D&M has certified 3P gross reserves of 198.3 mmbbl in the Situche Central field (131.2 mmbbl net to GeoPark), which represents a 111% increase with respect to the 2017 reserve certification, and provides more information with respect to the field size and significant upside potential.

        The Situche Central oil field in the Morona block represented 100% of GeoPark’s Peruvian D&M certified reserves.

        Chile

        GeoPark’s 2P D&M certified reserves in Chile decreased by 27% to 24.7 mmboe compared to 2017. Oil and gas production, adjusted development plans and other technical revisions caused the declines, which were partially offset by drilling successes.

        The 1P RLI was 7.2 years (no change from 2017). The 2P RLI decreased to 24.7 years, compared to 30.7 years in 2017.

        The Fell block represented 99% of GeoPark Chile 2P D&M certified reserves and consisted of 40% oil and 60% gas, similar to 2017.

        Argentina

        After production of 0.7 mmboe in 2018, GeoPark’s 2P D&M certified reserves in Argentina increased significantly to 14.2 mmboe compared to 1.1 mmboe in 2017. The net increase in 2018 includes the acquisition of 100% WI and operatorship of the Aguada Baguales, El Porvenir and Puesto Touquet blocks.

        The 1P RLI and 2P RLI increased to 6.1 years and 15.2 years, respectively.

        The Aguada Baguales, El Porvenir and Puesto Touquet blocks represented 91% of GeoPark Argentina 2P D&M certified reserves and consisted of 42% oil and 58% gas.

        Brazil

        GeoPark’s 2P D&M certified reserves in Brazil decreased by 27% to 3.2 mmboe compared to 2017, resulting from production of 1.1 mmboe during 2018.

        The 2P RLI decreased to 2.9 years compared to 4.0 years in 2017.

        The Manati field (GeoPark non-operated, 10% WI) represented 100% of GeoPark’s Brazilian D&M certified reserves and is 98% gas.

        D&M Net Certified Reserves Change by Country

        The following table shows the net change in 2P net reserves by country from December 31, 2017 to December 31, 2018:

        (mmboe) Colombia Peru Chile Argentina Brazil Total
        2P Net Reserves as of Dec. 31, 2017 88.2 31.5 34.0 1.1 4.4 159.2
        2018 Production -10.4 0.0 -1.0 -0.7 -1.1 -13.2
        Net Change 33.4 -1.2 -8.3 – -0.1 23.9
        Acquisitions – – – 13.8 – 13.8
        2P Net Reserves as of Dec. 31, 2018 111.2 30.3 24.7 14.2 3.2 183.7

        Net Present Value Summary

        The table below details D&M certified NPV10 by country and by category of reserves as of December 31, 2018 as compared to 2017:

        Country

        Reserves
        Category

        		 NPV10 2018 NPV10 2017
        ($ mm) ($ mm) % Change
        Colombia 1P 1,366 1,123
        2P 1,884 1,393
        3P 2,394 1,588
        Peru 1P 264 230
        2P 410 395
        3P 1,896 773
        Chile 1P 94 120
        2P 306 417
        3P 495 707
        Argentina 1P 44 1
        2P 93 7
        3P 262 90
        Brazil 1P 49 76
        2P 52 78
        3P 56 82
        Total 1P 1,817 1,549 17%
        (D&M Certified) 2P 2,745 2,291 20%
        3P 5,103 3,240 58%

        Oil Price Forecast

        The price assumptions used to estimate feasibility of PRMS reserves and NPV10 in 2018 and 2017 D&M reports are detailed in the table below:

        Brent Oil Price

        ($/bbl)

        		 2019 2020 2021 2022 2023

        2024-
        2026
        2018 Reserves Report 63.9 68.2 71.0 73.4 75.4 77.4-81.6
        2017 Reserves Report 62.0 65.0 68.1 71.6 74.3 78.1-84.6

        After 2026, Brent oil prices in the 2018 D&M report grow 2% per year.

        Total D&M Certified Future Net Revenue (Actual and Discounted)

        The table below presents D&M’s best estimate of GeoPark’s future net revenue (both actual and discounted at a 10% rate) and the unit value per boe, by country, and by category of certified reserves as of December 31, 2018:

        ($ mm)

        Oil and
        Gas
        Revenues

        Royalties

        Operating
        Costs

        Future
        Development
        Capital and
        Abandonment
        Costs

        Income
        Tax

        Future
        Net
        Revenue
        after tax

        Future Net
        Revenue
        after tax
        discounted
        at 10%

        Unit Value
        after tax
        discounted
        at 10%
        ($/boe)

        Colombia1
        1P 4,320 611 543 208 872 2,086 1,366 $17
        2P 6,120 877 715 288 1,259 2,981 1,884 $17
        3P 8,142 1,280 904 349 1,675 4,935 2,394 $16
        Peru
        1P 1,428 81 365 294 212 476 264 $14
        2P 2,467 141 624 415 392 895 410 $14
        3P 11,384 1,248 1,591 1,345 2,157 5,043 1,896 $15
        Chile
        1P 341 15 154 39 4 129 94 $13
        2P 1,107 46 369 159 66 467 306 $12
        3P 1,733 73 500 222 127 811 495 $13
        Argentina
        1P 298 56 123 54 7 58 43 $8
        2P 662 125 184 176 36 141 93 $7
        3P 1,432 269 292 262 147 462 262 $9
        Brazil
        1P 113 9 39 4 5 56 49 $16
        2P 118 9 39 4 5 61 52 $16
        3P 125 10 39 4 6 66 56 $16
        Total
        1P 6,500 772 1,224 599 1,100 2,805 1,817 $16
        2P 10,474 1,198 1,931 1,042 1,758 4,545 2,745 $15
        3P 22,817 2,880 3,326 2,182 4,112 10,317 5,103 $15
        1 Oil and gas revenues in Colombia are shown net of earn-out expenses, per IFRS rules, of $180 mm (1P), $250 mm (2P) and $325 mm (3P). D&M reported these expenses as operating costs.

        Finding and Development Cost by Reserves Category

        The table below sets forth the calculation of F&D and FD&A Cost as of December 31, 2018:

        December 31, 2018
        1P 2P

        Colombia
        1P

        Colombia
        2P
        Capital Expenditure/Acquisitions (unaudited) ($ mm) 124.7 124.7 97.0 97.0
        Reserve Additions (mmboe) 24.5 34.5 23.8 33.4

        Argentina Acquisition F&D Cost ($ mm)

        		 48.8 48.8 – –
        Argentina Reserves (mmboe) 5.2 13.8 – –

        F&D Cost ($/boe)

        		 5.1 3.6 4.1 2.9

        FD&A Cost ($/boe)

        		 5.8 3.6

        OTHER NEWS / RECENT EVENTS

        Reporting Date for 4Q2018 Results Release, Conference Call and Webcast

        GeoPark will report its 4Q2018 and Annual 2018 financial results on Wednesday, March 6, 2019 after the market close.

        In conjunction with 4Q2018 results press release, GeoPark’s management will host a conference call on March 7, 2019 at 9:00 am (Eastern Standard Time) to discuss these 4Q2018 financial results. To listen to the call, participants can access the webcast located in the Investor Support section of the Company’s website at www.geo-park.com.

        Interested parties may participate in the conference call by dialing the numbers provided below:United States

        Participants: 866-547-1509
        International Participants: +1 920-663-6208
        Passcode: 4069004

        Please allow extra time prior to the call to visit the website and download any streaming media software that might be required to listen to the webcast.

        An archive of the webcast replay will be made available in the Investor Support section of the Company’s website at www.geo-park.com after the conclusion of the live call.

        GLOSSARY

        1P

        		 Proven Reserves

        2P

        		 Proven plus Probable Reserves

        3P

        		 Proven plus Probable plus Possible Reserves

        boe

        Barrels of oil equivalent (6,000 cf gas per bbl of oil equivalent)

        boepd

        		 Barrels of oil equivalent per day

        bopd

        		 Barrels of oil per day

        Certified Reserves

        		 Refers to net reserves independently evaluated by the petroleum consulting firm, DeGolyer and MacNaughton Corp. (“D&M”)

        F&D Cost

        Finding and Development Cost, calculated as the unaudited cash flow from investing activities divided by the applicable net reserves additions before changes in Future Development Capital

        FD&A Cost

        Finding, Development and Acquisition Cost, calculated as the unaudited cash flow from investing activities plus acquisition costs divided by the applicable net reserves additions before changes in Future Development Capital

        mboed

        		 Thousands of Barrels of oil equivalent per day

        mmboed

        		 Millions of Barrels of oil equivalent per day

        mmbbl

        		 Millions of Barrels of oil

        mcfpd

        		 Thousands of standard cubic feet per day

        mmcfpd

        		 Millions of standard cubic feet per day

        NPV10

        		 Net Present Value after tax discounted at 10% rate

        PDNP

        		 Proven Developed Non-Producing Reserves

        PDP

        		 Proven Developed Producing Reserves

        PUD

        		 Proven Undeveloped Reserves

        RLI

        		 Reserve Life Index

        RRR

        		 Reserve Replacement Ratio

        sqkm

        		 Square kilometers

        WI

        		 Working Interest

        NOTICE

        Additional information about GeoPark can be found in the “Investor Support” section of the website at www.geo-park.com.

        The reserve estimates provided in this release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. Statements relating to reserves are by their nature forward-looking statements.

        Gas quantities estimated herein are reserves to be produced from the reservoirs, available to be delivered to the gas pipeline after field separation prior to compression. Gas reserves estimated herein includes fuel gas.

        Rounding amounts and percentages: Certain amounts and percentages included in this press release have been rounded for ease of presentation. Percentage figures included in this press release have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, certain percentage amounts in this press release may vary from those obtained by performing the same calculations using the figures in the financial statements. In addition, certain other amounts that appear in this press release may not sum due to rounding.

        Oil and gas production figures included in this release are stated before the effect of royalties paid in kind, consumption and losses.

        All evaluations of future net revenue contained in the D&M Reports are after the deduction of cash royalties, development costs, operating expenses, production and profit taxes, fees, earn out payments, well abandonment costs, and country income taxes from the future gross revenue. It should not be assumed that the estimates of future net revenues presented in the tables represent the fair market value of the reserves. The actual production, revenues, taxes and development, and operating expenditures with respect to the reserves associated with the Company’s properties may vary, from the information presented herein, and such variations could be material. In addition, there is no assurance that the forecast price and cost assumptions contained in the D&M Report will be attained, and variances could be material.

        CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

        This press release contains statements that constitute forward-looking statements. Many of the forward looking statements contained in this press release can be identified by the use of forward-looking words such as ‘‘anticipate,’’ ‘‘believe’’, ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among others.

        Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters including 2019 work program, NPV10 and NPV10/share estimations, estimated future revenues and oil price forecast. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors.

        Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see the Company’s filings with the U.S. Securities and Exchange Commission.

        Information about oil and gas reserves: The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proven, probable and possible reserves that meet the SEC’s definitions for such terms. GeoPark uses certain terms in this press release, such as « PRMS Reserves » that the SEC’s guidelines do not permit GeoPark from including in filings with the SEC. As a result, the information in the Company’s SEC filings with respect to reserves will differ significantly from the information in this press release. NPV10 for PRMS 1P, 2P and 3P reserves is not a substitute for the standardized measure of discounted future net cash flows for SEC proved reserves.

        Contacts

        INVESTORS:
        Stacy Steimel – Shareholder Value Director
        Santiago, Chile
        T: +562 2242 9600
        ssteimel@geo-park.com

        Miguel Bello – Market Access Director
        Santiago, Chile
        T: +262 2242 9600
        mbello@geo-park.com

        MEDIA:
        Jared Levy – Sard Verbinnen & Co
        New York, USA
        T: +1 (212) 687-8080
        jlevy@sardverb.com

        Kelsey Markovich – Sard Verbinnen & Co
        New York, USA
        T: +1 (212) 687-8080
        kmarkovich@sardverb.com

        https://www.businesswire.com/news/home/20190205005362/en/GeoPark-Announces-2018-Certified-Oil-Gas-Reserves

    • Uzbekneftegaz remaking Uzbekistan’s energy sector

      janvier 17, 2019

      • A big Uzbek delegation travelled to Berlin for the Uzbek-German investment summit that kicked off on January 14 and managed to sign off on €4bn worth of deals on the first day.

        bne IntelliNews managed to put some questions to Ulugbek Sayidov, first deputy chairman of the board at Uzbekistan’s national oil company Uzbekneftegaz on the prospects for the development of the country’s energy sector. While Uzbekistan does not have anywhere as near as much in the way of hydrocarbon deposits as its neighbours Kazakhstan and Turkmenistan, the oil and gas sector is crucial for supplying what is Central Asia’s most populous country with energy.

        bne: How much oil and gas does Uzbekneftegaz produce a year?

        In 2018, natural gas was produced at around 60-65 billion cubic metres which is 8.5% higher than in 2017.

        In 2018, the production of liquid hydrocarbons accounted for around of 3 million tonnes, fully sent to local refineries for further processing.

        bne: How has this changed over the last few years? Stable or rising?

        For the last few years the production of natural gas has risen moderately and in 2018 the growth rate accounted for 8.5% in comparison to 2017. The production of liquid hydrocarbons has stayed stable for the last few years.

        bne: What is the domestic need for oil and gas? Does Uzbekneftegaz produce enough to cover all domestic needs or does Uzbekistan have to import?

        Natural gas produced in Uzbekistan is used both to satisfy the domestic demand, and also for export in accordance with long-term export contracts.

        Uzbekistan imports liquid hydrocarbons from Turkmenistan, Kazakhstan and Russia in order to satisfy the rising need in oil products.

        bne: What is the potential for finding new deposits of oil and gas in the country?

        Currently, the government of the country is paying great attention to increasing the potential of the oil and gas industry. In this direction, the “Program of development and reproduction of the mineral resource base for the period 2017-2021” is being implemented. This program includes a complex of various special geological and other works carried out for the purpose of finding, detecting and preparing for the industrial development of hydrocarbon deposits.

        In order to increase the extraction of hydrocarbons and the further production of petroleum products under exploration programs, work is being undertaken on promising investment blocks of the republic. Such leading foreign companies as Lukoil, Gazprom, CNPC, KNOC, Socar, British Petroleum, Tatneft, Zarubezhneft, Total, ONGC and others are involved in the process.

        bne: Is Uzbekneftegaz going to be part of the privatisation programme?

        JSC Uzbekneftegaz put up for auction its non-core assets that are on the balance sheet of the company. In most cases, these are companies and business units that are ready-made businesses. There are more than 150 of them, and they are sold to business entities at market value through public tenders. In addition, 26 business units have been transferred to local executive authorities in the field at the residual (book) value.

        We also develop public-private partnerships. In particular, the possibility of creating conditions for attracting private sector investment to gas distribution enterprises are now being considered by concluding a public-private partnership agreement. These steps are aimed at developing healthy competition in the industry, leading to an improved quality of services provided to consumers.

        bne: Are there any plans to IPO the company at any point? Can you give any details? Will it be like Gazprom/Rosneft? Any indication of how big a stake could be sold to foreign investors?

        Currently, work is underway to obtain an international credit rating of the company, which will expand the cooperation of Uzbekneftegaz with foreign partners, attract credit funds from world financial markets and provide various sources of foreign investment and its diversification.

        Assistance in this direction for Uzbekneftegaz is being given by the Asian Development Bank in the framework of the project on technical assistance for the corporate transformation of the company. The auditing company EY is assisting us to audit the consolidated financial statements of Uzbekneftegaz. The consulting company The Boston Consulting Group has been hired to assess the prospects of the prospective projects in terms of their effectiveness of the use of natural, material, financial and other resources. The consulting company DeGolyer & MacNaughton has been engaged for the calculation of reserves, according to the most global accounting system for the classification and management of hydrocarbons and their reserves.

        bne: Does the company plan to offer any eurobonds after the government has gone ahead with its debut eurobond this year?

        The company is conducting a systematic review for the preparation of a debut issue of debt securities, eurobonds, this year after the issue of sovereign bonds.

        The first step in this direction is the preparation of consolidated financial statements for the requirements of IFRS and having a credit rating from the world’s leading rating agencies such as S&P, Moody’s and/or Fitch, which requires preparation in the following things:

        – determine the market value of fixed assets, intangible assets, capital investment objects and investments (work has already started with the help of KPMG);

        – independent calculation and economic evaluation of hydrocarbon reserves and conditional resources (ditto with « DeGolyer & MacNaughton »), etcetera.

        The next step is to attract other necessary counterparties such as project coordinators, legal consultants, etcetera, which is also already in progress now.

        bne: Are there any plans to invest in downstream facilities like refineries?

        Uzbekneftegaz JSC is implementing a number of large investment projects in downstream. One of them is the project “Expanding the Shurtan Gas Chemical Plant”, where the production of value added products such as polyethylene (280,000 tonnes) and polypropylene (100,000 tonnes) will be adjusted.

        During the production of polymers in the Shurtan project, a co-product – a pyrolysis distillate  – will be established that allows for further processing and the production of aromatic hydrocarbons, which are valuable raw materials for specific subsectors of the chemical industry.

        Furthermore, it is planned to implement a number of projects on the technology of MTO (methanol to olefins) for the production of oil plasticizers.

        The implementation of these projects will allow for organising the production of new types of products such as polyethylene terephthalate (PET), polyacrylonitrile, butadiene rubber, polystyrene, benzene, toluene, and xylenes, which are in demand in the textile and processing industries, automotive industry, pharmaceuticals, production of building materials, automobile tires, rubber products, consumer goods and special chemistry and facing materials.

        bne: In addition to a bond and retained earnings, what other plans are there for funding the expansion of your business, including plans for debt.

        Uzbekneftegaz practices various schemes for financing investment projects: enterprises’ own funds, foreign direct investment, loans from local commercial banks, loans from the Fund for Reconstruction and Development of the Republic of Uzbekistan, loans from international commercial banks for project financing. In addition, the practice of attracting loans from foreign commercial banks and financial institutions under the state guarantee for projects of strategic importance is also practiced.

        In the future we plan to fund large projects by attracting foreign direct investment and loans on a project financing basis.

        bne: What roles do China and Russia play in the country’s energy sector?

        A number of Russian and Chinese oil and gas companies, such as Gazprom, Lukoil, Zarubezhneft, Tatneft, CNPC and others, are involved in the energy market of Uzbekistan. They participate in both upstream projects and downstream as investors.

        At the same time, large financial institutions like Vnesheconombank (VEB), Gazprombank, and the Silk Road Fund provide for the financing of large investment projects in Uzbekistan. Also, Uzbekneftegaz exports natural gas to these countries, and also imports oil from Russia.

        http://www.intellinews.com/interview-uzbekneftegaz-remaking-uzbekistan-s-energy-sector-154813/

    • GeoPark Announces Fourth Quarter 2018 Operational Update

      janvier 16, 2019

      • Record Annual Oil and Gas Production up 31%

        Extending Consistent 15-Year Growth Track Record

        More Than 85% Drill Bit Success

        Acquisition of Key Colombian Llanos 34 Interests

        BOGOTA, Colombia–(BUSINESS WIRE)–GeoPark Limited (“GeoPark” or the “Company”) (NYSE: GPRK), a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Peru, Argentina, Brazil and Chile, today announced its operational update for the three-month period ended December 31, 2018 (“4Q2018”).

        All figures are expressed in US Dollars and growth comparisons refer to the same period of the prior year, except when otherwise specified.

        Fourth Quarter 2018 Highlights

        Oil and Gas Production: Hits and Exceeds Targets

        • Annual 2018 average production up 31% to 36,027 boepd, hitting 35,500-36,500 boepd guidance
        • Record 2018 exit production of 39,600 boepd, exceeded guidance of 38,000-39,000 boepd
        • Consolidated oil and gas production up 26% to 38,741 boepd (up 4% compared to 3Q2018)
        • Oil production increased by 30% to 32,859 bopd (up 5% compared to 3Q2018)
        • Gross operated production in Llanos 34 block (GeoPark operated, 45% WI) surpassed 70,000 bopd
        • Gas production increased by 11% to 35.3 mmcfpd

        Operations: Capital Efficiency and Execution

        • GeoPark’s 2018 work program included a total of 33 gross wells drilled (30 operated with a success rate of over 85%), including development, appraisal and exploration wells, as part of its $140-150 million capital expenditure plan
        • In Colombia: eight new wells were tested and put on production in the Llanos 34 block, adding 7,000 bopd gross from new wells. Llanos 34 flowline on schedule and on budget
        • In Brazil: Praia dos Castelhanos 1 exploration well was drilled in the REC- T-128 block (GeoPark operated, 70% WI) and will be completed and tested in 1Q2019

        Portfolio Growth: Acquisition of LGI’s Interests in Colombia and Chile

        • Acquired LGI’s 20% equity interest in GeoPark’s Chilean and Colombian subsidiaries, which expanded the Company’s participation in the valuable Llanos 34 block, and contributed with significant corporate synergies and bottom-line benefits
        • Divested high-cost, non-core La Cuerva and Yamu Colombian assets for up to $20 million

        Catalysts: 1Q2019

        • Testing five drilled wells and drilling five new wells, including development, appraisal and exploration wells across the pan-regional portfolio in Colombia, Argentina, Brazil and Chile
        • Flowline in the Llanos 34 block expected to be operational in 1Q2019
        • New independent reserves certification by DeGolyer and MacNaughton (D&M) underway and expected to be released in early February 2019

        Breakdown of Quarterly Production by Country

        The following table shows production figures for 4Q2018, as compared to 4Q2017:

        4Q2018 4Q2017

        Total
        (boepd)

        Oil
        (bopd)a

        Gas
        (mcfpd)

        Total
        (boepd)

        		 % Chg.
        Colombia 30,641 30,497 863 24,378 +26%
        Brazil 2,894 41 17,117 3,328 -13%
        Chile 2,823 725 12,585 2,932 -4%
        Argentina 2,383 1,596 4,723 16 –
        Total 38,741 32,859 35,288 30,654 +26%

        a) Includes royalties paid in kind in Colombia for approximately 1,181 bopd in 4Q2018. No royalties were paid in kind in Brazil, Chile or Argentina.

        Quarterly Production Evolution

        (boepd) 4Q2017 1Q2018 2Q2018 3Q2018 4Q2018
        Colombia 24,378 26,405 27,940 29,139 30,641
        Brazil 3,328 2,775 2,904 3,124 2,894
        Chile 2,932 2,873 2,559 2,632 2,823
        Argentina 16 142 2,467 2,319 2,383
        Total 30,654 32,195 35,870 37,214 38,741
        Oil 25,341 27,345 30,249 31,266 32,859
        Gas 5,313 4,850 5,621 5,948 5,882

        Oil and Gas Production Update

        Consolidated:

        Overall oil and gas production grew by 26% to 38,741 boepd in 4Q2018 from 30,654 boepd in 4Q2017, due to increased production in Colombia and new production from the recent Argentina acquisitions.

        Oil represented 85% of total reported production compared to 83% in 4Q2017.

        Colombia:

        Average net production in Colombia grew 26% to 30,641 boepd in 4Q2018 compared to 24,378 boepd in 4Q2017, reflecting continued successful appraisal and development drilling in Tigana and Jacana oil fields in the Llanos 34 block, which represented 96% of Colombian production in 4Q2018.

        By end-December 2018, the Llanos 34 block surpassed the 70,000 gross bopd milestone, extending seven years of production growth and operating momentum, and setting a solid base for continued growth during 2019.

        Llanos 34 block 4Q2018 operational results:

        Exploration drilling:

        • Tigui Sur 1 well, located south of the Tigui 1 exploration well, next to the southern border of the Llanos 34 block, was successfully tested during 4Q2018. Tigui oil field (including Tigui 1 and Tigui Sur 1 wells) is currently producing 1,900 bopd with a 6% water cut.
        • The Company is currently drilling Tigui 2 appraisal well, located 870 meters east of Tigui 1 well, to continue delineating the size and distribution of the reservoir.

        Development and appraisal drilling:

        • Seven new wells were tested and put on production, including Tigana 5, Tigana Norte 10, Tigana Norte 11, Tigana Norte 12, Tua 11, Jacana 14 and Jacana 19, which are currently producing approximately 6,800 bopd gross.

        Infrastructure update:

        • The flowline to connect the Llanos 34 block to the Oleoducto de los Llanos (ODL), one of Colombia’s principal pipelines (with a capacity of 314,000 bopd) is on budget and on schedule and is expected to be operational in 1Q2019. The project will support future production growth (with a capacity of up to 100,000 bopd) and reduce transportation and operating costs.

        Sale of La Cuerva and Yamu non-core assets:

        • In November 2018, GeoPark signed an agreement with Perenco Oil and Gas to divest the La Cuerva and Yamu blocks for $18 million plus a contingent payment of $2 million based on future oil prices. GeoPark will continue operating the La Cuerva and Yamu blocks until the closing of this transaction, expected in 1Q2019.

        For a summary of upcoming drilling and testing activities, please refer to the 1Q2019 drilling schedule below.

        Peru:

        During 4Q2018, GeoPark successfully concluded the last round of workshops with local communities. The Company is currently waiting for additional comments from Servicio Nacional de Certificación Ambiental para las Inversiones Sostenibles, which is the last step of the Environmental Impact Assessment approval process.

        The Morona block (GeoPark operated, 75% WI) contains the Situche Central oil field, which has been delineated by two wells that tested combined production rates of 7,500 bopd of light oil with identified upside potential of more than 200 mmbo. As of December 2017, D&M certified gross proven and probable (2P) reserves of 42.1 mmbo and 3P reserves of 83.0 mmbo for the Situche Central oil field.

        Argentina:

        Average net production in Argentina totaled 2,383 boepd in 4Q2018 (67% oil, 33% gas) corresponding to the acquisition of the Aguada Baguales, El Porvenir and Puesto Touquet blocks (GeoPark operated, 100% WI) in the Neuquen basin. Net production levels in 4Q2018 increased by 3% compared to 3Q2018, due to an ongoing secondary recovery optimization project that included a low-cost well intervention campaign initiated in August 2018.

        Testing activities in the El Porvenir block (GeoPark operated, 100% WI):

        • Site preparation and installation activities completed during 4Q2018 to test a tight gas play in the Challaco Bajo 1001 well. Testing expected to begin in January 2019.

        Exploration drilling in the CN-V block (GeoPark, 50% WI):

        • Initial testing activities in the Rio Grande Este 1 exploration well were unsuccessful. The joint venture is currently evaluating subsequent steps.

        For a summary of upcoming drilling and testing activities, please refer to the 1Q2019 drilling schedule below.

        Brazil:

        Average net production in the Manati field (GeoPark non-operated, 10% WI) decreased by 13% to 2,894 boepd in 4Q2018, compared to 3,328 boepd in 4Q2017, due to lower gas demand for power generation as a result of increased hydroelectric power availability.

        Exploration drilling in the REC-T-128 block:

        • Praia dos Castelhanos 1 exploration well was drilled to a total depth of 8,431 feet. Testing activities expected during 1Q2019.

        Chile:

        Average net oil and gas production in Chile decreased by 4% to 2,823 boepd in 4Q2018 compared to 2,932 boepd in 4Q2017, but increased 7% compared to 3Q2018 due to the recent discovery of the Jauke gas field. The production mix during 4Q2018 was (74% gas, 26% light oil vs. 66% gas, 34% light oil in 4Q2017). The Fell block (GeoPark operated, 100% WI) represented 100% of Chilean production in 4Q2018.

        During 4Q2018, surface facilities optimization resulted in an increase of overall gas production levels. The Fell block is currently producing 3,000-3,100 boepd (80% gas, 20% light oil).

        For a summary of upcoming drilling and testing activities, please refer to the 1Q2019 drilling schedule below.

        1Q2019 Drilling Schedule

        The following is a summary of expected drilling and testing activities scheduled for 1Q2019:

        Prospect/Wella Country Block WI Type
        1 Tigana Sur Oeste 10 Colombia Llanos 34 45% Development
        2

        Aruco 2b

        		 Colombia Llanos 34 45% Development
        3

        Tigui 2b

        		 Colombia Llanos 34 45% Appraisal
        4 Tua 13 Colombia Llanos 34 45% Development
        5

        Jacana 23b

        		 Colombia Llanos 34 45% Development
        6 Jacana 31 Colombia Llanos 34 45% Development
        7

        Challaco Bajo -1001c

        		 Argentina El Porvenir 100% Exploration
        8 Challaco Bajo -2002 Argentina El Porvenir 100% Development
        9

        Praia dos Castelhanos 1b

        		 Brazil REC-T-128 70% Exploration
        10 Jauke 2 Chile Fell 100% Development

        a) Information included in the table above is subject to change and may also be subject to partner or regulatory approval

        b) Drilling initiated or completed with testing activities expected in 1Q2019

        c) Drilled in prior years by the previous operator of the block before GeoPark acquired the assets. Testing activities expected in 1Q2019

        GLOSSARY
        Adjusted EBITDA Adjusted EBITDA is defined as profit for the period before net finance costs, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful efforts, accrual of share-based payments, unrealized results on commodity risk management contracts and other non-recurring events
        Adjusted EBITDA per boe Adjusted EBITDA divided by total boe deliveries
        Operating netback per boe Revenue, less production and operating costs (net of depreciation charges and accrual of stock options and stock awards) and selling expenses, divided by total boe deliveries. Operating netback is equivalent to Adjusted EBITDA net of cash expenses included in Administrative, Geological and Geophysical and Other operating costs
        Bbl Barrel
        Boe Barrels of oil equivalent
        Boepd Barrels of oil equivalent per day
        Bopd Barrels of oil per day
        CEOP Contrato Especial de Operacion Petrolera (Special Petroleum Operations Contract)
        D&M DeGolyer and MacNaughton

        F&D costs

        Finding and development costs, calculated as capital expenditures divided by the applicable net reserves additions before changes in Future Development Capital

        LTM

        Last Twelve Months
        Mboe Thousand barrels of oil equivalent
        Mmbo Million barrels of oil
        Mmboe Million barrels of oil equivalent
        Mcfpd Thousand cubic feet per day
        Mmcfpd Million cubic feet per day
        Mm3/day Thousand cubic meters per day
        PRMS Petroleum Resources Management System
        SPE Society of Petroleum Engineers
        WI Working interest
        NPV10 Present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual rate of 10%
        Sqkm Square kilometers

        NOTICE

        Additional information about GeoPark can be found in the “Investor Support” section on the website at www.geo-park.com.

        Rounding amounts and percentages: Certain amounts and percentages included in this press release have been rounded for ease of presentation. Percentage figures included in this press release have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, certain percentage amounts in this press release may vary from those obtained by performing the same calculations using the figures in the financial statements. In addition, certain other amounts that appear in this press release may not sum due to rounding.

        CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

        This press release contains statements that constitute forward-looking statements. Many of the forward- looking statements contained in this press release can be identified by the use of forward-looking words such as ‘‘anticipate,’’ ‘‘believe,’’ ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’ ‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among others.

        Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters, including expected production growth, expected schedule, economic recovery, payback timing, IRR, drilling activities, demand for oil and gas, capital expenditures plan, regulatory approvals, reserves and exploration resources. Forward-looking statements are based on management’s beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors. Oil and gas production figures included in this release are stated before the effect of royalties paid in kind, consumption and losses, except when specified.

        Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see filings with the U.S. Securities and Exchange Commission.

        Readers are cautioned that the exploration resources disclosed in this press release are not necessarily indicative of long-term performance or of ultimate recovery. Unrisked prospective resources are not risked for change of development or chance of discovery. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development. There is no certainty that any portion of the Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Prospective Resource volumes are presented as unrisked.

        Contacts

        INVESTORS:
        Stacy Steimel – Shareholder Value Director
        Santiago, Chile
        ssteimel@geo-park.com
        T: +562 2242 9600

        Miguel Bello – Market Access Director
        Santiago, Chile
        T: +562 2242 9600
        mbello@geo-park.com

        MEDIA:
        Jared Levy – Sard Verbinnen & Co
        New York, USA
        T: +1 (212) 687-8080
        jlevy@sardverb.com

        Kelsey Markovich – Sard Verbinnen & Co
        New York, USA
        T: +1 (212) 687-8080
        kmarkovich@sardverb.com

        https://www.businesswire.com/news/home/20190116005164/en/GeoPark-Announces-Fourth-Quarter-2018-Operational-Update

    • Matra Petroleum AB: 2018 reserves and operations update

      janvier 16, 2019

      • The net present value (PV10) of Matra Petroleum’s proved net oil and gas reserves as per 31 December 2018 increased by 75% to 265 million USD (151 million USD*). Proved oil and gas reserves were estimated at 22,758 (20,964*) thousand barrels of oil equivalent (« MBOE »). The increase in value and reserves resulted from successful drilling, an acquisition and higher oil and gas prices.

        In 2018, preliminary gross oil and gas production increased by 11% to approximately 272,000 (2017: 245,004) barrels of oil equivalent.

        Category Net reserves PV (10%)
        Oil, MBO Gas, MMCF MBOE Thousand USD
        Proved developed producing 1,834 8,951 3,326 49,972
        Proved developed non-producing 2,675 18,030 5,680 67,309
        Proved undeveloped 8,889 29,176 13,752 147,444
        Total proved 13,398 56,157 22,758 264,725

        In 2018, Matra drilled 17 and completed 16 production wells. One additional well was completed early in 2019. Proved developed producing reserves increased by 40%, from 2,378 MBOE to 3,326 MBOE, primarily as a result of the successful drilling campaign. In Q2, Matra acquired 40 oil and gas leases in the Texas Panhandle region, adding estimated proved reserves of 3,934 MBOE with a PV 10 of 40.3 million USD as per 31 December 2018.

        Gross oil and gas production amounted to 272 MBOE in 2018 and non-producing leases with reserves of approximately 1,900 MBOE mainly in the proved undeveloped category, included in previous reserve report, were deemed non-economical and relinquished.

        « In 2018, Matra’s producing reserve base further expanded through successful field development. Matra continues to create value through drilling and conversion of its substantial inventory of undeveloped oil and gas reserves into production » says Maxim Barskiy, CEO of Matra Petroleum AB.

        The estimate of reserves has been conducted by independent petroleum consultants DeGolyer and MacNaughton and was prepared in compliance with the United States Securities and Exchange Commission (SEC) regulations. Future prices were estimated using guidelines established by the SEC and FASB based on the 12 month average NYMEX oil and gas prices.

        *Previous third party reserve appraisal as per 30 November 2017

        For further information please contact:

        Maxim Barskiy, CEO, Matra Petroleum AB

        Tel.: +46 8 611 49 95

        This information is information that Matra Petroleum AB is obliged to make public pursuant to the EU Market Abuse Regulation. The information was submitted for publication, through the agency of the contact person set out above, on 16 January 2019, at 08:30 CET.

        About Matra Petroleum

        Matra Petroleum AB (publ) is a Swedish independent oil and gas exploration and production company operating in the United States, where the company owns and operates 170 leases, covering an area of 45,640 net acres in the Panhandle region in Texas. Matra’s reserves amount to 22.8 million barrels of oil equivalent. Matra Petroleum ‘s shares are traded on NASDAQ First North in Sweden under the symbol MATRA.Mangold Fondkommission AB is Certified Adviser (www.mangold.se,Tel: +46 (0) 8 50 30 1550, Email: CA@mangold.se).

        Web: www.matrapetroleum.com

        https://www.nasdaq.com/press-release/matra-petroleum-ab-2018-reserves-and-operations-update-20190116-00054


  • 2018


    • Cristo Rey and D&M

      août 30, 2018

      • For our second school year,  DeGolyer and MacNaughton has been a corporate job partner with Cristo Rey Dallas College Prep, participating in its Corporate Work Study Program. The Corporate Work Study Program is an innovative model of education that gives students a college-preparatory education while providing the opportunity to earn work experience in a corporate setting. Each year, Cristo Rey Dallas hosts an NFL-style draft that gives corporate job partners the opportunity to “draft” new students onto their corporate team. The Draft Day is a unique occasion for students to be recognized on an individual basis and to meet their new job partners.

        Cristo Rey Dallas College Prep is a private, independent Catholic high school located in the Pleasant Grove area of Southeast Dallas. Cristo Rey Dallas is part of the Cristo Rey Network, the only network of high schools in the country that integrates four years of rigorous college preparatory coursework with four years of professional work experience through a corporate work study program. Comprising 35 Catholic college preparatory schools that serve approximately 11,000 students across 22 states, the Cristo Rey Network delivers a powerful and innovative approach to inner-city education, equipping students from economically disadvantaged families with the knowledge, character, and skills to transform their lives.

        D&M has provided opportunities to six different Cristo Rey students through the Corporate Work Study Program. These students work 5 days a month to gain valuable skills in the areas of accounting, human resources, and business administration. Their duties span a wide range of activities, such as data entry, report processing, and other administrative activities.

        “Rarely do high school students have the opportunity to learn about the oil and gas industry, so D&M’s participation in the Corporate Work Study Program presents a very unique educational experience for the students,” said Austin Waugh, an accountant at D&M who has served as the firm’s Cristo Rey intern liaison. “Exposing the students to a professional office environment in their high school years will hopefully give them a level of familiarity with a professional office setting an advantage when it comes to pursuing job opportunities in the future.”

    • Valeura Announces Second Quarter 2018 Results and Restart of Operations at Yamalik-1

      août 9, 2018

      • CALGARY, Aug. 8, 2018 /CNW/ – Valeura Energy Inc. (TSX:VLE) (« Valeura » or the « Company« ) is pleased to report its financial and operating results for Q2 2018 and the restart of operations at the Yamalik-1 well. Yamalik production testing is the first step in the Company’s appraisal of its unconventional gas discovery in Turkey, which has been evaluated by DeGolyer and MacNaughton to hold 10.1 trillion cubic feet of estimated working interest unrisked mean prospective resources of natural gas.

        Valeura Energy Inc. (CNW Group/Valeura Energy Inc.)

        Financial and Operating Highlights for Q2:

        • Yamalik-1: Preparations for the Yamalik-1 long-term production test progressed smoothly throughout the quarter, including sourcing and importing suitable production testing equipment and constructing a pipeline to tie the well in to Valeura’s gathering and processing infrastructure. All required equipment is now onsite and operations have resumed.
        • BCGA appraisal drilling: Permitting of multiple well locations was completed in the quarter and procurement activities for the three well appraisal drilling program progressed on plan for a spud of the first well, Inanli-1, around the end of Q3 2018. Well site construction has commenced and the rig is currently being mobilized. The Company also selected the second appraisal well, Devepinar-1, which will be located in the West Thrace Lands 18km west of Yamalik-1.
        • Conventional gas: The Company’s shallow, conventional gas play continued to provide a modest, reliable production stream of 736 boe/d average production, generating revenue of C$2.9 million. The Company drilled the Karanfiltepe-7 commitment well, which was a gas discovery and is now tied in and producing.
        • Balance Sheet: Valeura’s Balance Sheet remained strong throughout the quarter, with an ending working capital position of C$60.3 million.

        « We have had an exciting quarter as the team prepares to begin appraisal operations on our 10 Tcf gas discovery in Turkey, » said Sean Guest, President and CEO, « I am very pleased to have our operations team back at work on the Yamalik-1 well, and look forward to seeing the results of our production testing in the coming weeks and months. In addition, we have made great progress in preparing for the appraisal drilling program.  All permits, approvals, and major contracts are in place with a plan to spud the first well, Inanli-1, at the end of Q3 2018. »

        « Our balance sheet remains in excellent shape, with enough working capital to see us through our share of the appraisal of the unconventional basin-centered gas accumulation (BCGA).  Additionally, recent moves by Turkey’s regulators to again increase Turkish gas prices has offset weakening in the Turkish Lira and continues to demonstrate that our selling price of natural gas in Turkey should remain approximately in line European import prices. This gives us more confidence than ever in the long-term value of our unconventional gas resources in Turkey. »

        FINANCIAL AND OPERATING RESULTS SUMMARY

        Table 1 Financial Results Summary

        Three Months Ended

        June 30, 2018

        Three Months Ended

        March 31, 2018

        Six Months Ended

        June 30, 2018

        Three Months Ended

        June 30, 2017

        Six Months Ended

        June 30, 2017

        Financial

        (thousands of CDN$ except share and per share amounts)

        Petroleum and natural gas revenues

        2,949

        3,469

        6,418

        3,764

        6,852

        Adjusted funds flow (used) (1)

        461

        545

        1,006

        959

        (1,924)

        Net loss from operations

        (1,404)

        (2,435)

        (3,839)

        (526)

        (2,527)

        Exploration and development capital

        1,128

        874

        2,002

        4,011

        5,943

        Acquisitions

        –

        –

        –

        –

        21,450

        Dispositions

        –

        –

        –

        (3,973)

        (26,288)

        Net working capital surplus

        60,296

        58,824

        60,296

        8,618

        8,618

        Cash

        55,945

        56,899

        55,945

        9,903

        9,903

        Common shares outstanding

        Basic

        86,136,988

        83,675,321

        86,136,988

        73,148,321

        73,148,321

        Diluted

        90,983,320

        90,973,321

        90,983,320

        79,731,821

        79,731,821

        Share trading

        High

        5.82

        8.27

        8.27

        0.85

        1.00

        Low

        3.97

        3.30

        3.30

        0.62

        0.62

        Close

        4.78

        4.14

        4.78

        0.70

        0.70

        Operations

        Production

        Crude oil (barrels (« bbl« )/d)

        9

        15

        12

        9

        6

        Natural Gas (one thousand cubic feet (« Mcf« )/d)

        4,360

        5,066

        4,711

        5,550

        5,189

        boe/d (@ 6:1)

        736

        859

        797

        934

        871

        Average reference price

        Brent ($ per bbl)

        96.23

        84.56

        90.32

        66.63

        68.82

        BOTAS Reference ($ per Mcf) (2)

        7.33

        7.49

        7.48

        7.47

        7.29

        Average realized price

        Crude oil ($ per bbl)

        95.77

        82.61

        87.59

        68.39

        69.64

        Natural gas ($ per Mcf)

        7.24

        7.37

        7.31

        7.34

        7.21

        Average Operating Netback

        ($ per boe @ 6:1) (1)

        22.53

        25.34

        24.05

        22.38

        25.26

        Notes:

        See the Company’s 2018 management’s discussion and analysis filed on SEDAR for further discussion.

        (1)

        The above table includes non-IFRS measures, which may not be comparable to other companies.  Adjusted funds flow is calculated as net income (loss) for the period adjusted for non-cash items in the statement of cash flows.  Operating netback is calculated as petroleum and natural gas sales less royalties, production expenses and transportation costs. 

        (2)

        Boru Hatlari ile Petrol Tasima Anonim Sirketi (« BOTAS« ) regularly posts prices and its Level-2 Wholesale Tariff benchmark is shown herein as a reference price.  See the Company’s 2017 annual information form (the « 2017 AIF« ) filed on SEDAR for further discussion.

         

        Net petroleum and natural gas sales in Q2 2018 averaged 736 boe/d, which was 14% lower than Q1 2018 and 21% lower than the same period last year.  While Valeura continues to manage its production operations including activities such as selective low-cost workovers, well abandonments, and drilling the Karanfiltepe -7 commitment well in its conventional gas fields, the Company is focusing its technical efforts and its capital allocation on appraisal of its BCGA play.

        Adjusted funds flow for Q2 2018 was  $0.5 million compared to  $1.0 million for the same period in 2017.  The decrease in adjusted funds flow in Q2 2018 was primarily due to lower revenues caused by lower production volumes partially offset by decreased production costs. Lower production is the result of significantly reduced drilling activity on the shallow conventional gas play in 2018 while the focus remains on the BCGA unconventional play.

        Net loss from operations was $1.4 million for Q2 2018, compared to a loss of $2.4 million in Q1 2018 and a loss of $0.5 million in Q2 2017.  The net loss is due to non-cash items including depletion and depreciation, accretion on decommissioning liabilities, share based compensation and deferred tax expense.

        2018 OUTLOOK

        Valeura is fully focused on appraising and de-risking its BCGA discovered by the Yamalik-1 well. The objective of the 2018 and 2019 work program is to demonstrate that over-pressured gas is pervasive across Valeura’s Thrace Basin lands and to show that commercial flow rates can be achieved. The key activities to support this objective are the tie-in and long-term testing of the Yamalik-1 well and a three well appraisal program.

        The Company has sourced production test equipment appropriate for the flow back of the Yamalik-1 well post fracing.  All required equipment has now arrived on the Yamalik-1 well site and operations have commenced. Assuming a successful test, the well will be immediately completed and tied in to Valeura’s gas infrastructure, with production sold to Valeura’s existing customers. The pipeline was completed and commissioned in advance of testing operations, so as to eliminate the need for gas flaring during the long-term test.

        Inanli-1 is the first well in the appraisal drilling program and is planned to be drilled to a depth of 5,000m. The well location is 6 km northeast of Yamalik-1 and has been selected to target an area of the play interpreted to have more natural fracturing of the reservoir than Yamalik-1.  All government permits have been received for the well location and construction of the well pad has commenced. KCA Deutag will provide a 2,000hp drilling rig for the three-well campaign and it is currently being mobilized to Turkey with expected arrival at the end of August. Other key long-lead items have been procured, with all equipment and services planned to be available for a spud of the well around the end of Q3 2018. Valeura is planning an extensive data acquisition program for the well, including more than 300m of core.  The well is expected to take approximately 80 days to drill and case for testing. Results of the well are expected in the second half of Q4 2018. With success, Inanli-1 will be fraced and flow tested in Q1 2019. Equinor will fund the drilling and testing of Inanli-1 which will fulfill their earning obligations under the Banarli farm-in agreement.

        Valeura and its partners have selected Devepinar-1 as the second well in the appraisal campaign. This well will be drilled approximately 18km west of Yamalik-1.  The location was selected as a significant step out from the Yamalik and Inanli sites to prove that the BCGA play is pervasive across to the west margin of the basin. Government permits have been received for the well location. Seven additional well locations have been approved by the government as potential sites for the third well.

        In the shallow, conventional gas production play, subsequent to the end of Q2, the Company completed the tie-in of the Karanfiltepe-7 well which was a gas discovery. The Company is also continuing with its plan of selective low-cost workovers throughout the conventional play, to slow the natural decline from the existing fields.

        In all its activities, the Company remains committed to continuing its safe operations and ensuring that operational and administrative functions are conducted in the most cost-efficient way.

        ABOUT THE COMPANY

        Valeura Energy Inc. is a Canada-based public company currently engaged in the exploration, development and production of petroleum and natural gas in Turkey.

        OIL AND GAS ADVISORIES

        Boes

        A boe is determined by converting a volume of natural gas to barrels using the ratio of 6 Mcf to one barrel. boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Further, a conversion ratio of 6 Mcf:1 boe assumes that the gas is very dry without significant natural gas liquids. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

        ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION

        This news release contains certain forward-looking statements and information (collectively referred to herein as « forward-looking information« ) including, but not limited to: Valeura’s view that it has discovered a world-class unconventional gas play; the costs, timelines and objectives for the deep drilling and BCGA appraisal program in 2018 and 2019; the timing, cost and construction to tie-in and conduct a long term production test and achieve natural sales from the Yamalik-1 well; the timing of the spudding of the Inanli-1 well;;  the potential for a BCGA play in the Thrace Basin; the timing and completion of the delineation drilling campaign and related procurement activities (including the anticipated rig contract); management’s belief regarding the potential of the Company’s deep BCGA play and shallow gas business in the Thrace Basin; Valeura’s commitment to safety and optimizing operational and administrative functions; Valeura’s business strategy and outlook; the use of proceeds from the financing that closed on March 1, 2018 and the ability to finance future developments. Forward-looking information typically contains statements with words such as « anticipate », estimate », « expect », « target », « potential », « could », « should », « would » or similar words suggesting future outcomes. The Company cautions readers and prospective investors in the Company’s securities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company.

        Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: political stability of the areas in which the Company is operating and completing transactions; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the Turkish government in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the prospectivity of the deep BCGA and shallow gas plays on the TBNG joint venture lands and Banarli licences; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licences and leases; and the Company’s continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Company’s work programs and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, fracing and other specialized oilfield equipment and service providers, changes in partners’ plans and unexpected delays and changes in market conditions. Although the Company believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

        Forward-looking information involves significant known and unknown risks and uncertainties. A number of factors could cause actual results to differ materially from those anticipated by the Company including, but not limited to: the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the contemplated timelines for the timelines and costs for the deep evaluation in 2018 and 2019; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues, terrorist attacks, insurgencies or civil unrest in Turkey; political stability in Turkey, including potential changes in Turkey’s political leaders or parties or a resurgence of a coup or other political turmoil; the uncertainty regarding government and other approvals; counterparty risk; potential changes in laws and regulations; and the risks associated with weather delays and natural disasters; the risk associated with international activity. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. See the 2017 AIF for a detailed discussion of the risk factors.

        Additional information relating to Valeura is also available on SEDAR at www.sedar.com

        SOURCE Valeura Energy Inc. https://markets.businessinsider.com/news/stocks/valeura-announces-second-quarter-2018-results-and-restart-of-operations-at-yamalik-1-1027444540

    • SEFI – Reserves and Resources Evaluation Class, Mexico City August 8-9, 2018

      juillet 19, 2018

      • D&M is doing its second reserves and resources evaluation class in Mexico City on August 8-9, 2018, as a donation to the society of former alumni of the engineering school at UNAM university (SEFI). The class will be led by Federico Dordoni, VP and Staff Engineer of D&M. The class is structured such that both technical and non-technical personnel will be able to comprehend and utilize reserves and resources reports.

        http://sefi.org.mx/index/evento

    • Case Study: DeGolyer and MacNaughton Workflow for Well Performance Analysis, Fracture Modeling and Completion Design

      juin 17, 2018

    • Gazprom Neft improves efficiency in developing the Priobskoye field together with D&M Corp

      juin 1, 2018

      • Gazprom Neft has entered into an agreement with American corporation DeGolyer and MacNaughton Corp. on the selection and utilisation of innovative enhanced oil recovery (EOR) techniques at its Priobskoye field, in a document signed at this year’s St Petersburg International Economic Forum by Vadim Yakovlev, First Deputy CEO, Gazprom Neft, and Martin Wiewiorowski, Director of D&M’s Russian Branch.

        Under this agreement DeGolyer and MacNaughton specialists will, throughout 2018–2020, analyse the history of the Priobskoye field since its discovery, assess the potential for increasing production and increasing the oil recovery factor (ORF), formulate recommendations for realising this potential, and address immediate challenges and problems in developing the Yuzhny (Southern) licence block at the Priobskoye field. On the basis of this data, plans for pilot works and further geological prospecting at the asset will be put in place.

        In addition to this, the process of analysing the appropriate cutting-edge technologies to be used will be initiated, and alternative approaches to solving field development problems developed. A programme for the further professional development of Gazprom Neft specialists will also be put in place.

        According to Gazprom Neft specialists, the full implementation of programmes developed under the agreement with D&M will allow reserves at the Priobskoye field to be brought into development, will enhance oil recovery through existing well stock, and will increase the ORF by five to six percent.

        DeGolyer and MacNaughton plans to open an office in St Petersburg in 2018 in order to undertake implementation of this project.

        Vadim Yakovlev, First Deputy CEO, Gazprom Neft, commented: Gazprom Neft has been working with DeGolyer and MacNaughton for more than 10 years. The unique competencies accumulated by the company during annual reserves audits has become a key component in our joint project to study the potential of the Priobskoye field, initiated in 2016. I have every confidence that this new agreement will allow our companies to further strengthen their cooperation and, ultimately, significantly improve efficiency in developing one of our largest production assets. »

        http://www.gazprom-neft.com/press-center/news/1646776/

    • Gazprom Neft improves efficiency in developing the Priobskoye field together with D&M Corp

      juin 1, 2018

      • As one of the leading independent consulting firm focused on the petroleum industry, DeGolyer and MacNaughton provides unbiased and informed answers to clients worldwide. D&M skilfully blends energy economics, engineering, and the earth sciences to help clients in more than 100 countries make the smartest decisions regarding exploration, recovery, and management of oil and gas resources.

        The firm’s services include resources assessments, reserves consulting, reservoir modelling, geologic and petrophysical analyses, development planning, guidance with financial reporting issues, and financial forecasting for petroleum discoveries. DeGolyer and MacNaughton has the largest, most experienced team of professional reservoir consultants in the industry. D&M has built up extensive international experience in independent reserves assessments, the results of which are frequently used in certifying projects for presentation to financial institutions worldwide.

        Gazprom Neft is a vertically integrated oil company, primarily involved in oil and gas exploration and production, refining, and the production and sale of oil products. The Gazprom Neft’s corporate structure comprises more than 70 production, refining and sales subsidiaries throughout Russia, the CIS, and abroad.

        The company’s proved and probable reserves (SPE-PRMS) are estimated at 2.78 billion tonnes of oil equivalent (btoe), making Gazprom Neft one of the top-20 largest oil and gas companies in the world, and one of Russia’s top three largest companies in terms of production and refining volumes. Total production in 2017 reached 89.75 million tonnes of oil equivalent (mtoe), with refining volumes of 40.1 million tonnes.

        Gazprom Neft products are exported to more than 50 countries worldwide, and sold throughout the Russian Federation and abroad. The company’s filling station network totals more than 1,850 outlets throughout Russia, the CIS and Europe.

        Gazprom Neft’s net profit in 2017 was RUB253 billion — a 26.5-percent increase year-on-year. The company is an industry market leader in terms of both financial growth and various efficiency metrics, including its internal rate of return (IRR).

        The company’s main shareholder is Gazprom PJSC, which has a 95.68-percent interest, with the remaining shares in free circulation.

        http://www.einnews.com/pr_news/449447502/gazprom-neft-improves-efficiency-in-developing-the-priobskoye-field-together-with-degolyer-and-macnaughton-corp

    • DeGolyer & MacNaughton to study Priobskoye EOR

      juin 1, 2018

      • Gazprom-Neft has entered an agreement with DeGolyer & MacNaughton Corp., Dallas, on the selection and use of enhanced oil recovery methods for giant Priobskoye field in the Khanti-Mansi Autonomous District of West Siberia.

        The Russian company said DeGolyer & MacNaughton will “analyze the history of the Priobskoye since its discovery, assess the potential for increasing production and increasing the oil recovery factor, formulate recommendations for realizing this potential, and address the immediate challenges and problems in developing the Yuzhny (Southern) license block” of the field. The work will occur during 2018-20.

        In an April 2016 announcement about production of the 100 millionth tonne of oil from Yuzhno-Priobskoye, Gazprom-Neft said the field, known to have complex geology, was producing 32,000 tonnes/day from 2,000 wells.

        https://www.ogj.com/articles/2018/05/degolyer-macnaughton-to-study-priobskoye-eor.html

    • Forecasting Well Production Data in Unconventional Resources – Dr. Dilhan Ilk

      mai 7, 2018

      • Short Course 4

         Saturday, 21–Sunday, 22 July 2018

        Objectives

        Production analysis and forecasting in unconventional resources are challenging tasks due to the high degree of uncertainty and non-uniqueness associated with evaluating well completion and understanding reservoir properties. This course provides guidelines on the interpretation of data behavior and a consistent approach to analyze and forecast production in unconventional resources.

        Who Should Attend

        This course is intended for technologists, engineers, and managers involved in evaluating well performance (time-rate-pressure) data for optimizing production, understanding completion efficiency, and estimating reserves and ultimate recoveries.

        Course Content

        This course provides a comprehensive methodology for the diagnosis, analysis, and forecasting of well production data in unconventional resources. An extensive evaluation of the diagnostic tools for assessing data viability, checking data correlation along with flow regime identification is presented. The principal focus is to diagnose the characteristic flow regimes associated with well production and apply methodologies to estimate performance parameters and forecast production. These methodologies include simple analytical tools, decline curves, and more complex techniques such as nonlinear numerical simulation. Examples from tight gas sands, gas shales, and liquids-rich shale systems will illustrate the theoretical considerations and practical aspects.

        Topics Include:

        • Collect, analyze, and interpret critical data for well performance analysis
        • Identify well performance characteristics and flow regimes using diagnostic plots
        • Estimate key reservoir and completion parameters
        • Forecast future performance for various production/completion and field development scenarios
        • Establish the optimal workflow to help quantify well performance uncertainty and non-uniquenes

        Dilhan Ilk is a reservoir engineer at DeGolyer and MacNaughton in Dallas, Texas. Ilk’s interests include analysis of well test and production data, reservoir engineering, and inverse problems. In particular, he focuses on well performance analysis in unconventional reservoirs and has extensive field experience in well performance assessment of unconventional reservoirs. He has made several contributions to petroleum engineering literature, and to date, has prepared more than 30 articles in well test analysis, analysis/interpretation of production data, and general reservoir engineering. Ilk holds a BS from Istanbul Technical University, and MS and PhD degrees from Texas A&M University—all in petroleum engineering.

        http://urtec.org/2018/Technical-Program/Short-Courses

    • Navitas says Gulf of Mexico field has 155 mln barrels of oil

      mai 7, 2018

    • EOG Resources: Reports Fourth Quarter and Full 2017 Results

      avril 13, 2018

      • « For the 30th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton. »

        EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth quarter 2017 net income of $2,430 million, or $4.20 per share. This compares to a fourth quarter 2016 net loss of $142 million, or $0.25 per share.  For the full year 2017, EOG reported net income of $2,583 million, or $4.46 per share, compared to a net loss of $1,097 million, or $1.98 per share, for the full year 2016.

        Adjusted non-GAAP net income for the fourth quarter 2017 was $401 million, or $0.69 per share, compared to an adjusted non-GAAP net loss of $7 million, or $0.01 per share, for the same prior year period.  Adjusted non-GAAP net income for the full year 2017 was $648 million, or $1.12 per share, compared to an adjusted non-GAAP net loss of $893 million, or $1.61 per share, for the full year 2016.  Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items.  One of the adjusting items in the fourth quarter and full year 2017 was a non-cash reduction in income tax expense of $2.2 billion, or $3.75 per share, related to the revaluation of EOG’s deferred tax liability and certain other items resulting from the Tax Cuts and Jobs Act.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

        Higher commodity prices, increased production volumes, well productivity improvements and per-unit cost reductions resulted in significant increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX for the fourth quarter 2017 compared to the fourth quarter 2016.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

        Operational Highlights
        Crude oil and condensate volumes in the U.S. increased 20 percent in 2017 to 335,000 barrels of oil per day (Bopd).  Increased development activity and well productivity improvements supported the volume increase.  Total company natural gas liquids (NGLs) volumes grew 8 percent while natural gas volumes decreased 6 percent primarily due to the sale of the company’s Barnett and Haynesville Shale dry gas assets in late 2016.  Transportation expenses decreased 11 percent and depreciation, depletion and amortization expenses decreased 12 percent, on a per-unit basis.

        Increased development activity drove substantial volume increases in the Eagle Ford and Delaware Basin during the fourth quarter.  Total company crude oil and condensate volumes increased 40,200 Bopd compared to the third quarter 2017.  Natural gas liquids volumes grew 15 percent while natural gas volumes increased 6 percent, compared to the third quarter 2017.

        « EOG emerged from the industry downturn in 2017 with unprecedented levels of efficiency and productivity, driving oil production volumes to record levels with capital expenditures approximately one half the prior peak, » said William R. « Bill » Thomas, Chairman and Chief Executive Officer.  « EOG’s integrated teams demonstrated superb operational performance, overcoming a major hurricane and other challenges to deliver record production volumes and cost savings which surpassed original targets set at the beginning of the year. »

        2018 Capital Plan
        EOG’s disciplined capital plan is designed to achieve strong returns on capital employed and healthy growth while spending within cash flow.  The company expects to grow total company crude oil volumes by 18 percent, generate double-digit ROCE and cover capital investment and dividend payments within discretionary cash flow.  EOG can deliver on its 2018 plan at oil prices below $50 and generates significant free cash flow at a $60 oil price.

        EOG’s return-based culture continues to drive cost reductions.  The company targets lower well costs and per-unit operating expenses in 2018 despite a potentially inflationary operating environment.  EOG is also focused on driving continued improvements in well productivity and pursuing exploration efforts in new plays.

        Capital expenditures for 2018 are expected to range from $5.4 to $5.8 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions.  EOG expects to complete approximately 690 net wells in 2018, compared to 536 net wells in 2017.  Capital will be allocated primarily to EOG’s highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and the Bakken.

        At least 90 percent of the wells completed in 2018 are expected to be premium.  EOG has an inventory of approximately 8,000 such wells, which have a direct after-tax rate of return of at least 30 percent assuming $40 flat crude oil prices and $2.50 flat natural gas prices.

        « EOG enters 2018 better positioned than ever to generate significant shareholder value through the development of its large and diverse inventory of high rate-of-return premium wells, » Thomas said.  « We are determined to maintain the discipline, record-level operational efficiency and performance gained through the downturn.  Our deep inventory of premium wells across the U.S. offers flexibility to adjust to changing conditions.  We also see significant opportunities to increase our premium well inventory through organic exploration and development technology to further extend EOG’s return on capital advantage. »

        Dividend Increase
        The board of directors increased the cash dividend on the common stock by 10.4 percent.  Effective with the dividend payable April 30, 2018, to stockholders of record as of April 16, 2018, the board declared a quarterly dividend of $0.185 per share on the common stock.  The indicated annual rate is $0.74 per share.

        Delaware Basin
        2017 was a watershed year for EOG in the Delaware Basin, where it successfully integrated the Yates acquisition, identified 1,240 additional net premium well locations, added the First Bone Spring as its fourth premium play and reduced completed well costs by $800,000 per well.  Delaware Basin crude oil and condensate volumes increased over 80 percent in 2017 and exceeded 100,000 Bopd in the fourth quarter 2017.

        EOG continued active development of its 416,000 net acre position in the Delaware Basin in the fourth quarter 2017, completing 65 wells.

        In the Delaware Basin Wolfcamp, in Lea County, NM, EOG completed a four-well package, the Calm Breeze 2 Fed Com #701-704H, with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 2,605 Bopd, 440 barrels per day (Bpd) of NGLs and 3.7 million cubic feet per day (MMcfd) of natural gas.

        In the Delaware Basin First Bone Spring, in Lea County, NM, EOG completed the Righteous 6 State Com #301H with a treated lateral length of 7,100 feet and 30-day initial production rate of 1,305 Bopd, 170 Bpd of NGLs and 1.4 MMcfd of natural gas.

        In the Delaware Basin Leonard, in Loving County, TX, EOG completed a four-well package, the State Atlas A#3H – D#6H, with an average treated lateral length of 9,800 feet per well and average 30-day initial production rates per well of 1,215 Bopd, 270 Bpd of NGLs and 2.3 MMcfd of natural gas.

        South Texas Eagle Ford and Austin Chalk
        EOG continues to enhance the productivity of its bellwether asset in the South Texas Eagle Ford.  Eight years after initiating development, EOG further reduced well costs and improved well performance during 2017 in its 520,000 net acre position in the crude oil window of this world class play.  EOG also expanded its enhanced oil recovery program, adding 56 wells last year.  For the full year 2017, crude oil production in the Eagle Ford and Austin Chalk increased one percent year-over-year despite interruption to producing volumes as a result of Hurricane Harvey.

        In the fourth quarter, EOG completed 74 wells in the Eagle Ford.  These included 13 wells with lateral lengths of more than 10,000 feet.  In LaSalle County, EOG completed a four-well package, the White 5H-8H, with an average treated lateral length of 12,900 feet per well and average 30-day initial production rates per well of 1,545 Bopd, 80 Bpd of NGLs and 0.5 MMcfd of natural gas.  In DeWitt County, EOG completed a four-well package, the Hendrix 8H-10H and the Hendrix 12H, with an average treated lateral length of 6,700 feet per well and average 30-day initial production rates per well of 2,545 Bopd, 420 Bpd of NGLs and 2.4 MMcfd of natural gas.

        EOG continued to test its position in the South Texas Austin Chalk, a geologically complex formation which lies above the South Texas Eagle Ford, completing four net wells in the fourth quarter.

        Rockies
        EOG’s Wyoming Powder River Basin and DJ Basin activity both contributed to the company’s 2017 crude oil production growth.  In the Powder River Basin, EOG continued exploration activity on its 400,000 net acre position in the core of the play.  The company tested the prospectivity of multiple target zones and also tested the aerial extent of various targets in the Powder River Basin during the year.  In the DJ Basin, EOG achieved significant well cost reductions during 2017 through a focus on efficiency improvements in drilling and completion operations.

        In the fourth quarter, EOG completed nine wells in the Powder River Basin.  In Converse County, EOG completed the Mary’s Draw 453-0310H and 455-0310H wells with an average treated lateral length of 7,300 feet per well and average 30-day initial production rates per well of 1,280 Bopd, 610 Bpd of NGLs and 7.6 MMcfd of natural gas.  In the DJ Basin, EOG completed three wells in the fourth quarter.  This included the Big Sandy 522-2536H with a treated lateral length of 8,800 feet and 30-day initial production rate of 1,100 Bopd, 110 Bpd of NGLs and 0.2 MMcfd of natural gas.

        Reserves
        At year-end 2017, total company net proved reserves were 2,527 million barrels of oil equivalent (MMBoe), an increase of 18 percent compared to year-end 2016.  Net proved reserve additions from all sources, excluding revisions due to price, replaced 201 percent of EOG’s 2017 production at a finding and development cost of $8.71 per barrel of oil equivalent.  Revisions due to price increased net proved reserves by 154 MMBoe and asset divestitures decreased net proved reserves by 21 MMBoe.  (For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.)

        For the 30th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.

        Hedging Activity
        During the fourth quarter ended December 31, 2017, EOG entered into crude oil financial price swap contracts and differential basis swap contracts.  A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.

        Capital Structure and Asset Sales
        At December 31, 2017, EOG’s total debt outstanding was $6.4 billion with a debt-to-total capitalization ratio of 28 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG’s net debt was $5.6 billion with a net debt-to-total capitalization ratio of 25 percent.  For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

        Proceeds from asset sales for the full year 2017 totaled $227 million.

        Conference Call February 28, 2018
        EOG’s fourth quarter and full year 2017 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, February 28, 2018.  To access the live audio webcast and related presentation materials, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.

        EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China.  EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol « EOG. »  For additional information about EOG, please visit www.eogresources.com.

        This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG’s future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG’s management for future operations, are forward-looking statements.  EOG typically uses words such as « expect, » « anticipate, » « estimate, » « project, » « strategy, » « intend, » « plan, » « target, » « goal, » « may, » « will, » « should » and « believe » or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.  In particular, statements, express or implied, concerning EOG’s future operating results and returns or EOG’s ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Moreover, EOG’s forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG’s control.  Furthermore, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position.  These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented.  EOG’s actual results may differ materially from the measure and estimates presented or referenced herein.  Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward-looking statements include, among others:

        • the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;
        • the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
        • the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;
        • the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;
        • the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, transportation and refining facilities;
        • the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses and leases;
        • the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
        • EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
        • the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully and economically;
        • competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;
        • the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;
        • the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
        • weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;
        • the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
        • EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
        • the extent to which EOG is successful in its completion of planned asset dispositions;
        • the extent and effect of any hedging activities engaged in by EOG;
        • the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
        • political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;
        • the use of competing energy sources and the development of alternative energy sources;
        • the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
        • acts of war and terrorism and responses to these acts;
        • physical, electronic and cyber security breaches; and
        • the other factors described under ITEM 1A, Risk Factors, on pages 14 through 23 of EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, and any updates to those factors set forth in EOG’s subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

        In light of these risks, uncertainties and assumptions, the events anticipated by EOG’s forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG’s forward-looking statements. EOG’s forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

        The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only « proved » reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also « probable » reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as « possible » reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves).  Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include « potential » reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines.  Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

        http://investors.eogresources.com/2018-02-27-EOG-Resources-Reports-Fourth-Quarter-and-Full-Year-2017-Results-and-Announces-2018-Capital-Program

    • 80 billion barrels of ‘oil in place’ identified in Bahrain

      avril 4, 2018

      • Manama, Apr. 4 (BNA): Bahrain’s National Oil and Gas Authority (NOGA), alongside international consultants DeGolyer and MacNaughton, Halliburton, and Schlumberger, today provided new details on the Kingdom’s largest ever discovery of oil and gas, with tight oil amounting to at least 80 billion barrels.
        The discovery, made within the 2,000 km2 Khalij Al-Bahrain Basin, is located in shallow waters off the Kingdom’s west coast, close to a fully-operational oil field with ready-to-connect-to facilities, according to Halliburton, who added that this unique factor provides potential for significant cost optimisation.

        A separate discovery of significant gas reserves in two accumulations below Bahrain’s main gas reservoir has been confirmed.

        Extensive work has already been carried out to evaluate in-place volumes. The first well in the drilling programme is planned to produce in August, and over the next two years focus will be given to maximising production and commercial efficiency.

        Announcing the size and content of the discovered resources, Bahrain’s Minister of Oil, Shaikh Mohammed bin Khalifa Al Khalifa, said: « DeGolyer and MacNaughton’s and Haliburton’s independent appraisals have confirmed NOGA’s find of highly significant quantities of oil in-place for the Khalij Al Bahrain, with tight oil amounting to at least 80 billion barrels, and deep gas reserves in the region of 10-20 trillion cubic feet.

        « Agreement has been reached with Halliburton to commence drilling on two further appraisal wells in 2018, to further evaluate reservoir potential, optimise completions, and initiate long-term production, » the Minister added.

        « Oil in place of 80 billion barrels is based on a P50 resource estimate, » said DeGolyer and MacNaughton Senior Vice president, Dr John Hornbrook, speaking at today’s press conference. Dr Hornbrook added that « the discovery breaks new ground for the Bahrain oil and gas industry using established technologies. »

        Positive test well results have successfully demonstrated the productivity of the significant resource, with Schlumberger, who performed the first test well drilling, adding that Bapco has already succeeded in flowing high quality oil from the wells during the testing and flow back phases. « Based on the core analysis carried out on several wells the formation could be classified at the edge of the conventional-unconventional type of plays, » a Schlumberger spokesperson noted.

        Bapco Chief Exploration Geologist in charge of the discovery, Yahya Al Ansari, added that « the presence of a layer with moderate conventional reservoir properties on top of an organic-rich source rock creates a unique self-sourcing and trapping system, enhancing production and economic viability. The confirmation of this significant resource highlights the vast E&P (exploration and production) potential and opportunities in Bahrain. »

        The newly-discovered resource, which officials expect to be ‘on production’ within five years, is expected to provide significant and long-term positive benefits to the Kingdom’s economy – both directly and indirectly through downstream activities in related industries.

        NOGA added that the next stage of development will focus on ensuring robust frameworks, data and terms are in place to facilitate further activities and commercial opportunities with international partners.

        http://www.bna.bh/portal/en/news/834702

    • Bahrain’s Biggest Oil Find Since 1932 Dwarfs Reserves

      avril 1, 2018

      • Bahrain, the smallest energy producer in the Persian Gulf, discovered its biggest oil field since it started producing crude in 1932, according to the country’s official news agency.

        The shale oil and natural gas discovered in a deposit off the island state’s west coast “is understood to dwarf Bahrain’s current reserves,” Bahrain News Agency reported, without giving figures. U.S. consultants DeGolyer & MacNaughton Corp. evaluated the field, and Bahrain plans to provide additional details on Wednesday about the reservoir’s “size and extraction viability,” BNA reported.
        Bahrain’s energy industry is overshadowed by the world’s biggest oil and gas producers. It sits between Saudi Arabia, the largest oil exporter, and Qatar, the biggest shipper of liquefied natural gas. Bahrain has crude reserves of 124.6 million barrels — fewer than Poland — and 92.03 billion cubic meters of natural gas, according to the U.S. CIA Factbook. Saudi Arabia, by comparison, has 266.5 billion barrels of crude reserves, while Qatar has 24.3 trillion cubic meters of gas.
        The find could “provide a much needed boost to Bahrain’s fiscal accounts,” Ehsan Khoman, head of research for the Middle East and North Africa at Mitsubishi UFJ in Dubai, said Monday. “However, it is too early at the current juncture to estimate the potential increase in hydrocarbon receipts until further guidance is provided.”

        Bahrain Field

        It is currently bound by the global agreement among major oil producers to limit production to reduce global inventories.

        “Initial analysis demonstrates the find is at substantial levels, capable of supporting the long-term extraction of tight oil and deep gas,” Bahrain Oil Minister Shaikh Mohammed bin Khalifa Al Khalifa said in the BNA report.

        Bahrain’s revenue from oil and gas dropped 43 percent from 2013 to 2016, according to most recent data available from the Finance Ministry, as crude prices slumped as much as 77 percent. With energy sales accounting for 87 percent of the government’s total income for 2016, Bahrain is trying to diversify its economy and borrow funds to ease pressure on its public finances.

        https://www.bloomberg.com/news/articles/2018-04-01/bahrain-says-its-biggest-oil-find-since-1932-dwarfs-reserves

    • DNO ASA 2017 Annual Statement of Reserves and Resources

      mars 16, 2018

      • DNO ASA, the Norwegian oil and gas operator, today released its 2017 Annual Report and Accounts together with its 2017 Annual Statement of Reserves and Resources, reporting an increase in operating profit and improvements across other key financial and operational metrics.

        Founded in 1971 and listed on the Oslo Stock Exchange with the code DNO. OL, the company holds stakes in onshore and offshore licences at various stages of exploration, development and production in the Kurdistan region of Iraq, Yemen, Oman, the United Arab Emirates, Tunisia and Somaliland. Its largest shareholder is UAE-based RAK Petroleum.

        Annual 2017 revenues climbed to US$ 347 million, up 72 percent from the 2016 figures, the company said. Operating profit totalled US$ 521 million, up from US$ 6 million in 2016, with the recognition as other income of US$ 556 million under the August 2017 Kurdistan Receivables Settlement Agreement. Excluding the settlement agreement and non-cash impairments, DNO operating profit in 2017 more than doubled to US$ 72 million. Although operational expenditure last year reached US$ 259 million, double the 2016 figure, the company ended 2017 with a cash balance of USD 430 million.

        Company Working Interest, CWI, production increased to 73,700 barrels of oil equivalent per day (boepd) from 69,200 boepd in 2016. Total production from DNO-operated fields, including those in which other companies have stakes, rose to 113,500 boepd in 2017, up from 112,600 boepd in 2016. Lifting costs last year averaged US$ 3.6 per barrel of oil equivalent.

        DNO’s production continues to be driven by the Tawke field in Kurdistan, where output in 2017 averaged 105,500 barrels of oil per day (bopd). The adjacent Peshkabir field, brought on stream in the middle of 2017, contributed another 3,600 bopd to bring total Tawke licence production to 109,100 bopd for the year. DNO plans to boost production from this licence area in 2018 by drilling ten new wells, the report said.

        “We are committed this year (2018) to continue to outdrill, outproduce and outperform all other international companies in Kurdistan – combined,” DNO’s Executive Chairman, Bijan Mossavar-Rahmani, commented.

        At year end 2017, DNO’s CWI 1P reserves climbed to 240 million barrels of oil equivalent (MMboe) from 219 MMboe at year end 2016, after adjusting for production during the year, technical revisions and an increase in DNO’s operated stake in the Tawke licence from 55 percent to 75 percent under the terms of the August 2017 agreement. On a 2P basis, DNO’s CWI reserves stood at 384 MMboe (up from 368 MMboe) and on a 3P basis, DNO’s CWI reserves stood at 666 MMboe (up from 521 MMboe). DNO’s yearend 2017 CWI contingent resources (2C) were estimated at 99 MMboe, down from 161 MMboe at yearend 2016, following reclassification of certain contingent resources to reserves.

        On a gross basis, at year end 2017, 1P reserves at the Tawke licence, containing the Tawke and Peshkabir fields, totalled 348 MMboe (353 MMboe at yearend 2016) after adjusting for production of 40 MMboe during the year and technical revisions; 2P reserves totalled 513 MMboe (536 MMboe at yearend 2016); 3P reserves totalled 880 MMboe (725 MMboe at yearend 2016) and 2C resources totaled 91 MMboe (211 MMboe at yearend 2016) following reclassification.

        International petroleum consultants DeGolyer and MacNaughton carried out The annual independent assessment of the Tawke and Peshkabir fields was carried out by international petroleum consultants DeGolyer and MacNaughton, while DNO internally evaluated the remaining assets.

        By Shayne Heffernan on

        http://www.livetradingnews.com/dno-asa-2017-annual-statement-of-reserves-and-resources-78014.html#.Wqu7cXwh3mE

         

    • The Outdoor Classroom Seminar: Integrated Reservoir Appraisal and Reservoir Modeling

      février 23, 2018

      • What you will learn: Through this immersive field-based seminar, students will improve their understanding of modeling and their abilities to model geological features affecting reservoir performance through the collection, observation, interpretation, and modeling of geologic, petrophysical, and engineering data. Seminar instructors will present methods for collecting, analyzing, and interpretating data to most efficiently appraise reservoir size and characteristics. Over the course of the seminar, students will visit outcrops that reveal the complex but interpretable geologic features that influence reservoir development. These outcrop observations, along with wireline log data, petrophysical data collected from nearby boreholes, will be incorporated into the geocellular models that must be developed and simulated during the 5-day course.

        Who Should Attend: This course is designed for petroleum engineers, geologists, geophysicists, petrophysicists, and supervisory personnel responsible for executing field-development programs focused on primary, secondary, or tertiary-recovery projects in conventional terrigineous-clastic reservoirs. The geologic and engineering concepts and practices introduced in the seminar are applicable to reservoirs spanning all depositional settings.

        See Brochure Link for more details! Integrated Reservoir Appraisal and Development Seminar Final

        Costs: TBD per person and includes:

        • 5 day seminar
        • Field guide and exercise materials
        • Transportation during seminar
        • Lunch, snacks, and drinks during the seminar

                   Additional costs (responsibility of attendees)

        • Transportation to and from Salt Lake City, Utah on May 6, returning May 12.
        • Meals other than lunch during the five-day course
        • Hotel costs

    • Gazprom Neft: Reserves Replacement at 170%

      février 22, 2018

      • Gazprom Neft:  Reserves Replacement at 170%

        Gazprom Neft has completed auditing of the company’s hydrocarbon reserves as at 2017. As at 31 December 2017 the company’s total proved and probable hydrocarbon reserves (proved + probable — 2P based on SPE-PRMS international standards,* including proportional shares in production at joint enterprises**) totalled 2.78 billion tonnes of oil equivalent (toe) — a year-on-year increase of 2.3 percent. Production volumes in 2017, at 89.75 mtoe, were compensated by reserves replacement in the order of 170 percent. The audit was undertaken by independent international consulting company DeGolyer and MacNaughton.

        Proved 1P hydrocarbons as at end 2017 are estimated at 1.52 btoe — an increase of 0.6 percent, year-on-year. The reserve replacement ratio for this category of reserves is 110 percent Gazprom Neft’s reserves-to-production ratio in terms of proved hydrocarbon reserves (SPE-PRMS standards) is 17 years. According to SEC standards,*** the company’s total hydrocarbon reserves stand at 1.34 mtoe (an increase of 3.4 percent over 2017).

        Drilling of 27 prospecting and exploratory wells was completed in this accounting period, with drilling meterage in 2017 increasing by 41.2 percent (to 94,600 metres). Four new wells and 42 hydrocarbon deposits were discovered last year throughout the group’s licence blocks.

        A key positive factor in allowing the company to expand its resources base has been the fine-tuning of technologies in geological prospecting and development drilling, together with the implementation of dynamic ranking for all company options. Gazprom Neft’s new assets — including the Tazovskoye, Severo-Samburgskoye and Kamennomysskoye fields — have all made a major contribution to expanding the company’s resource base.

        An assessment of prospective resources at Gazprom Neft’s licence blocks on the Arctic Shelf was undertaken for the first time in 2017, with DeGolyer and MacNaughton estimating these at 1.6 billion tonnes of oil and three trillion cubic metres of gas.

        Vadim Yakovlev, First Deputy CEO, Gazprom Neft, commented: «Gazprom Neft last year continued its consistent development of its upstream projects, as well as undertaking work on accessing new licence blocks. Major discoveries were confirmed, which have made the company’s resource base still more balanced and high-quality. The company’s priority development vectors continue to include improving quality in the development of new reserves, active work in studying low-permeability strata, and implementing a programme for improving efficiency in production in those regions in which the company has traditionally operated.»

    • Abraxas Provides Reserve and Operational Update

      février 20, 2018

      • SAN ANTONIO–(BUSINESS WIRE)–Abraxas Petroleum Corporation (“Abraxas” or the “Company”) (NASDAQ:AXAS) today provided the following reserve and operational update. Highlights include:

        • Total proved reserves as of December 31, 2017 of 65.9 MMBoe up 21.2 MMBoe or 47.5%
        • Proved developed producing (“PDP”) reserves grew 48.5% to 20.7 MMBoe
        • PV-10 (1) of $425.9 million using SEC 12-month average pricing of $51.34/bbl and $2.99/mcf natural gas
        • 2017 reserve replacement ratio of 887%
        • 2017 PDP finding and development (“PDP F&D”) cost of $10.42/Boe
        • In the Delaware Basin, Abraxas booked 17 gross Wolfcamp A1, 17 gross Wolfcamp A2, two gross Wolfcamp B and two gross Third Bone Spring proved undeveloped locations across four gross sections at Caprito (1320 foot spacing assumed)
        • In the Delaware Basin, Abraxas booked an additional eight gross Third Bone Spring, Wolfcamp A1 and Wolfcamp A2 proved undeveloped locations across four additional gross sections
        • Potential downspacing and the remainder of Abraxas’ leasehold in the Delaware Basin remains unbooked for future years
        • In Ward County, Texas, the Caprito 82-101, a 4,820 foot lateral and the Company’s first Third Bone Spring well, averaged 1,122 Boepd (878 barrels of oil per day, 1,463 mcf of natural gas per day)(2) over the well’s first 30 days of production
        • In Ward County, Texas, the Caprito 82-202, a 4,820 foot lateral targeting the Wolfcamp A1, averaged 1,134 Boepd (863 barrels of oil per day, 1,626 mcf of natural gas per day)(2) over the well’s first 30 days of production

        https://www.businesswire.com/news/home/20180220005422/en/Abraxas-Reserve-Operational-Update

        December 31, 2017 Reserves

        As of December 31, 2017, Abraxas’ proved oil and natural gas reserves consisted of approximately 65.9 MMBoe, a net increase of 21.2 MMBoe or 47.5% over 2016 year-end reserves of 44.7 MMBoe. December 31, 2017 reserves consisted of approximately 37.6 million barrels of oil, 12.0 million barrels of NGLs and 97.8 billion cubic feet of natural gas. PDP reserves were 20.7 MMBoe an increase of 48.5% over 2016 PDP reserves and comprised 31.4% of proved reserves as of December 31, 2017.

        The SEC-priced pre-tax PV-10 (1) (a non-GAAP financial measure) was $425.9 million, using 2017 average prices of $51.34/bbl of oil and $2.99/mcf of natural gas. Realized pricing, including differentials, used in this calculation equated to $46.82/bbl of oil and $1.79/mcf of natural gas.

        Net proved reserve additions of 23.9 MMBoe resulted in a reserve replacement ratio of 887% (defined as the sum of extensions, discoveries, revisions and purchases, divided by annual production). PDP F&D cost (defined as total drilling and completion capital expenditures divided by total PDP reserve additions) was $10.42/Boe.

        The majority of Abraxas’ reserve additions came from the Delaware Basin, where Abraxas booked 17 gross Wolfcamp A1, 17 gross Wolfcamp A2, two gross Wolfcamp B and two gross Third Bone Spring proved undeveloped locations across four gross sections at Caprito (1320 foot spacing assumed). Abraxas booked an additional eight gross Third Bone Spring, Wolfcamp A1 and Wolfcamp A2 proved undeveloped locations across four additional gross sections. The remainder of Abraxas’ leasehold in the Delaware Basin remains entirely unbooked for future years. Abraxas also sold 1.3 MMBoe of reserves during 2017.

        The independent reserve engineering firm DeGolyer and MacNaughton prepared a complete engineering analysis on 98.5% of Abraxas’ proved reserves on a Boe basis.

        The following table outlines changes in Abraxas’ proved reserves from December 31, 2016:

        Oil

        (MMbbl)

        		 Natural Gas

        (Bcf)

        		 NGL

        (MMbbl)

        		 Total

        (MMBoe)
        Proved Reserves December 31, 2016 24.2

        70.8

        		 8.6 44.7
        Additions 14.5 14.5 2.8 19.8
        Purchases 0.0 1.0 0.0 0.2
        Revisions 0.8 19.3 1.3 5.3
        Sales (0.4 ) (4.0 ) (0.3 ) (1.3 )
        Production (1.6 ) (3.9 ) (0.5 ) (2.7 )
        Proved Reserves December 31, 2017 37.6 97.8 12.0 65.9

        Fourth Quarter and Year End 2017 Production and CAPEX Update

        Production for the fourth quarter of 2017 averaged approximately 8,788 Boepd (5,325 barrels of oil per day, 12,334 mcf of natural gas per day, 1,407 barrels of NGL per day). Production for the year ending December 31, 2017 averaged approximately 7,391 Boepd (4,311 barrels of oil per day, 10,655 mcf of natural gas per day, 1,304 barrels of NGL per day).

        Capital expenditures for the year ended December 31, 2017 are expected to be approximately $135 million ($132 million cash and $3 million stock issuance). Approximately $31 million of the capital expenditures were spent on acquisitions with the remainder spent on drilling, completion and facilities.

        Operations Update

        In Ward County, Texas, the Caprito 82-101H, a 4,820 foot lateral and the Company’s first Third Bone Spring test, averaged 1,122 Boepd (878 barrels of oil per day, 1,463 mcf of natural gas per day)(2) over the well’s first 30 days of production. The Caprito 82-202H, a 4,820 foot lateral targeting the Wolfcamp A1 zone, averaged 1,134 Boepd (863 barrels of oil per day, 1,626 mcf of natural gas per day)(2) over the well’s first 30 days of production. Abraxas owns a 100% and 57.1% working interest in the Caprito 82-101H and 82-202H, respectively.

        Bob Watson, President and CEO of Abraxas, commented, “We are pleased to report our sixth consecutive year of production and reserve growth. 2018 promises to be a continuation of this trend with substantial upside left to be booked in the Delaware Basin and current production rates that are 50% higher than our 2017 average production. Our focused inventory of highly economic development locations in the Bakken and Wolfcamp/Bone Spring position us to drive multiple-years of high-return production and reserve growth for our shareholders.

        “We are also pleased to announce another highly productive zone on our Ward County acreage in the Third Bone Spring. This represents the fourth zone we have derisked in Ward County. We are currently testing downspacing on our acreage. The results of this will dictate the optimal development of these four zones on our acreage. Importantly, very little of this potential or downspacing is currently booked as proved undeveloped reserves, which bodes well for future reserve growth.”

        (1) The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2016 and 2017:

        December 31,
        (in thousands) 2016 2017
        PV-10 $ 160,600 $ 425,936
        Estimated present value of future income taxes discounted at 10% —

        (32,448

        )
        Standardized measure of discounted future net cash flows $ 160,600 $

        393,488

        (2) The 30-day average rates represent the highest 30 days of production and do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.

        Abraxas Petroleum Corporation is a San Antonio based crude oil and natural gas exploration and production company with operations in the Williston Basin, Permian Basin and South Texas regions of the United States.

        Safe Harbor for forward-looking statements: Statements in this release looking forward in time involve known and unknown risks and uncertainties, which may cause Abraxas’ actual results in future periods to be materially different from any future performance suggested in this release. Such factors may include, but may not be necessarily limited to, changes in the prices received by Abraxas for crude oil and natural gas. In addition, Abraxas’ future crude oil and natural gas production is highly dependent upon Abraxas’ level of success in acquiring or finding additional reserves. Further, Abraxas operates in an industry sector where the value of securities is highly volatile and may be influenced by economic and other factors beyond Abraxas’ control. In the context of forward-looking information provided for in this release, reference is made to the discussion of risk factors detailed in Abraxas’ filings with the Securities and Exchange Commission during the past 12 months.

        Contacts

        Abraxas Petroleum Corporation
        Geoffrey King, 210-490-4788
        Vice President – Chief Financial Officer
        gking@abraxaspetroleum.com
        www.abraxaspetroleum.com

    • Ecopetrol Group increases its hydrocarbon reserves, proven reserves mount to 1,659 million barrels-equivalent at 2017 close

      février 19, 2018

      • https://www.prnewswire.com/news-releases/ecopetrol-group-increases-its-hydrocarbon-reserves-proven-reserves-mount-to-1659-million-barrels-equivalent-at-2017-close-300600891.html

        BOGOTÁ, Colombia, Feb. 19, 2018 /PRNewswire/ — Ecopetrol (BVC: ECOPETROL; NYSE: EC) today announced its proven reserves of oil, condensate and natural gas (1P reserves), including its share in affiliates and subsidiaries, as of December 31, 2017.

        Reserves were estimated based on US Securities and Exchange Commission (SEC) standards and methodologies. 99% of the reserves were audited by two well-known, independent, specialized firms (Ryder Scott Company and Degolyer and MacNaughton).

        At the 2017 close, the Ecopetrol Group’s net proven reserves were 1,659 million barrels of oil-equivalent. The reserve replacement index was 126%, with average reserve life equivalent to 7.1 years.

        95% of the proven reserves are owned by Ecopetrol S.A., while Hocol, Ecopetrol America and the Equión and Savia Perú interests contributed 5%. Ecopetrol S.A. has an average reserve life of 7.4 years.

        In 2017, the Ecopetrol Group incorporated 295 million barrels of oil-equivalent of proven reserves, representing a positive change in the reserves incorporation trend in recent years. The year’s total accumulated production was 234 million barrels of oil-equivalent.

        The SEC price used for valuation of the 2017 reserves was USD 54.93 per Brent barrel, versus USD 44.49 per Brent barrel in 2016. Ecopetrol estimates that 94 million barrels of oil equivalent were recovered as a result of the higher price effect due to the extension of the fields’ economic limit and the incorporation of new projects. It is further estimated that the company’s technical management and financial optimization of assets contributed 201 million barrels of oil equivalent.

        We note that much of the increase in proven reserves (73 MBOE) is due to the results of the Recovery Factor Increase program, the principal gains of which occurred in fields such as Chichimene, Castilla, Casabe and Tibú. This result is very satisfactory, as it is one of the pillars of the company’s growth in reserves and production.

         

        Ecopetrol Group Proven Reserves 2015 – 2017

        2015

        2016

        2017

        Proven

        2.084

        1.849

        1.598

        Revisions

        -25

        -54

        175

        Enhanced Recovery

        16

        11

        73

        Mineral Purchases

        0

        0

        4

        Extensions and discoveries

        24

        27

        44

        Sales

        0.0

        0.0

        0.0

        Production

        -251

        -235

        -234

        Net proven reserves Dec 17

        1.849

        1.598

        1.659

        Bogotá D.C., February 19, 2018

        ————————————–

        This release contains statements that may be considered forward looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933 and Section 21E of the U.S. Securities Exchange Act of 1934. All forward-looking statements, whether made in this release or in future filings or press releases or orally, address matters that involve risks and uncertainties, including in respect of the Company’s prospects for growth and its ongoing access to capital to fund the Company’s business plan, among others. Consequently, changes in the following factors, among others, could cause actual results to differ materially from those included in the forward-looking statements: market prices of oil & gas, our exploration and production activities, market conditions, applicable regulations, the exchange rate, the Company’s competitiveness and the performance of Colombia’s economy and industry, to mention a few. We do not intend, and do not assume any obligation to update these forward-looking statements.

        For further information contact:
        Capital Markets Manager
        María Catalina Escobar
        Telephone: +571-234-5190
        Email: investors@ecopetrol.com.co

        Media Relations (Colombia)
        Jorge Mauricio Tellez
        Telephone: +571-234-4329
        Email: mauricio.tellez@ecopetrol.com.co

        SOURCE Ecopetrol S.A.

    • Antero Resources (AR) Announces 12% Increase in Estimated Proved Reserves to 17.3 Tcfe

      février 14, 2018

      • https://www.streetinsider.com/Corporate+News/Antero+Resources+%28AR%29+Announces+12%25+Increase+in+Estimated+Proved+Reserves+to+17.3+Tcfe/13808873.html

        Antero Resources (NYSE: AR) (« Antero » or the « Company ») today announced estimated reserves as of December 31, 2017.

        Highlights:

        • Proved reserves increased by 12% to 17.3 Tcfe at year-end 2017 (36% liquids), compared to year-end 2016
        • Pre-tax PV-10 of proved reserves at year-end 2017 was $10.8 billion at SEC pricing, including hedges
        • Proved developed reserves increased by 23% to 8.5 Tcfe at year-end 2017, compared to year-end 2016
        • $0.54 per Mcfe proved developed finding and development cost for 2017
        • $0.37 per Mcfe future development cost for year-end 2017 proved undeveloped reserves
        • 3P reserves increased by 18% to 54.6 Tcfe at year-end 2017 (25% liquids), compared to year-end 2016
        • Pre-tax PV-10 of 3P reserves at year-end 2017 was $18.4 billion at SEC pricing, including hedges

        Antero’s estimated proved reserves at December 31, 2017 were 17.3 Tcfe, a 12% increase compared to estimated proved reserves at December 31, 2016. Proved, probable and possible (« 3P ») reserves at year-end 2017 totaled 54.6 Tcfe, which represents an 18% increase compared to the previous year. For further discussion of 3P reserves, please read « Non-GAAP Disclosure. »

        Proved developed finding and development (« F&D ») cost for estimated proved developed reserve additions was $0.54 per Mcfe for 2017. All-in F&D cost for estimated proved reserve additions, including acquisitions, was $0.59 per Mcfe for 2017. Future development costs for proved undeveloped locations are estimated to be $0.37 per Mcfe. The reserve life of the Company’s estimated proved reserves is approximately 21 years based on 2017 production. For further discussion of all-in F&D cost and proved developed F&D cost, please read « Non-GAAP Disclosure. » Antero’s estimated proved and 3P reserves at December 31, 2017 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton (« D&M »). D&M’s reserve audit covered properties representing 100% of Antero’s total 3P reserves at December 31, 2017.

        Estimated Proved Reserves

        As of December 31, 2017, the Company’s 17.3 Tcfe of estimated proved reserves were comprised of 64% natural gas, 35% NGLs and 1% oil. The Marcellus Shale accounted for 90% of estimated proved reserves and the Ohio Utica Shale accounted for 10%. For 2017, Antero added 1.7 Tcfe of estimated proved reserves organically, excluding acquisitions, which is reflective of the continued productivity gains from the use of advanced completion techniques and longer laterals.

        All 381 proved undeveloped locations in the Marcellus at year-end 2017 were booked at an approximate 2 Bcf/1,000′ type curve. This compares to year-end 2016 at which time 81 proved undeveloped locations, or 21% of the total proved undeveloped locations in the Marcellus, were booked at the approximate 2 Bcf/1,000′ type curve. The primary driver behind the increase in the number of proved undeveloped locations booked at the higher approximate 2 Bcf/1,000′ type curve type curve is the increased production history observed from the implementation of advanced completions techniques.

        Estimated proved developed reserves increased by 23% from year-end 2016 to 8.5 Tcfe at December 31, 2017. The percentage of estimated proved reserves classified as proved developed increased to 49% at December 31, 2017 from 45% at year-end 2016. The average heating content of Antero’s proved undeveloped locations is 1237 BTU, and the average lateral length is approximately 10,500 feet.

        Under the Securities and Exchange Commission (« SEC ») reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking. The Company reclassified 2,778 Bcfe of formerly non-proved reserves to proved undeveloped due to their addition to Antero’s five-year development plan. Included in this reclassification was the revision of 286 Bcfe related to an improvement in performance from advanced completions and a 291 Bcfe revision related to a lateral extension of previously booked locations. Additionally, the Company reclassified 2,280 Bcfe of generally lower BTU proved undeveloped reserves to the probable category in 2017 to comply with the SEC five-year development rule. Antero’s 8.8 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.37 per Mcfe.

        Antero incurred estimated capital costs of approximately $1.7 billion during 2017, including drilling and completion costs of $1.282 billion, proved property acquisitions of $176 million and leasehold additions of $204 million. Based on the $1.7 billion of capital costs, 2017 all-in F&D cost for proved reserve additions from all sources, including acquisitions and revisions, was $0.59 per Mcfe.

        Summary of Changes in Estimated Proved Reserves (in Bcfe)

        Balance at December 31, 2016

        15,386

        Extensions, discoveries and additions

        1,711

        Purchases of estimated proved reserves

        373

        Revisions to prior estimates

        726

        Ethane recovery revision

        (113)

        Production

        (822)

        Balance at December 31, 2017

        17,261

        The table below summarizes both SEC and strip pricing as of December 31, 2017 and the associated PV-10 for estimated proved reserves and hedge values:

        2017 Year-End

        Benchmark Pricing:

        SEC Pricing

        Strip Pricing(1)

        Variance

        % Variance

        WTI Oil Price ($/Bbl)

        $51.03

        $53.44

        $2.41

        5%

        Appalachian Oil Price ($/Bbl)(2)

        $45.35

        $47.70

        $2.35

        5%

        Nymex Natural Gas Price ($/MMBtu)

        $3.11

        $2.93

        $(0.18)

        (6)%

        Appalachian Natural Gas Price ($/MMBtu)(2)

        $2.91

        $2.63

        $(0.28)

        (10)%

        C3+ Natural Gas Liquids ($/Bbl) (3)

        $32.37

        $32.23

        $(0.14)

        0%

        C2+ Natural Gas Liquids ($/Bbl)(3)

        $20.40

        $20.62

        $0.22

        1%

        Pre-Tax PV-10 Values ($Bn):

        Estimated proved reserves PV-10

        $10.2

        $9.1

        $(1.1)

        (11)%

        Hedge PV-10 (4)

        0.6

        1.2

        0.6

        100%

        Total PV-10

        $10.8

        $10.3

        $(0.5)

        (5)%

        1)

        Strip pricing as of December 31, 2017 for each of the first ten years and flat thereafter.

        2)

        Represents SEC and strip prices as of December 31, 2017 on a weighted average Appalachian index basis related to company-specific sales points.

        3)

        Represents realized NGL price including regional market differentials.

        4)

        Hedge PV-10 at strip pricing differs from year-end 2017 mark-to-market value of $1.3 billion due to the application of a higher discount rate.

        Proved, Probable and Possible Reserves

        Antero estimates that it had year-end 2017 3P reserves of 54.6 Tcfe, an 18% increase from year-end 2016. The 18% increase in 3P reserves was driven by a combination of increased type curves in certain areas driven by continued productivity gains from advanced completions, as well as 2017 leasehold acquisitions. As of December 31, 2017, the Company’s 54.6 Tcfe of 3P reserves were comprised of 75% natural gas, 23% NGLs and 2% oil. The Marcellus and Ohio Utica Shale comprised 48.3 Tcfe and 6.4 Tcfe of the 3P reserves, respectively. Virtually no Upper Devonian or West Virginia Utica reserves were included in 3P reserves.

        Importantly, 46.2 Tcfe of Antero’s 48.3 Tcfe, or 96% of estimated Marcellus 3P reserves were classified as proved and probable reserves (« 2P »), reflecting the low risk and statistically repeatable nature of Antero’s resource base. The 46.2 Tcfe of Marcellus 2P reserves includes 381 proved undeveloped and 460 probable locations, or 26% of the total undeveloped 2P reserve locations in the Marcellus that were booked at the approximate 2 Bcf/1,000′ type curve. This compares to year-end 2016 where 81 proved undeveloped and 7 probable locations, or just 3% of the total undeveloped 2P reserve locations in the Marcellus were booked at the approximate 2 Bcf/1,000′ type curve. The increase in upgraded 2P locations is primarily driven by continued productivity gains from implementing advanced completions techniques across a larger subset of Antero’s acreage position. Further, 6.2 Tcfe of Antero’s 6.4 Tcfe, or 97% of estimated 3P reserves in the Ohio Utica were classified as 2P.

        The tables below summarize Antero’s estimated 3P reserve volumes as of December 31, 2017 using SEC pricing, categorized by operating area as well as PV-10 values of Antero’s 3P reserve volumes using both SEC and strip pricing. For further discussion of 3P reserves, please read « Non-GAAP Disclosure. »

        Marcellus Shale

        Ohio Utica Shale

        Gas

        (Bcf)

        Liquids

        (MMBbl)

        Total (Bcfe)

        Gross Locations

        Gas

        (Bcf)

        Liquids

        (MMBbl)

        Total

        (Bcfe)

        Gross Locations

        Proved

        9,726

        971

        15,553

        1,054

        1,372

        56

        1,708

        243

        Probable

        24,174

        1,079

        30,645

        2,864

        3,978

        85

        4,489

        524

        Possible

        1,688

        67

        2,089

        267

        142

        4

        164

        51

        Total 3P

        35,588

        2,117

        48,287

        4,185

        5,492

        145

        6,361

        818

        % Liquids(1)

        26%

        14%

        Combined 3P Reserves

        Gas

        (Bcf)

        Liquids

        (MMBbl)

        Total

        (Bcfe)

        Gross Locations

        Proved(2)

        11,098

        1,027

        17,261

        1,297

        Probable

        28,152

        1,164

        35,134

        3,388

        Possible

        1,830

        70

        2,253

        318

        Total 3P

        41,080

        2,261

        54,648

        5,003

        % Liquids(1)

        25%

        1) Represents liquids volumes as a percentage of total volumes. Combined liquids comprised of 812 million

        barrels of ethane, 1.3 billion barrels of C3+ NGLs and 131 million barrels of oil

        2) 427 of the 1,297 proved locations were undeveloped locations

        Pre-Tax 3P PV-10 Values ($ Billions):

        SEC Pricing

        Strip Pricing(1)

        Variance

        % Variance

        3P Reserves PV-10

        $17.8

        $15.5

        $(2.3)

        (13)%

        Hedge PV-10 (2)

        0.6

        1.2

        0.6

        100%

        Total PV-10

        $18.4

        $16.7

        $1.7

        (9)%

        1) Strip pricing as of December 31, 2017 for each of the first ten years and flat thereafter

        2) Hedge PV-10 at strip pricing differs from year-end 2017 mark-to-market value of $1.3 billion due to the application of a higher discount rate

        Non-GAAP Disclosure

        Certain selected financial information in this release is unaudited. Additional unaudited financial information will be provided in Antero’s Annual Report on Form 10-K for the year ended December 31, 2017, which the Company filed with the SEC on February 13, 2018. In this release, Antero has provided a number of unaudited metrics, which include all-in F&D cost per unit and proved developed F&D cost per unit. These non-GAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company’s ability of adding and developing reserves at a reasonable cost. The F&D costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the F&D costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies. There are no directly comparable financial measures presented in accordance with GAAP for all-in F&D cost per unit and proved developed F&D cost per unit, and therefore a reconciliation to GAAP is not practicable.

        Calculations for all-in and proved developed F&D cost per unit are based on costs incurred in 2017. The calculations for both all-in and proved developed F&D cost per unit do not include future development costs required for the development of proved undeveloped reserves.

        Pre-tax PV–10 values and pre-tax PV-10 values including hedges are non-GAAP financial measures as defined by the SEC. Antero believes that the presentation of these pre-tax PV–10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves and hedges prior to taking into account corporate future income taxes and the Company’s current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves and hedges as compared with other companies. Antero believes that PV–10 estimates using strip pricing and including hedges can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV–10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV–10 value using SEC pricing.

        The GAAP financial measure most directly comparable to pre-tax PV–10 is the standardized measure of discounted future net cash flows (« Standardized Measure »). The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (Standardized measure) at December 31, 2017:

        (In millions, except per Mcf data)

        At December 31, 2017

        Future net cash flows

        $

        26,137

        Present value of future net cash flows:

        Before income tax (PV-10)

        $

        10,175

        Income taxes

        $

        (1,548)

        After income tax (Standardized measure)

        $

        8,627

        Notwithstanding their use for comparative purposes, the Company’s non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.

        Antero has provided summations of its proved, probable and possible reserves and summations of its PV-10 for its proved, probable and possible reserves in this press release. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because estimates of probable and possible reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use.

    • Valeura Announces Prospective Resources for Unconventional Basin-Centered Gas Prospect

      février 7, 2018

      • http://markets.businessinsider.com/news/stocks/valeura-announces-prospective-resources-for-unconventional-basin-centered-gas-prospect-1015019490

        CALGARY, Feb. 6, 2018 /CNW/ – Valeura Energy Inc. (« Valeura » or the « Corporation« ) (TSX: VLE) is pleased to announce summary results of an independent evaluation of its prospective resources in the Thrace Basin of Turkey prepared by DeGolyer and MacNaughton (« D&M« ) of Dallas, Texas in its report dated February 6, 2018 (the « D&M Resources Report« ). Highlights of the D&M Resources Report are as follows:

        • 10.1 Tcf of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate; and
        • 5.2 Tcf of estimated working interest risked mean prospective resources of natural gas, which includes 165 MMbbl of condensate.

        Valeura’s CEO, Sean Guest, said « We are pleased to now have an independent evaluation that supports Valeura’s thesis that the Thrace Basin may hold a very large unconventional, basin-centered natural gas-condensate resource. Valeura has been maturing this play for almost five years and these efforts culminated in the drilling of the Yamalik-1 natural gas-condensate discovery in 2017 with our partner Statoil. While Valeura is confident that natural gas is pervasive in these deep formations, we recognise that we are in the early phases of exploration. More drilling and testing will be required to prove that the gas will flow at commercial rates, and to refine the large uncertainty around recoverable gas and condensate. Valeura and Statoil are committed to progressing the work required to further evaluate this unconventional prospect. We are currently working to tie-in the Yamalik-1 discovery well to Valeura’s gas production network to allow for further testing and long-term production and sales. Additionally, Statoil and Valeura are planning a three-well delineation drilling and testing program which is expected to commence in Q3 2018. »

        2017 YEAR-END UNCONVENTIONAL PROSPECTIVE RESOURCES SUMMARY

        The D&M Resources Report was prepared using the guidelines outlined in the Canadian Oil and Gas Evaluation Handbook (« COGEH« ) and in accordance with NI 51-101 and is valid at December 31, 2017. D&M evaluated the unconventional prospective resources attributable to the Teslimkoy/Kesan basin-centered gas prospect on Valeura’s lands in the Thrace Basin of Turkey. The working interest lands included comprise the deep formations (generally below 2,500 m depth) on the Corporation’s Banarli licenses (50% working interest), TBNG JV West Thrace lands (31.5% working interest), and TBNG JV South Thrace lands (81.5% working interest).

        The D&M evaluation benefited from the Yamalik-1 natural gas-condensate discovery, which was recently drilled and tested on the Banarli licenses. Yamalik-1 discovered an approximate 1,300 m column of natural gas and condensate in over-pressured reservoirs below 2,900 m in the Teslimkoy and Kesan formations. The well was drilled to 4,196 m, fracture stimulated and production tested in Q4 2017. As announced on December 27, 2017, four production tests from eight frac stages in the Kesan formation yielded a 24-hour aggregate test rate of 2.9 MMcf/d. Extensive coring and wireline logging information was also captured in the well.

        Yamalik-1 was the first well to be extensively facture stimulated in the basin-centered gas prospect in the Thrace Basin. However, well data from seven other legacy wells drilled in the prospective area to depths up to 4,050 m also indicate over-pressured natural gas below approximately 2,500 m and were available for D&M’s evaluation. Only one of these legacy wells (Yayli-1) was fracture stimulated with a small two-stage frac at a depth of approximately 2,800 m.

        Table 1 below summarizes D&M’s estimates of Valeura’s working interest prospective natural gas resources (defined as « conventional natural gas » under NI 51-101). These numbers as reported by D&M are for the complete gas stream and explicitly include condensate resources (defined as « natural gas liquids » under NI 51-101) which are entrained in the natural gas. Sales gas volumes would be nominally lower than those presented in Table 1. Table 2 shows the amount of condensate that would be recovered associated with the production of the natural gas volumes shown in Table 1.

        Table 1 Valeura Working Interest Natural Gas Prospective Resources at December 31, 2017(6)(7)(8)(9)(10)

        Valeura Working
        Interest Lands (1)

        Unrisked

        Chance of
        Commerciality

        % (11)

        Risked

        Mean

        Estimate (12)

        Low

        Estimate (2)

        Best

        Estimate (3)

        High

        Estimate (4)

        Mean

        Estimate (5)

        Conventional Natural Gas (13) – Bcf

        Total

        3,229

        7,652

        20,077

        10,137

        51.1

        5,182

         

        The broad range of recoverable gas from 3.2 to more than 20 Tcf  is a function of the uncertainty in the various components of the assessment including recovery factor. There has been very limited stimulation and production testing from the over-pressured Teslimkoy and Kesan formations in the Thrace Basin, and as yet there is no production data. To determine potential recovery factors, D&M have utilized their experience in analogous basins. The prospective resources in Table 1 and 2 assume a low recovery factor estimate of approximately 25%, a best and mean estimate of 40% and high estimate of 55%. Significantly more delineation drilling, stimulation, and testing will be required to confirm that gas can be commercially recovered from the prospect, and to generate type curves that can be used in a predictive sense. All of Valeura’s prospective resources were sub-classified into the project maturity subclass of ‘prospect’.

        Table 2 Valeura Working Interest Natural Gas Liquids Prospective Resources at December 31, 2017(6)(7)(8)(9)(10)

        Valeura Working
        Interest Lands (1)

        Unrisked

        Low

        Estimate (2)

        Best

        Estimate (3)

        High

        Estimate (4)

        Mean

        Estimate (5)

        Condensate (Natural Gas Liquids) (14) – MMbbl

        Total

        45

        155

        504

        236

         

        D&M has assigned a chance of discovery of 70%. This high chance is driven by: (1) the hundreds of legacy wells drilled in the Thrace Basin which support the geological model for the Teslimkoy and Kesan formations; (2) the over-pressured natural gas which was encountered and tested at Yamalik-1, and (3) the seven legacy wells surrounding the basin which all encountered over-pressured gas below 2,500 m.

        D&M has assigned a chance of development of the natural gas prospective resources of approximately 74%, which is a product of the probability of threshold economic field size and probability of development. This high chance of development reflects that existing hydraulic fracturing technology is being applied, well depths and costs are not expected to be excessive, sales pipeline infrastructure already exists in the area and there are ready domestic markets in Turkey for domestic natural gas and condensate sales. This results in an overall chance of commerciality of 51.1% which is the product of chance of discovery and chance of development. The resulting risked mean estimates of conventional natural gas prospective resources are shown in Table 1, as risked for chance of commerciality.

        Understanding of the extent of this basin-centered gas prospect in the Thrace Basin and its potential commerciality is in the early stages of exploration and appraisal. There are a number of positive and negative factors which are driving large uncertainty. The key positive factors include:

        • Design work is underway for the production facilities and gathering pipeline to tie-in the Yamalik-1 well to Valeura’s existing gathering sales pipeline infrastructure to enable a long-term production test and natural gas and condensate sales from the well at an anticipated cost of approximately US$3 MM (gross). First sales from Yamalik-1 are targeted for Q2 2018.
        • Valeura and Statoil are planning a delineation drilling program comprising three wells expected to commence in Q3 2018 and extend into 2019. The first well in this program will be the second and final earning well under Phase 3 of the Banarli Farm-in to be fully funded by Statoil.
        • The follow-up delineation drilling program will benefit from the new Karaca 3D seismic in terms of finalizing drilling locations, correlating the seismic to the Yamalik-1 well results and targeting sweet-spots in the basin-centered gas prospect.
        • It is expected that the follow-up delineation wells will be drilled to approximately 5,000 m given good potential to extend the column of hydrocarbon-bearing sands. The Yamalik-1 well was drilled to 4,196 m, the limit of the rig capability and well completion, but the base of the well was still in gas-bearing sands that were successfully flow tested.
        • Valeura’s existing infrastructure and customer base is expected to be capable of handling sales of more than 35 MMcf/d compared to current sales through the system of less than 10 MMcf/d, thereby providing the opportunity for early production from any future delineation wells.
        • Turkey is a captive natural gas market given that 99% of its natural gas demand is served by imports. This provides an attractive marketing opportunity for a domestic natural gas producer. As Valeura’s natural gas production volumes potentially grow beyond the limit of its owned infrastructure, there are multiple take-away opportunities. These include: a potential to tie-in to a pipeline owned by Bori Hatlari ile Petrol Tasima Anonim Sirketi (« BOTAS« ) just north of the Banarli lands; a tie-in to another BOTAS interconnector pipeline traversing Banarli and connected to an export line to Greece; and sales to the local gas distributor who currently offtakes gas from the BOTAS pipeline to the north.
        • Natural gas prices in Turkey are strong. Valeura’s average natural gas price realization in Q4 2017 was approximately CAD$6.61/Mcf. On January 1, 2018, the reference natural gas price set by BOTAS was increased by 14%.

        Negative factors with respect to the estimate of prospective resources include:

        • The basin-centered gas prospect is in the early exploration and delineation cycle with very sparse well control and very limited fracture stimulation and testing data.
        • There is no long-term well production performance from the basin-centered prospect to establish a production type curve specific to the prospect, thereby requiring use of analogue information at this time to establish development plans and to confirm the chance of commerciality.
        • Recovery efficiencies are uncertain given the absence of site specific long-term well production performance data in the basin-centered gas prospect.
        • The limited deep drilling carried out in the Thrace Basin provides poor visibility on future costs to drill, frac and complete deep development wells to exploit the basin-centered gas prospect and the associated impact on the chance of commerciality.
        • Although oil and gas activity has been underway for many decades in the Thrace Basin area, as activity levels increase, timelines may increase to achieve government and local landowner approvals.

        RESERVES UPDATE

        For completeness, the Corporation also announces an update on its proved plus probable (2P) gross reserves attributed to its properties in the Thrace Basin of Turkey. The Corporation has completed an internal assessment (non-independent) which estimates 2P gross reserves of 7.8 MMboe effective December 31, 2017. This represents a significant increase in reserves relative to the reported year-end 2016 and is attributed to the TBNG acquisition which occurred after the year-end 2016 report.  The Corporation expects that the related 2P net present value of future net revenue before-tax for year-end 2017 will be similar to year-end 2016 as the increase in reserves from the TBNG acquisition is expected to be mostly offset by a reduction in the forecast gas price.

        D&M are currently preparing their independent evaluation of the Corporation’s reserves at December 31, 2017. This information will be released in the normal course in March 2018 in conjunction with the release of the 2017 Annual Information Form.

        ABOUT THE CORPORATION

        Valeura Energy Inc. is a Canada-based public company currently engaged in the exploration, development and production of petroleum and natural gas in Turkey.

        OIL AND GAS ADVISORIES

        When used herein, the term « boe » means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or natural gas liquids, or 6.0 Mcf of natural gas. Barrel of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of 6.0 Mcf to 1.0 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

        The prospective resources and reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves and prospective resources will be recovered.

        RESERVES AND RESOURCES DEFINITIONS

        « Chance of Discovery » is the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum.

        « Chance of Development » is the estimated probability that, once discovered, a known accumulation will be commercially developed.

        « Company gross reserves » are the Company’s working interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Company.

         »Condensate » is defined as Natural Gas Liquids product type as per NI 51-101.

        « Natural Gas » is defined as Conventional Natural Gas product type as per NI 51-101

        « Proved » or « 1P » reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

        « Probable » reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable (« 2P« ) reserves.

        « Prospective Resources » are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.

         »Reserves » are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

        FOOTNOTES TO TABLES

        (1)

        Valeura’s working interest in the lands (exploration licences and production leases) that are encompassed (all or a portion thereof) in the basin-centered gas prospect in the Teslimkoy/Kesan formation is as follows: Banarli 50%, West Thrace 31.5% and South Thrace 81.5%.

        (2)

        The low estimate is the P90 quantity. P90 means there is a 90% chance that the estimated quantity will be equaled or exceeded.

        (3)

        The best estimate is the P50 quantity. P50 means there is a 50% chance that the estimated quantity will be equaled or exceeded.

        (4)

        The high estimate is the P10 quantity. P10 means there is a 1 % chance that the estimated quantity will be equaled or exceeded.

        (5)

        The mean estimate is the probability-weighted average (expected value).

        (6)

        The totals are the arithmetic summation of probabilistic estimates. Arithmetic summation may produce invalid results except for the mean.

        (7)

        Unconventional prospective resources, as prepared by D&M, are those quantities of petroleum that are estimated, at a given date, to be potentially recoverable from undiscovered unconventional accumulations by application of future development projects. Unconventional prospective resources may exist in petroleum accumulations that are pervasive throughout a large potential production area and would not be significantly affected by hydrodynamic influences (also called continuous-type deposits). Typically such accumulations (once discovered) require specialized extraction technology (e.g. massive fracturing programs for tight gas). Tight gas occurs within low permeability reservoir rocks, which are rocks with matrix porosity of 10 percent or less and permeability of 0.1 millidarcies or less, exclusive of fractures. Tight gas can be regionally distributed (e.g. the basin-centered gas prospect in the Thrace Basin evaluated herein), rather than accumulated in a readily producible reservoir in a discrete structural closure as in a conventional gas field.

        (8)

        Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the unconventional prospective resources estimated herein will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the unconventional prospective resources evaluated. Estimates of the unconventional prospective resources should be regarded only as estimates that may change as additional information becomes available. Not only are such unconventional prospective resources estimates based on that information which is currently available, but such estimates are also subject to uncertainties inherent in the application of judgmental factors in interpreting such information. Unconventional prospective resources should not be confused with those quantities that are associated with contingent resources or reserves due to the additional risks involved. Because of the uncertainty of commerciality and the lack of sufficient exploration drilling, the unconventional prospective resources estimated herein cannot be classified as contingent resources or reserves. The quantities that might actually be recovered, should they be discovered and developed, may differ significantly from the estimates herein.

        (9)

        The unconventional prospective resources estimates contained in the D&M Resources Report are expressed as gross and working interest unconventional prospective resources. Table 1 and 2 summarizes Valeura’s working interest unconventional prospective resources, which incorporate the fraction of potential hydrocarbon pore volume owned or partially owned by Valeura and Valeura’s working interest ownership, before deduction of any associated royalty burdens. Recovery efficiency is applied to unconventional prospective resources in Table 1 and 2.

        (10)

        The estimation of resources quantities for a prospect is subject to both technical and commercial uncertainties and, in general, may be quoted as a range. The range of uncertainty reflects a reasonable range of estimated potentially recoverable quantities. Estimates of petroleum resources herein are expressed using the terms low estimate, best estimate, high estimate and mean estimate (unrisked and risked) to reflect the range of uncertainty.

        (11)

        The chance of commerciality is defined as the product of the chance of discovery and the chance of development. Chance of discovery is defined in COGEH as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. Chance of development is the estimated probability that, once discovered, a known accumulation will be commercially developed.

        Chance of discovery in the D&M Resources Report is referred to as the probability of geologic success (Pg), which is defined as the probability of discovering reservoirs that flow hydrocarbons at a measureable rate. The Pg is estimated by quantifying with a probability, each of the following geologic chance factors: trap, source, reservoir and migration. The product of the probabilities of these four chance factors is Pg. Pg is predicated and correlated to the minimum case prospective resources gross recoverable volume(s). Consequently, the Pg is not linked to economically viable volumes, economic flow rates or economic field size distributions.

        In the D&M Resources Report, two factors have been considered in determining the chance of development as follows:

        Chance of development = Ptefs (probability of threshold economic field size) x Pd (probability of development)

        D&M defines Ptefs as the probability of discovering an accumulation that is large enough to be economically viable. Ptefs is estimated by using the prospective resources potential recoverable quantities distribution in conjunction with the threshold economic field size (TEFS). TEFS is the minimum amount of the producible petroleum required to recover the total capital and operating expenditure used to establish the potential accumulation as having a potential present worth at 10% equal to zero using the most likely price scenario.

        D&M defines Pd as the probability that a given discovery will be a viable development project. It takes into account the chance that the discovered target zone will flow the predicted hydrocarbon phase(s) at a commercial rate. It also considers the chance that the target zone can be mechanically completed and appraised in a reasonable time and in compliance with the projected cost schedule. The Pd is estimated by the quantification and product of these two chance factors.

        (12)

        The risked mean estimate of conventional natural gas prospective resources = the unrisked mean estimate x chance of discovery x chance of development.

        (13)

        The risked mean estimate of natural gas liquids prospective resources = the Unrisked mean estimate x chance of discovery.

        (14)

        The natural gas liquids prospective resources are included in the conventional natural gas prospective resources.

         

        ABBREVIATIONS

        Bcf

        billion cubic feet

        bbl

        barrels

        boe

        barrels of oil equivalent

        m

        metres

        M

        thousand

        MM

        million

        MMcf/d

        million cubic feet per day

        Tcf

        trillion cubic feet

         

        ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION

        This news release contains certain forward-looking statements and information (collectively referred to herein as « forward-looking information« ) including, but not limited to: the anticipated delineation drilling and development program to exploit the basin-centered gas prospect on Valeura’s working interest lands; the plans, timelines and cost to tie-in the Yamalik-1 well to conduct a long term production test, establish production type curves and achieve gas sales; completion of Phase 3 of the Banarli Farm-in and drilling of the second earning well to be funded by Statoil; the ability to target sweet spots in the basin-centered gas prospect; the plans to drill to 5,000m in the basin-centered gas prospect delineation program and the cost and timeline impacts; the capacity of Valeura’s existing infrastructure in the Thrace Basin and ability to handle up to 35 MMcf/d; the ability to access other pipeline systems in the Thrace Basin should future production volumes exceed the capacity of Valeura’s existing infrastructure; the anticipated conventional tight gas development program in the Tekirdag field that underpins the Corporation’s current probable and possible reserves; the preparation and timing of the 2017 D&M Reserves Report; and the ability to finance future developments. Forward-looking information typically contains statements with words such as « anticipate », estimate », « expect », « target », « potential », « could », « should », « would » or similar words suggesting future outcomes. The Corporation cautions readers and prospective investors in the Corporation’s securities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Corporation.

        Statements related to « reserves » or « prospective resources » are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and prospective resources can be profitably produced in the future. Specifically, forward-looking information contained herein regarding « reserves » and « prospective resources » may include: estimated volumes and value of Valeura’s oil and gas reserves; estimated volumes of prospective resources and the ability to finance future development; and, the conversion of a portion of prospective resources into reserves.

        Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: political stability of the areas in which the Corporation is operating and completing transactions, and in particular the aftermath of the July 2016 failed coup attempt in Turkey and April 2017 constitutional referendum; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the Turkish government in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the prospectivity of the TBNG JV lands and Banarli licences, including the deep basin-centered gas potential; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licences and leases; and the Corporation’s continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Corporation’s work programs and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, fracing and other specialized oilfield equipment and service providers, changes in partners’ plans and unexpected delays and changes in market conditions. Although the Corporation believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

        Forward-looking information involves significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a significant degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Corporation including, but not limited to: the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the contemplated timelines for the Yamalik-1 tie-in program; completion of the Banarli Farm-in program and the basin-centered gas delineation drilling program; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues, terrorist attacks, insurgencies or civil unrest in Turkey; political stability in Turkey, including potential changes in Turkey’s constitution, political leaders or parties or a resurgence of a coup or other political turmoil; the uncertainty regarding government and other approvals; counterparty risk; potential changes in laws and regulations; and risks associated with weather delays and natural disasters; the risk associated with international activity; and, the uncertainty regarding the ability to fulfill the drilling commitment on the West Thrace lands. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. See Valeura’s 2016 AIF for a detailed discussion of the risk factors.

        Additional information relating to Valeura is also available on SEDAR at www.sedar.com

        Neither the Toronto Stock Exchange nor its Regulation Services Provider (as that term is defined in the policies of the Toronto Stock Exchange) accepts responsibility for the adequacy or accuracy of this news release.

        SOURCE Valeura Energy Inc.

    • Maurel & Prom: -2017 sales: $400m (up 14%)

      février 6, 2018

      • Paris, 5 February 2018
         No. 02-18

        2017 sales: $400m (up 14%)
        • Group sales up 14% to $400m for 2017
          • Increase in the average sale price of oil: up 24% compared to 2016
          • Higher demand for gas in Tanzania: annual production up 13%
        • Group reserves at 31 December 2017 in M&P share :
          • Gross P1+P2 reserves: 215 MMboe
          • P1+P2 reserves net of royalties: 195 MMboe

         

        2017 Sales

        Q1 2017 Q2 2017 Q3 2017 Q4 2017   12 months 2017   12 months 2016 Chg.17/16
           
        Total production sold over the period, M&P share                  
        millions of barrels of oil 1.6 1.7 1.8 1.7   6.8   7.4 -8%
        million MMBTU 1.9 1.4 2.7 2.8   8.8   7.8 +13%
           
        Average sale price                  
        OIL, in $/bbl 52.8 48.6 50.0 59.7   53.0   42.7 24%
        GAS, in $/BTU 3.18 3.22 3.13 3.12 3.15 3.13 1%
        EUR/USD exchange rate 1.06 1.10 1.17 1.18   1.13   1.11 2%
                   
        SALES (in $m)                
        Oil production 91 87 97 109   384   337 14%
        Gabon 86 83 90 102   361   317 14%
        Tanzania 5 4 7 7   23   20 14%
        Drilling operations 5 3 4 4   16   14 17%
        Consolidated sales (in $m) 96 90 101 113   400 351 14%
        Consolidated sales (in €m) 90 81 86 97   355 317 12%
         

        The Group’s consolidated sales for 2017 amounted to $400 million (€355 million), up 14% compared to 2016.

        This increase was due to the sharp rise in oil prices in 2017, despite a drop in oil production in Gabon during the period.
        The average sale price of oil in fiscal year 2017 rose by 24% to $53/bbl versus $42.7/bbl in 2016.

        To meet the higher demand for gas in Tanzania, gas production significantly increased starting in the second half of 2017. For the full year, average production stood at 49.1 MMcf/d at 100%, up 14% over the previous year.

        Hydrocarbon production in 2017

        Q1 2017 Q2 2017 Q3 2017 Q4 2017   12 months 2017   12 months 2016 Chg.17/16
                     
        Production operated by Maurel & Prom (100%)                
         Oil bopd 24,303 25,104 26,290 24,144   24,963   27,195 -8%
         Gas MMcf/d 43.3 30.7 60.0 62.2   49.1   43.1 14%
         TOTAL  boepd 31,509  30,221  36,268  34,514      33,145      34,365  -4%
        Maurel & Prom
        share of production        		                
         Oil bopd 19,442 20,083 21,032 19,315   19,970   21,756 -8%
         Gas MMcf/d 20.8 14.8 28.8 29.9   23.6   20.7 14%
         TOTAL  boepd 22,905  22,542  25,828  24,299      23,903      25,202  -5%

        Operated oil production in Gabon in the fourth quarter of 2017 amounted to 24,144 bopd, down 8% compared to the previous quarter. This was primarily due to the installation of an autonomous power generation system designed to reduce operating costs. Production was halted during its commissioning, resulting in an estimated loss of 860 bopd in Q4 2017.

        To mitigate the Ezanga permit field depletion resulting, among other things, from its development programme being halted for close to three years on account of the drop in oil prices, Maurel & Prom Gabon will resume all of its drilling activities. This programme, set to begin in the first half of 2018, involves drilling 11 development wells and three sidetracks.
        In addition, drilling of the first exploration wells on the Kari and Nyanga-Mayomnbé permits will start in the second half of 2018.

        In Tanzania, demand for gas from the national company, TPDC, rose steadily in 2017 to reach average production of 62.2 MMcf/d at 100% in Q4 2017.
        This demand, which is linked to industrial gas consumption in Dar Es Salam, is expected to increase further in 2018.
        Group reserves in M&P share at 31 December 2017 (WI M&P)

        The Group’s reserves correspond to the volumes of recoverable hydrocarbons currently in production plus those revealed by discovery and delineation wells that can be operated commercially. These reserves were certified by DeGolyer and MacNaughton in Gabon and RPS Energy in Tanzania as at 31 December 2017.

        Gross P1+P2 reserves
        M&P’s share        		 Oil (MMbbl) Gas
        (Bcf) ([1])        		 MMboe
        Gabon Tanzania
        01/01/2017 178.2 272.3 223.6
        production -7.2 -8.8  
        revision 0.2 1.9  
        31/12/2017 171.3 265.4 215.5
         o/w gross P1 reserves 134.9 146.5 159.3
        or 79% 55% 74%
        P1+P2 reserves net of royalties
        M&P’s share        		 Oil (MMbbl) Gas
        (Bcf) (1)        		 MMboe
        Gabon Tanzania
        01/01/2017 157.7 272.3 203.1
        production -6.8 -8.8
        revision 0.2 1.9
        31/12/2017 151.1 265.4 195.3
         o/w P1 reserves net of royalties 119.1 146.5 143.5
        or 79% 55% 73%

        At 31 December 2017, gross P1+P2 (2P) reserves amounted to 215 MMboe, the equivalent of 195 MMboe in M&P share net of royalties.

        In Gabon, 2P reserves net of royalties and restated for 2017 production amounted to 151.1 MMbbls at 31 December 2017, with P1 reserves accounting for 79% of that total. This level of certified reserves reflects the value and success of the work undertaken to optimise the Ezanga field following the drop in oil prices.

        At 31 December 2017, the Group also had gas reserves of 265 Bcf.

        These gas assets give the Group access to fixed, stable revenues over the long term. The sale price is $3.0441 per thousand cubic feet and rises with inflation. Maurel & Prom thus has cash flow unaffected by oil price fluctuations.

        Français     Anglais
        pieds cubes pc cf cubic feet
        pieds cubes par jour pc/j cfpd cubic feet per day
        milliers de pieds cubes kpc Mcf 1,000 cubic feet
        millions de pieds cubes Mpc MMcf 1,000 Mcf = million cubic feet
        milliards de pieds cubes Gpc Bcf billion cubic feet
        baril b bbl barrel
        barils d’huile par jour b/j bopd barrels of oil per day
        milliers de barils kb Mbbl 1,000 barrels
        millions de barils Mb MMbbl 1,000 Mbbl = million barrels
        barils équivalent pétrole bep boe barrels of oil equivalent
        barils équivalent pétrole par jour bep/j boepd barrels of oil equivalent per day
        milliers de barils équivalent pétrole kbep Mboe 1,000 barrels of oil equivalent
        millions de barils équivalent pétrole Mbep MMboe 1,000 Mbbl = million barrels of oil equivalent

        https://globenewswire.com/news-release/2018/02/05/1332573/0/en/Maurel-Prom-2017-sales-400m-up-14.html

         

    • KMG EP reserves update as at 31 December 2017

      février 1, 2018

      • http://www.lse.co.uk/regulatory-news-article.asp?ArticleCode=wrsgv56r&ArticleHeadline=KMG_EP_reserves_update_as_at_31_December_2017

        RNS Number : 4570D
        JSC KazMunaiGas Exploration Prod
        31 January 2018
        �
        PRESS-RELEASE

        Astana, 31�January 2018. JSC KazMunaiGas Exploration Production (« KMG EP » or the « Company ») announces the results of an independent audit of liquid hydrocarbon reserves at the Ozenmunaigas JSC, Embamunaigas JSC and the Ural Oil and Gas LLP (KMG EP’s share – 50%) fields as at 31 December 2017. The audit was performed by independent consultant DeGolyer and MacNaughton (« D&M »).

        According to the D&M report, proved plus probable (2P) reserves of liquid hydrocarbons as at 31 December 2017 were 145 million tonnes (1,065 million barrels), equal to the level at the end of 2016. The reserve replacement ratio (the ratio of increase in reserves to annual production) was 100%.

        Proved (1P) reserves of liquid hydrocarbons at 31 December 2017 were 102 million tonnes (754 million barrels), and proved, probable and possible (3P) reserves amounted to 193 million tonnes (1,418 million barrels).

        Liquid hydrocarbon reserves as of 31 December 2017

        (See Article link for tables)

        The report does not include KMG EP’s share in reserves of JV Kazgermunai LLP, CCEL (Karazhanbasmunai) and PetroKazakhstan Inc.

        NOTES TO EDITORS

        KMG EP is among the top three Kazakh oil producers based on the 2017 results. The overall production in 2017 was 11.9 million tonnes (240 kbopd) of crude oil, including the Company’s share in Kazgermunai, CCEL and PKI. The Company’s volume of proved and probable reserves excluding shares in the associates, at the end of 2016 was 182 million tonnes (1,327 mmbbl). The Company’s shares are listed on the Kazakhstan Stock Exchange and the GDRs are listed on the London Stock Exchange and Kazakhstan Stock Exchange. The Company raised over US$2bn at its IPO in September 2006.

        For further details please contact us at:
        KMG EP. Investor Relations (+7 7172 97 5433)
        Saken Shoshanov
        e-mail: ir@kmgep.kz�

        KMG EP. Public Relations (+7 7172 97 7887)

        Bakdaulet Tolegen

        e-mail: pr@kmgep.kz�

        �

        Finsbury (+44 (0)20 7251 3801)

        Dorothy Burwell

        e-mail: KMGEP@finsbury.com��

        Forward-looking statements

        This document includes statements that are, or may be deemed to be,  »forward-looking statements ». These forward-looking statements can be identified by the use of forward-looking terminology including, but not limited to, the terms  »believes »,  »estimates »,  »anticipates »,  »expects »,  »intends »,  »may »,  »target »,  »will », or  »should » or, in each case, their negative or other variations or comparable terminology, or by discussions of strategy, plans, objectives, goals, future events or intentions. These forward-looking statements include all matters that are not historical facts. They include, but are not limited to, statements regarding the Company’s intentions, beliefs and statements of current expectations concerning, amongst other things, the Company’s results of operations, financial condition, liquidity, prospects, growth, potential acquisitions, strategies and as to the industries in which the Company operates. By their nature, forward-looking statements involve risk and uncertainty because they relate to future events and circumstances that may or may not occur. Forward-looking statements are not guarantees of future performance and the actual results of the Company’s operations, financial condition and liquidity and the development of the country and the industries in which the Company operates may differ materially from those described in, or suggested by, the forward-looking statements contained in this document. The Company does not intend, and does not assume any obligation, to update or revise any forward-looking statements or industry information set out in this document, whether as a result of new information, future events or otherwise. The Company does not make any representation, warranty or prediction that the results anticipated by such forward-looking statements will be achieved.

        This information is provided by RNS, The company news service from the London Stock Exchange

    • NOVATEK Announces Year-End 2017 Reserves

      janvier 25, 2018

      • Moscow, 23 January 2018. PAO NOVATEK (“NOVATEK” and/or the “Company”) announced that independent petroleum engineers, DeGolyer & MacNaughton, have completed their comprehensive reserve appraisal of the Company’s hydrocarbon reserves as of 31 December 2017.

        Total SEC proved reserves, including the Company’s proportionate share in joint ventures, aggregated 15,120 million barrels of oil equivalent (boe), including 2,098 billion cubic meters (bcm) of natural gas and 164 million metric tons (mmt) of liquid hydrocarbons. Total proved reserves increased by 12.8% compared to the year-end 2016, representing a reserve replacement rate of 435% for the year.

        The Company’s reserves were positively impacted by successful exploration works at the Utrennee, Kharbeyskoye, West-Yurkharovskoye and Urengoyskoye (Samburgskiy license area) fields, production drilling at the South-Tambeyskoye field, as well as the new licenses obtained through tender auctions (Gydanskoye, Verhnetiuteyskoye and West-Seyakhinskoye fields) and recent asset acquisitions (South-Khadyryakhinskoye, Syskonsynyinskoye fields and West-Yaroyakhinskiy license area). Excluding the effect of obtaining new licenses, our total proved reserves increased by 1.3%, representing an organic reserve replacement rate of 134%.

        At year-end 2017, the Company’s reserve to production ratio (or R/P ratio) was 29 years.

        Under the PRMS reserves reporting methodology, the Company’s total proved plus probable reserves, including the Company’s proportionate share in joint ventures, aggregated 28,471 million boe, including 3,879 bcm of natural gas and 366 mmt of liquid hydrocarbons.

        NOVATEK reserves according to international standards
        Proved reserves under the SEC methodology

        ***

        Information provided in this press release represents expected results of PAO NOVATEK operations in 2017. The information represents preliminary assessment only, which can be adjusted after statistical, financial, fiscal and business reporting becomes available. The information on PAO NOVATEK’s operational results in this press release depends on many external factors and therefore, provided all permanent obligations imposed by the London Stock Exchange listing rules are unconditionally observed, cannot qualify for accuracy and completeness and should not be regarded as an invitation for investment. Therefore, the results and indicators actually achieved may significantly differ from any declared or forecasted results in 2017. PAO NOVATEK assumes no obligation (and expressly declares that it has no such obligation) to update or change any declarations concerning any future results, due to new information obtained, any future events or for any other reasons.

        NOVATEK Announces Year-End 2017 Reserves

    • Algerian Sonatrach and Libyan NOC to jointly operate oilfields on mutual borders

      janvier 17, 2018


      • Photo Source: NOC Facebook page. Left to right, NOC Chairman, Mr. Mustafa A. Sanalla; Sonatrach Chairman & CEO, Mr. Abdelmoumen Ould-Kaddour; and D&M Chairman & CEO, Mr. John W. Wallace

        Algerian Sonatrach signed Monday an agreement with the Libyan National Oil Corporation (NOC) to run a number of oilfields located on the borders between the two countries, according to a statement on the NOC website.

        According to the agreement was a further step on the ground after a study that was carried out on 2006 concerning Al-Rar and Al-Wafaa oilfields that are located on the borders between Algeria and Libya. Al-Rar gas field is located on the Algerian side of the border, while Al-Wafa oilfield is located on the Libyan side of the border.

        “If it was proved that the two fields are in fact one field, they will be run and managed jointly by the two countries,” A source from Sonatrach told Anadolu Agency.

        “Through the agreement, the two companies decided to update the old study using the technical data collected from January 2008 to present,” the source clarified, adding that the two companies are also seeking to achieve the optimal utilization for the two fields through the agreement.

        Sonatrach have been halting all its projects and investments in Libya since 2011.
        Source: http://www.libyanexpress.com/algerian-sonatrach-and-libyan-noc-to-jointly-operate-oilfields-on-mutual-borders/

    • Algeria, Libya agree to jointly manage oil fields on shared border

      janvier 17, 2018

      • Algeria’s state-run oil company Sonatrach signed an agreement, Monday, with the Libyan National Oil Corporation (NOC) to run a number of crude oil fields located on the borders between the two countries.

        The agreement included updating a study that was carried out on 2006 concerning Al-Rar and Al-Wafa oilfields, which located on the shared borders between Algeria and Libya, according to a statement by Sonatrach.

        Al-Rar gas field is located on the Algerian side of the border, while Al-Wafa oilfield is located on the Libyan side of the border.

        An official at Sonatrach, who preferred anonymity, told Anadolu Agency, said the study would “clarify the hypothesis of the connection between the Algerian Al-Rar gas field and the Libyan Al-Wafa oil field.”

        Read More: Foreign intervention in Libya ‘frustrating progress’

        “If it was proved that the two fields are in fact one field, they will be run and managed jointly by the two countries,” the source noted.

        In September 2006, DeGolyer & MacNaughton (D&M) conducted a study, which aimed at confirming the existence of a connection between the two fields. The study depended on a data that was provided by Sonatrach and NOC.

        “Through the agreement, the two companies decided to update the old study using the technical data collected from January 2008 to present,” the source pointed out, adding that the two companies are also seeking to achieve the optimal utilization for the two fields through the agreement.

        Sonatrach have been halting all its projects and investments in Libya since the 2011 Arab Spring.

        The oil extraction industry in Libya has been experiencing security hurdles, a fact that has led to a reduction in the country’s daily oil production by 30 per cent.
        Source: https://www.middleeastmonitor.com/20180116-algeria-libya-agree-to-jointly-manage-oil-fields-on-shared-border/


  • 2017


    • DeGolyer and MacNaughton Signe un Accord de cooperation avec SOCAR

      novembre 9, 2017

      • DeGolyer and MacNaughton Signe un Accord de cooperation avec SOCAR
        Amélioration de la performance et le développement des gisements d huile et de gaz azerbaïdjanais

        Mrs John Wallace et Martin Wiewiorowski de D & M ont rencontré cette semaine Mr Rovnag Abdullayev, président de SOCAR, pour signer un accord visant à aider cette compagnie pétrolière et gazière publique, à améliorer l’efficacité des efforts de développement dans les champs pétroliers et gaziers du pays.

        Selon un communiqué publié par le gouvernement azerbaïdjanais, D & M examinera les plans de développement de 20 champs et préparera des recommandations pour accroître la production et la récupération du pétrole, réduire les coûts de production pétrolière et définir des objectifs stratégiques à court terme. D & M participera également à la mise en œuvre de ces recommandations.



        SOCAR announces Cooperative Agreement

    • D&M organise des séminaires et des séances d’information à l’intention des Dirigeants

      août 9, 2017

      • D & M organise des séminaires et des briefings sur les réservoirs non conventionnels
        Présentations axées sur la gestion des réservoirs et l’analyse du rendement des puits

        En raison de leur nature unique, les actifs non conventionnels présentent des défis dans l’estimation des réserves et des ressources. Au cours des dix dernières années en Amérique du Nord, les sociétés pétrolières, les opérateurs et les banques ont financé le developpemnt des ressources non conventionnelles à un rythme remarquable. Pourtant, des questions liées à la projection et aux prévisions exactes des flux de trésorerie et de la production des puits reste en suspens. Bien que l industrie a progresse avec des puits latéraux longs et a niveaux multiples.
        La Production à partir de ces ressources est, par nature, une fonction combinée des propriétés du réservoir et du fluide, de la géologie et des complétions, et par conséquent, la prévision de la production n’est pas un simple exercice d’ajustement de courbe.

        Dans sa série Executive Briefing 2017 et sa série Unconventional Short Course,
        DeGolyer and MacNaughton (D & M) a revise son approch pour répondre à ces questions ainsi que les problèmes associés à l’estimation des réserves et des ressources, comme le soulignent les lettres et pratiques récentes de la comission SEC. L’auditoire de plus de 150 cadres a été composé de clients de D & M et de non-clients et représentait plus de 60% de la valeur marchande de toutes les sociétés pétrolières et gazières en amont répertoriées en Amérique du Nord. De plus, de nombreuses sociétés privees, des entités de banque d’investissement et des sociétés nord-américaines et internationales de gestion de patrimoine et de capital prive, ainsi que des super-majors, étaient présents. Au cours des séances d’information, de nombreux points de vue ont été partagés lors des examens annuels indépendants de D & M portant sur plus de 40% des puits de ressources non conventionnelles en Amérique du Nord. La méthodologie de D & M pour évaluer les réservoirs non conventionnels a été partagée en détail, y compris la combinaison de D & M de diagnostic de production, d’analyse, d’analyse basée sur un modèle et de données de réservoir statique et completion .
        « L’approche de D & M est unique, correcte et très opportune » –participants lors du Briefing exécutif des ressources non conventionnelles 2017
        Les commentaires généraux des cadres présents à ces briefings ont été que «l’approche [ressources non conventionnelles] de D & M est unique [parmi ses pairs], correcte [techniquement] et très opportune.» En effet,
        L’utilisation de l’approche de D & M est applicable quotidiennement Plutôt que purement pendant le cycle d’estimation des réserves.

        Approche diagnostique est déjà utilisée par les ingénieurs de D & M pour examiner et estimer avec plus de précision les performances des puits de ressources non conventionnels. Les ingénieurs de D & M apportent un ensemble unique de connaissances à travers l’utilisation de cette approche cohérente. Il est prévu que des connaissances supplémentaires seront tirées de l’examen continu de ces puits, d’autant plus que les plans de completion sont affinés, évoluent et devraient établir de nouveaux repères économiques pour des formations particulières.

        Le cours abrégé Unconventionnel : « Analyse de la performance du puits et prévisions dans les réserves non conventionnelles » a été assure par le DrDilhan Ilk, qui dirige les activités de conseil en ressources non conventionnelles de D & M. Dans ce cours, M. Ilk a passé en revue les fondements théoriques de la méthodologie utilisée pour analyser et prévoir la production. Des exemples de son application à partir de plays majeurs ont été examinés en détail, et des idées tirées du travail de D & M ont été présentées pour améliorer le travail continu des participants dans des ressources non conventionnelles.

        L’une des technologies déployées par D & M pour apuyer son approche des ressources non conventionnelles est le module d’analyse de la production sur le gisement (Citrine) de Kappa Engineering. Qui a developpe Ce nouveau module en collaboration avec D & M et permet le chargement rapide et massif de donnees d origine publiques, des clients ou de simulation pour le traitement de données multipuits. Particulièrement adapté aux plays non conventionnels, Citrine utilise l’identification des tendances par visualisation et la comparaison multi-puits pour permettre aux utilisateurs de comprendre et d’interpréter pleinement les performances de gisement à l’aide de diagnostics et

        D’analyse de courbe de déclin.
        Cliquez ici pour en savoir plus.

        si vous le souhaitez le Dr Ilk peut organiser une version personalisee du cours abrégé non conventionnel : « Analyse du rendement des puits et prévisions dans les réservoirs non conventionnels » pour votre organisation.

        En plus de l’événement informationnel du 28 août 2017 à Denver, D & M tiendra à l’avenir, d’autres séances d’information à l’intention des cadres supérieurs.

        si vous souhaitez participer aux événements futurs.

        Dr. Dilhan Ilk, vice-président chez D & M, est une autorité de premier plan dans l’analyse de la performance des puits pour les réservoirs non conventionnels. Le présentateur principal pour chacune des réunions, Mr. Ilk dit que de nombreuses entreprises surestiment le potentiel des puits non conventionnels ou du moins ne regardent pas de façon réaliste le cycle de vie de la production.

        Dr. Dilhan Ilk

         

    • Citrine Field Production Analysis

      août 7, 2017

      • Kappa Engineering, en collaboration avec DeGolyer and MacNaughton , a publié un nouveau module qui permet le chargement rapide de donnees massives d origine publiques, de clients ou de simulation pour le traitement de données multipuits. Particulièrement adapté aux plays non conventionnels, Citrine utilise l’identification des tendances de visualisation et la comparaison multipuits pour permettre aux utilisateurs de comprendre et d’interpréter pleinement les performances sur le gisement à l’aide de diagnostics et d’analyse des courbes de déclin.

        Apprendre encore plus.


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