DeGolyer & MacNaughton | World Wide Petroleum Consultants

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

Emily Riccardi — Thu, 06 Jun 2019 17:26:13 +0000

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

Emily Riccardi — Thu, 09 May 2019 16:28:07 +0000

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

Emily Riccardi — Tue, 07 May 2019 14:34:10 +0000

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

Emily Riccardi — Wed, 17 Apr 2019 20:37:22 +0000

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

Kimberly Ramos — Wed, 10 Apr 2019 13:32:44 +0000

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/

Bahrain Seeks US Partners for Offshore Shale Discovery

Emily Riccardi — Fri, 05 Apr 2019 15:21:55 +0000

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

Emily Riccardi — Mon, 01 Apr 2019 15:17:58 +0000

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

Emily Riccardi — Wed, 20 Mar 2019 12:12:18 +0000

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

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

Emily Riccardi — Thu, 14 Mar 2019 13:55:39 +0000

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

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
Country	Field	Gross		Net		Gross		Net		Gross		Net		Hydrocarbon Type
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)

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

Emily Riccardi — Thu, 14 Mar 2019 13:54:44 +0000

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
YEAR	(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.

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

Emily Riccardi — Fri, 01 Mar 2019 14:45:35 +0000

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

Emily Riccardi — Fri, 01 Mar 2019 14:32:51 +0000

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 CO₂flood 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 CO₂to 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

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,
In thousands	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,
In thousands	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

Emily Riccardi — Fri, 01 Mar 2019 14:31:40 +0000

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.

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

Emily Riccardi — Fri, 01 Mar 2019 14:30:30 +0000

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

View original content:http://www.prnewswire.com/news-releases/callon-petroleum-company-announces-fourth-quarter-2018-results-300802580.html

SOURCE Callon Petroleum Company