Worldwide Petroleum Consulting
The Outdoor Classroom Seminar: Integrated Reservoir Appraisal and Reservoir Modeling

The Outdoor Classroom Seminar: Integrated Reservoir Appraisal and Reservoir Modeling

February 23, 2018

What you will learn: Through this immersive field-based seminar, students will improve their understanding of modeling and their abilities to model geological features affecting reservoir performance through the collection, observation, interpretation, and modeling of geologic, petrophysical, and engineering data. Seminar instructors will present methods for collecting, analyzing, and interpretating data to most efficiently appraise reservoir size and characteristics. Over the course of the seminar, students will visit outcrops that reveal the complex but interpretable geologic features that influence reservoir development. These outcrop observations, along with wireline log data, petrophysical data collected from nearby boreholes, will be incorporated into the geocellular models that must be developed and simulated during the 5-day course.

Who Should Attend: This course is designed for petroleum engineers, geologists, geophysicists, petrophysicists, and supervisory personnel responsible for executing field-development programs focused on primary, secondary, or tertiary-recovery projects in conventional terrigineous-clastic reservoirs. The geologic and engineering concepts and practices introduced in the seminar are applicable to reservoirs spanning all depositional settings.

See Brochure Link for more details! Integrated Reservoir Appraisal and Development Seminar Final

Costs: TBD per person and includes:

  • 5 day seminar
  • Field guide and exercise materials
  • Transportation during seminar
  • Lunch, snacks, and drinks during the seminar

           Additional costs (responsibility of attendees)

  • Transportation to and from Salt Lake City, Utah on May 6, returning May 12.
  • Meals other than lunch during the five-day course
  • Hotel costs


Gazprom Neft: Reserves Replacement at 170%

February 22, 2018

Gazprom Neft:  Reserves Replacement at 170%

Gazprom Neft has completed auditing of the company’s hydrocarbon reserves as at 2017. As at 31 December 2017 the company’s total proved and probable hydrocarbon reserves (proved + probable — 2P based on SPE-PRMS international standards,* including proportional shares in production at joint enterprises**) totalled 2.78 billion tonnes of oil equivalent (toe) — a year-on-year increase of 2.3 percent. Production volumes in 2017, at 89.75 mtoe, were compensated by reserves replacement in the order of 170 percent. The audit was undertaken by independent international consulting company DeGolyer and MacNaughton.

Proved 1P hydrocarbons as at end 2017 are estimated at 1.52 btoe — an increase of 0.6 percent, year-on-year. The reserve replacement ratio for this category of reserves is 110 percent Gazprom Neft’s reserves-to-production ratio in terms of proved hydrocarbon reserves (SPE-PRMS standards) is 17 years. According to SEC standards,*** the company’s total hydrocarbon reserves stand at 1.34 mtoe (an increase of 3.4 percent over 2017).

Drilling of 27 prospecting and exploratory wells was completed in this accounting period, with drilling meterage in 2017 increasing by 41.2 percent (to 94,600 metres). Four new wells and 42 hydrocarbon deposits were discovered last year throughout the group’s licence blocks.

A key positive factor in allowing the company to expand its resources base has been the fine-tuning of technologies in geological prospecting and development drilling, together with the implementation of dynamic ranking for all company options. Gazprom Neft’s new assets — including the TazovskoyeSevero-Samburgskoye and Kamennomysskoye fields — have all made a major contribution to expanding the company’s resource base.

An assessment of prospective resources at Gazprom Neft’s licence blocks on the Arctic Shelf was undertaken for the first time in 2017, with DeGolyer and MacNaughton estimating these at 1.6 billion tonnes of oil and three trillion cubic metres of gas.

Vadim Yakovlev, First Deputy CEO, Gazprom Neft, commented: «Gazprom Neft last year continued its consistent development of its upstream projects, as well as undertaking work on accessing new licence blocks. Major discoveries were confirmed, which have made the company’s resource base still more balanced and high-quality. The company’s priority development vectors continue to include improving quality in the development of new reserves, active work in studying low-permeability strata, and implementing a programme for improving efficiency in production in those regions in which the company has traditionally operated.»



Abraxas Provides Reserve and Operational Update

February 20, 2018

SAN ANTONIO–(BUSINESS WIRE)–Abraxas Petroleum Corporation (“Abraxas” or the “Company”) (NASDAQ:AXAS) today provided the following reserve and operational update. Highlights include:

  • Total proved reserves as of December 31, 2017 of 65.9 MMBoe up 21.2 MMBoe or 47.5%
  • Proved developed producing (“PDP”) reserves grew 48.5% to 20.7 MMBoe
  • PV-10 (1) of $425.9 million using SEC 12-month average pricing of $51.34/bbl and $2.99/mcf natural gas
  • 2017 reserve replacement ratio of 887%
  • 2017 PDP finding and development (“PDP F&D”) cost of $10.42/Boe
  • In the Delaware Basin, Abraxas booked 17 gross Wolfcamp A1, 17 gross Wolfcamp A2, two gross Wolfcamp B and two gross Third Bone Spring proved undeveloped locations across four gross sections at Caprito (1320 foot spacing assumed)
  • In the Delaware Basin, Abraxas booked an additional eight gross Third Bone Spring, Wolfcamp A1 and Wolfcamp A2 proved undeveloped locations across four additional gross sections
  • Potential downspacing and the remainder of Abraxas’ leasehold in the Delaware Basin remains unbooked for future years
  • In Ward County, Texas, the Caprito 82-101, a 4,820 foot lateral and the Company’s first Third Bone Spring well, averaged 1,122 Boepd (878 barrels of oil per day, 1,463 mcf of natural gas per day)(2) over the well’s first 30 days of production
  • In Ward County, Texas, the Caprito 82-202, a 4,820 foot lateral targeting the Wolfcamp A1, averaged 1,134 Boepd (863 barrels of oil per day, 1,626 mcf of natural gas per day)(2) over the well’s first 30 days of production

https://www.businesswire.com/news/home/20180220005422/en/Abraxas-Reserve-Operational-Update

December 31, 2017 Reserves

As of December 31, 2017, Abraxas’ proved oil and natural gas reserves consisted of approximately 65.9 MMBoe, a net increase of 21.2 MMBoe or 47.5% over 2016 year-end reserves of 44.7 MMBoe. December 31, 2017 reserves consisted of approximately 37.6 million barrels of oil, 12.0 million barrels of NGLs and 97.8 billion cubic feet of natural gas. PDP reserves were 20.7 MMBoe an increase of 48.5% over 2016 PDP reserves and comprised 31.4% of proved reserves as of December 31, 2017.

The SEC-priced pre-tax PV-10 (1) (a non-GAAP financial measure) was $425.9 million, using 2017 average prices of $51.34/bbl of oil and $2.99/mcf of natural gas. Realized pricing, including differentials, used in this calculation equated to $46.82/bbl of oil and $1.79/mcf of natural gas.

Net proved reserve additions of 23.9 MMBoe resulted in a reserve replacement ratio of 887% (defined as the sum of extensions, discoveries, revisions and purchases, divided by annual production). PDP F&D cost (defined as total drilling and completion capital expenditures divided by total PDP reserve additions) was $10.42/Boe.

The majority of Abraxas’ reserve additions came from the Delaware Basin, where Abraxas booked 17 gross Wolfcamp A1, 17 gross Wolfcamp A2, two gross Wolfcamp B and two gross Third Bone Spring proved undeveloped locations across four gross sections at Caprito (1320 foot spacing assumed). Abraxas booked an additional eight gross Third Bone Spring, Wolfcamp A1 and Wolfcamp A2 proved undeveloped locations across four additional gross sections. The remainder of Abraxas’ leasehold in the Delaware Basin remains entirely unbooked for future years. Abraxas also sold 1.3 MMBoe of reserves during 2017.

The independent reserve engineering firm DeGolyer and MacNaughton prepared a complete engineering analysis on 98.5% of Abraxas’ proved reserves on a Boe basis.

The following table outlines changes in Abraxas’ proved reserves from December 31, 2016:

Oil

(MMbbl)

Natural Gas

(Bcf)

NGL

(MMbbl)

Total

(MMBoe)

Proved Reserves December 31, 2016 24.2

70.8

8.6 44.7
Additions 14.5 14.5 2.8 19.8
Purchases 0.0 1.0 0.0 0.2
Revisions 0.8 19.3 1.3 5.3
Sales (0.4 ) (4.0 ) (0.3 ) (1.3 )
Production (1.6 ) (3.9 ) (0.5 ) (2.7 )
Proved Reserves December 31, 2017 37.6 97.8 12.0 65.9

Fourth Quarter and Year End 2017 Production and CAPEX Update

Production for the fourth quarter of 2017 averaged approximately 8,788 Boepd (5,325 barrels of oil per day, 12,334 mcf of natural gas per day, 1,407 barrels of NGL per day). Production for the year ending December 31, 2017 averaged approximately 7,391 Boepd (4,311 barrels of oil per day, 10,655 mcf of natural gas per day, 1,304 barrels of NGL per day).

Capital expenditures for the year ended December 31, 2017 are expected to be approximately $135 million ($132 million cash and $3 million stock issuance). Approximately $31 million of the capital expenditures were spent on acquisitions with the remainder spent on drilling, completion and facilities.

Operations Update

In Ward County, Texas, the Caprito 82-101H, a 4,820 foot lateral and the Company’s first Third Bone Spring test, averaged 1,122 Boepd (878 barrels of oil per day, 1,463 mcf of natural gas per day)(2) over the well’s first 30 days of production. The Caprito 82-202H, a 4,820 foot lateral targeting the Wolfcamp A1 zone, averaged 1,134 Boepd (863 barrels of oil per day, 1,626 mcf of natural gas per day)(2) over the well’s first 30 days of production. Abraxas owns a 100% and 57.1% working interest in the Caprito 82-101H and 82-202H, respectively.

Bob Watson, President and CEO of Abraxas, commented, “We are pleased to report our sixth consecutive year of production and reserve growth. 2018 promises to be a continuation of this trend with substantial upside left to be booked in the Delaware Basin and current production rates that are 50% higher than our 2017 average production. Our focused inventory of highly economic development locations in the Bakken and Wolfcamp/Bone Spring position us to drive multiple-years of high-return production and reserve growth for our shareholders.

“We are also pleased to announce another highly productive zone on our Ward County acreage in the Third Bone Spring. This represents the fourth zone we have derisked in Ward County. We are currently testing downspacing on our acreage. The results of this will dictate the optimal development of these four zones on our acreage. Importantly, very little of this potential or downspacing is currently booked as proved undeveloped reserves, which bodes well for future reserve growth.”

(1) The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2016 and 2017:

December 31,
(in thousands) 2016 2017
PV-10 $ 160,600 $ 425,936
Estimated present value of future income taxes discounted at 10%

(32,448

)

Standardized measure of discounted future net cash flows $ 160,600 $

393,488

(2) The 30-day average rates represent the highest 30 days of production and do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.

Abraxas Petroleum Corporation is a San Antonio based crude oil and natural gas exploration and production company with operations in the Williston Basin, Permian Basin and South Texas regions of the United States.

Safe Harbor for forward-looking statements: Statements in this release looking forward in time involve known and unknown risks and uncertainties, which may cause Abraxas’ actual results in future periods to be materially different from any future performance suggested in this release. Such factors may include, but may not be necessarily limited to, changes in the prices received by Abraxas for crude oil and natural gas. In addition, Abraxas’ future crude oil and natural gas production is highly dependent upon Abraxas’ level of success in acquiring or finding additional reserves. Further, Abraxas operates in an industry sector where the value of securities is highly volatile and may be influenced by economic and other factors beyond Abraxas’ control. In the context of forward-looking information provided for in this release, reference is made to the discussion of risk factors detailed in Abraxas’ filings with the Securities and Exchange Commission during the past 12 months.

Contacts

Abraxas Petroleum Corporation
Geoffrey King, 210-490-4788
Vice President – Chief Financial Officer
gking@abraxaspetroleum.com
www.abraxaspetroleum.com



Ecopetrol Group increases its hydrocarbon reserves, proven reserves mount to 1,659 million barrels-equivalent at 2017 close

February 19, 2018

https://www.prnewswire.com/news-releases/ecopetrol-group-increases-its-hydrocarbon-reserves-proven-reserves-mount-to-1659-million-barrels-equivalent-at-2017-close-300600891.html

BOGOTÁ, Colombia, Feb. 19, 2018 /PRNewswire/ — Ecopetrol (BVC: ECOPETROL; NYSE: EC) today announced its proven reserves of oil, condensate and natural gas (1P reserves), including its share in affiliates and subsidiaries, as of December 31, 2017.

Reserves were estimated based on US Securities and Exchange Commission (SEC) standards and methodologies. 99% of the reserves were audited by two well-known, independent, specialized firms (Ryder Scott Company and Degolyer and MacNaughton).

At the 2017 close, the Ecopetrol Group’s net proven reserves were 1,659 million barrels of oil-equivalent. The reserve replacement index was 126%, with average reserve life equivalent to 7.1 years.

95% of the proven reserves are owned by Ecopetrol S.A., while Hocol, Ecopetrol America and the Equión and Savia Perú interests contributed 5%. Ecopetrol S.A. has an average reserve life of 7.4 years.

In 2017, the Ecopetrol Group incorporated 295 million barrels of oil-equivalent of proven reserves, representing a positive change in the reserves incorporation trend in recent years. The year’s total accumulated production was 234 million barrels of oil-equivalent.

The SEC price used for valuation of the 2017 reserves was USD 54.93 per Brent barrel, versus USD 44.49 per Brent barrel in 2016. Ecopetrol estimates that 94 million barrels of oil equivalent were recovered as a result of the higher price effect due to the extension of the fields’ economic limit and the incorporation of new projects. It is further estimated that the company’s technical management and financial optimization of assets contributed 201 million barrels of oil equivalent.

We note that much of the increase in proven reserves (73 MBOE) is due to the results of the Recovery Factor Increase program, the principal gains of which occurred in fields such as Chichimene, Castilla, Casabe and Tibú. This result is very satisfactory, as it is one of the pillars of the company’s growth in reserves and production.

 

Ecopetrol Group Proven Reserves 2015 – 2017

2015

2016

2017

Proven

2.084

1.849

1.598

Revisions

-25

-54

175

Enhanced Recovery

16

11

73

Mineral Purchases

0

0

4

Extensions and discoveries

24

27

44

Sales

0.0

0.0

0.0

Production

-251

-235

-234

Net proven reserves Dec 17

1.849

1.598

1.659

Bogotá D.C., February 19, 2018

————————————–

This release contains statements that may be considered forward looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933 and Section 21E of the U.S. Securities Exchange Act of 1934. All forward-looking statements, whether made in this release or in future filings or press releases or orally, address matters that involve risks and uncertainties, including in respect of the Company’s prospects for growth and its ongoing access to capital to fund the Company’s business plan, among others. Consequently, changes in the following factors, among others, could cause actual results to differ materially from those included in the forward-looking statements: market prices of oil & gas, our exploration and production activities, market conditions, applicable regulations, the exchange rate, the Company’s competitiveness and the performance of Colombia’s economy and industry, to mention a few. We do not intend, and do not assume any obligation to update these forward-looking statements.

For further information contact:
Capital Markets Manager
María Catalina Escobar
Telephone: +571-234-5190
Email: investors@ecopetrol.com.co

Media Relations (Colombia)
Jorge Mauricio Tellez
Telephone: +571-234-4329
Email: mauricio.tellez@ecopetrol.com.co

SOURCE Ecopetrol S.A.



Antero Resources (AR) Announces 12% Increase in Estimated Proved Reserves to 17.3 Tcfe

February 14, 2018

https://www.streetinsider.com/Corporate+News/Antero+Resources+%28AR%29+Announces+12%25+Increase+in+Estimated+Proved+Reserves+to+17.3+Tcfe/13808873.html

Antero Resources (NYSE: AR) (“Antero” or the “Company”) today announced estimated reserves as of December 31, 2017.

Highlights:

  • Proved reserves increased by 12% to 17.3 Tcfe at year-end 2017 (36% liquids), compared to year-end 2016
  • Pre-tax PV-10 of proved reserves at year-end 2017 was $10.8 billion at SEC pricing, including hedges
  • Proved developed reserves increased by 23% to 8.5 Tcfe at year-end 2017, compared to year-end 2016
  • $0.54 per Mcfe proved developed finding and development cost for 2017
  • $0.37 per Mcfe future development cost for year-end 2017 proved undeveloped reserves
  • 3P reserves increased by 18% to 54.6 Tcfe at year-end 2017 (25% liquids), compared to year-end 2016
  • Pre-tax PV-10 of 3P reserves at year-end 2017 was $18.4 billion at SEC pricing, including hedges

Antero’s estimated proved reserves at December 31, 2017 were 17.3 Tcfe, a 12% increase compared to estimated proved reserves at December 31, 2016. Proved, probable and possible (“3P”) reserves at year-end 2017 totaled 54.6 Tcfe, which represents an 18% increase compared to the previous year. For further discussion of 3P reserves, please read “Non-GAAP Disclosure.”

Proved developed finding and development (“F&D”) cost for estimated proved developed reserve additions was $0.54 per Mcfe for 2017. All-in F&D cost for estimated proved reserve additions, including acquisitions, was $0.59 per Mcfe for 2017. Future development costs for proved undeveloped locations are estimated to be $0.37 per Mcfe. The reserve life of the Company’s estimated proved reserves is approximately 21 years based on 2017 production. For further discussion of all-in F&D cost and proved developed F&D cost, please read “Non-GAAP Disclosure.” Antero’s estimated proved and 3P reserves at December 31, 2017 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton (“D&M”). D&M’s reserve audit covered properties representing 100% of Antero’s total 3P reserves at December 31, 2017.

Estimated Proved Reserves

As of December 31, 2017, the Company’s 17.3 Tcfe of estimated proved reserves were comprised of 64% natural gas, 35% NGLs and 1% oil. The Marcellus Shale accounted for 90% of estimated proved reserves and the Ohio Utica Shale accounted for 10%. For 2017, Antero added 1.7 Tcfe of estimated proved reserves organically, excluding acquisitions, which is reflective of the continued productivity gains from the use of advanced completion techniques and longer laterals.

All 381 proved undeveloped locations in the Marcellus at year-end 2017 were booked at an approximate 2 Bcf/1,000′ type curve. This compares to year-end 2016 at which time 81 proved undeveloped locations, or 21% of the total proved undeveloped locations in the Marcellus, were booked at the approximate 2 Bcf/1,000′ type curve. The primary driver behind the increase in the number of proved undeveloped locations booked at the higher approximate 2 Bcf/1,000′ type curve type curve is the increased production history observed from the implementation of advanced completions techniques.

Estimated proved developed reserves increased by 23% from year-end 2016 to 8.5 Tcfe at December 31, 2017. The percentage of estimated proved reserves classified as proved developed increased to 49% at December 31, 2017 from 45% at year-end 2016. The average heating content of Antero’s proved undeveloped locations is 1237 BTU, and the average lateral length is approximately 10,500 feet.

Under the Securities and Exchange Commission (“SEC”) reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking. The Company reclassified 2,778 Bcfe of formerly non-proved reserves to proved undeveloped due to their addition to Antero’s five-year development plan. Included in this reclassification was the revision of 286 Bcfe related to an improvement in performance from advanced completions and a 291 Bcfe revision related to a lateral extension of previously booked locations. Additionally, the Company reclassified 2,280 Bcfe of generally lower BTU proved undeveloped reserves to the probable category in 2017 to comply with the SEC five-year development rule. Antero’s 8.8 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.37 per Mcfe.

Antero incurred estimated capital costs of approximately $1.7 billion during 2017, including drilling and completion costs of $1.282 billion, proved property acquisitions of $176 million and leasehold additions of $204 million. Based on the $1.7 billion of capital costs, 2017 all-in F&D cost for proved reserve additions from all sources, including acquisitions and revisions, was $0.59 per Mcfe.

Summary of Changes in Estimated Proved Reserves (in Bcfe)

Balance at December 31, 2016

15,386

Extensions, discoveries and additions

1,711

Purchases of estimated proved reserves

373

Revisions to prior estimates

726

Ethane recovery revision

(113)

Production

(822)

Balance at December 31, 2017

17,261

The table below summarizes both SEC and strip pricing as of December 31, 2017 and the associated PV-10 for estimated proved reserves and hedge values:

2017 Year-End

Benchmark Pricing:

SEC Pricing

Strip Pricing(1)

Variance

% Variance

WTI Oil Price ($/Bbl)

$51.03

$53.44

$2.41

5%

Appalachian Oil Price ($/Bbl)(2)

$45.35

$47.70

$2.35

5%

Nymex Natural Gas Price ($/MMBtu)

$3.11

$2.93

$(0.18)

(6)%

Appalachian Natural Gas Price ($/MMBtu)(2)

$2.91

$2.63

$(0.28)

(10)%

C3+ Natural Gas Liquids ($/Bbl) (3)

$32.37

$32.23

$(0.14)

0%

C2+ Natural Gas Liquids ($/Bbl)(3)

$20.40

$20.62

$0.22

1%

Pre-Tax PV-10 Values ($Bn):

Estimated proved reserves PV-10

$10.2

$9.1

$(1.1)

(11)%

Hedge PV-10 (4)

0.6

1.2

0.6

100%

Total PV-10

$10.8

$10.3

$(0.5)

(5)%

1)

Strip pricing as of December 31, 2017 for each of the first ten years and flat thereafter.

2)

Represents SEC and strip prices as of December 31, 2017 on a weighted average Appalachian index basis related to company-specific sales points.

3)

Represents realized NGL price including regional market differentials.

4)

Hedge PV-10 at strip pricing differs from year-end 2017 mark-to-market value of $1.3 billion due to the application of a higher discount rate.

Proved, Probable and Possible Reserves

Antero estimates that it had year-end 2017 3P reserves of 54.6 Tcfe, an 18% increase from year-end 2016. The 18% increase in 3P reserves was driven by a combination of increased type curves in certain areas driven by continued productivity gains from advanced completions, as well as 2017 leasehold acquisitions. As of December 31, 2017, the Company’s 54.6 Tcfe of 3P reserves were comprised of 75% natural gas, 23% NGLs and 2% oil. The Marcellus and Ohio Utica Shale comprised 48.3 Tcfe and 6.4 Tcfe of the 3P reserves, respectively. Virtually no Upper Devonian or West Virginia Utica reserves were included in 3P reserves.

Importantly, 46.2 Tcfe of Antero’s 48.3 Tcfe, or 96% of estimated Marcellus 3P reserves were classified as proved and probable reserves (“2P”), reflecting the low risk and statistically repeatable nature of Antero’s resource base. The 46.2 Tcfe of Marcellus 2P reserves includes 381 proved undeveloped and 460 probable locations, or 26% of the total undeveloped 2P reserve locations in the Marcellus that were booked at the approximate 2 Bcf/1,000′ type curve. This compares to year-end 2016 where 81 proved undeveloped and 7 probable locations, or just 3% of the total undeveloped 2P reserve locations in the Marcellus were booked at the approximate 2 Bcf/1,000′ type curve. The increase in upgraded 2P locations is primarily driven by continued productivity gains from implementing advanced completions techniques across a larger subset of Antero’s acreage position. Further, 6.2 Tcfe of Antero’s 6.4 Tcfe, or 97% of estimated 3P reserves in the Ohio Utica were classified as 2P.

The tables below summarize Antero’s estimated 3P reserve volumes as of December 31, 2017 using SEC pricing, categorized by operating area as well as PV-10 values of Antero’s 3P reserve volumes using both SEC and strip pricing. For further discussion of 3P reserves, please read “Non-GAAP Disclosure.”

Marcellus Shale

Ohio Utica Shale

Gas

(Bcf)

Liquids

(MMBbl)

Total (Bcfe)

Gross Locations

Gas

(Bcf)

Liquids

(MMBbl)

Total

(Bcfe)

Gross Locations

Proved

9,726

971

15,553

1,054

1,372

56

1,708

243

Probable

24,174

1,079

30,645

2,864

3,978

85

4,489

524

Possible

1,688

67

2,089

267

142

4

164

51

Total 3P

35,588

2,117

48,287

4,185

5,492

145

6,361

818

% Liquids(1)

26%

14%

Combined 3P Reserves

Gas

(Bcf)

Liquids

(MMBbl)

Total

(Bcfe)

Gross Locations

Proved(2)

11,098

1,027

17,261

1,297

Probable

28,152

1,164

35,134

3,388

Possible

1,830

70

2,253

318

Total 3P

41,080

2,261

54,648

5,003

% Liquids(1)

25%

1) Represents liquids volumes as a percentage of total volumes. Combined liquids comprised of 812 million

barrels of ethane, 1.3 billion barrels of C3+ NGLs and 131 million barrels of oil

2) 427 of the 1,297 proved locations were undeveloped locations

Pre-Tax 3P PV-10 Values ($ Billions):

SEC Pricing

Strip Pricing(1)

Variance

% Variance

3P Reserves PV-10

$17.8

$15.5

$(2.3)

(13)%

Hedge PV-10 (2)

0.6

1.2

0.6

100%

Total PV-10

$18.4

$16.7

$1.7

(9)%

1) Strip pricing as of December 31, 2017 for each of the first ten years and flat thereafter

2) Hedge PV-10 at strip pricing differs from year-end 2017 mark-to-market value of $1.3 billion due to the application of a higher discount rate

Non-GAAP Disclosure

Certain selected financial information in this release is unaudited. Additional unaudited financial information will be provided in Antero’s Annual Report on Form 10-K for the year ended December 31, 2017, which the Company filed with the SEC on February 13, 2018. In this release, Antero has provided a number of unaudited metrics, which include all-in F&D cost per unit and proved developed F&D cost per unit. These non-GAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company’s ability of adding and developing reserves at a reasonable cost. The F&D costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the F&D costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies. There are no directly comparable financial measures presented in accordance with GAAP for all-in F&D cost per unit and proved developed F&D cost per unit, and therefore a reconciliation to GAAP is not practicable.

Calculations for all-in and proved developed F&D cost per unit are based on costs incurred in 2017. The calculations for both all-in and proved developed F&D cost per unit do not include future development costs required for the development of proved undeveloped reserves.

Pre-tax PV10 values and pre-tax PV-10 values including hedges are non-GAAP financial measures as defined by the SEC. Antero believes that the presentation of these pre-tax PV10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves and hedges prior to taking into account corporate future income taxes and the Company’s current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves and hedges as compared with other companies. Antero believes that PV10 estimates using strip pricing and including hedges can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV10 value using SEC pricing.

The GAAP financial measure most directly comparable to pre-tax PV10 is the standardized measure of discounted future net cash flows (“Standardized Measure”). The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (Standardized measure) at December 31, 2017:

(In millions, except per Mcf data)

At December 31, 2017

Future net cash flows

$

26,137

Present value of future net cash flows:

Before income tax (PV-10)

$

10,175

Income taxes

$

(1,548)

After income tax (Standardized measure)

$

8,627

Notwithstanding their use for comparative purposes, the Company’s non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.

Antero has provided summations of its proved, probable and possible reserves and summations of its PV-10 for its proved, probable and possible reserves in this press release. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because estimates of probable and possible reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use.