Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

v3.19.3.a.u2
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
12 Months Ended
Dec. 31, 2019
Supplemental Information on Oil and Gas Producing Activities (Unaudited)  
Supplemental Information on Oil and Gas Producing Activities (Unaudited)

(21) Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following is supplemental information regarding the Company’s consolidated oil and gas producing activities. The amounts shown include the Company’s net working interests in all of its oil and gas properties.

(a)Capitalized Costs Relating to Oil and Gas Producing Activities

Year ended December 31,

 

(In thousands)

2018

2019

Proved properties

$

12,705,672

11,859,817

Unproved properties

 

1,767,600

 

1,368,854

 

14,473,272

 

13,228,671

Accumulated depletion and depreciation

 

(3,615,680)

 

(3,284,330)

Net capitalized costs

$

10,857,592

9,944,341

(b)Costs Incurred in Certain Oil and Gas Activities

Year ended December 31,

(In thousands)

2017

2018

2019

Acquisition costs:

Proved property

$

175,650

Unproved property

 

204,272

172,387

88,682

Development costs

 

897,287

1,164,800

1,104,336

Exploration costs

 

384,698

323,773

149,782

Total costs incurred

$

1,661,907

1,660,960

1,342,800

(c)Results of Operations for Oil and Gas Producing Activities

Year ended December 31,

 

(In thousands)

2017

2018

2019

Revenues

$

2,747,920

3,652,894

3,643,873

Operating expenses:

Production expenses

 

1,279,217

1,601,985

2,417,509

Exploration expenses

 

8,538

4,958

884

Depletion and depreciation

 

694,332

832,326

884,350

Impairment of oil and gas properties

 

159,598

549,437

1,300,444

Results of operations before income tax (expense) benefit

 

606,235

664,188

(959,314)

Income tax (expense) benefit

 

(228,096)

(156,350)

224,511

Results of operations

$

378,139

507,838

(734,803)

(d)Oil and Gas Reserves

The following table sets forth the net quantities of proved reserves and proved developed reserves during the periods indicated. This information includes the Company’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the years ended December 31, 2017, 2018 and 2019 were prepared by the Company’s reserve engineers and audited by DeGolyer and MacNaughton (“D&M”) utilizing data compiled by the Company. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States.

Proved reserves are the estimated quantities of oil, condensate, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average prices received for the previous 12 months.

Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. The Company’s development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital, future commodity prices, cash flows from operations, future drilling and completion costs, and other economic factors.

Oil and

Natural gas

NGLs

condensate

Equivalents

(Bcf)

(MMBbl)

(MMBbl)

(Bcfe)

Proved reserves:

December 31, 2016

9,414

957

38

15,386

Revisions

342

(22)

(6)

176

Extensions, discoveries and other additions

1,644

77

7

2,148

Production

(591)

(36)

(2)

(822)

Purchases of reserves

289

13

1

373

December 31, 2017

11,098

989

38

17,261

Revisions

(1,087)

8

(1)

(1,042)

Extensions, discoveries and other additions

2,125

98

12

2,781

Production

(711)

(43)

(3)

(989)

Purchases of reserves

December 31, 2018

11,425

1,052

46

18,011

Revisions

(1,735)

25

(11)

(1,648)

Extensions, discoveries and other additions

2,626

169

11

3,705

Production

(822)

(55)

(4)

(1,175)

Purchases of reserves

December 31, 2019

11,494

1,191

42

18,893

Oil and

Natural gas

NGLs

condensate

Equivalents

(Bcf)

(MMBbl)

(MMBbl)

(Bcfe)

Proved developed reserves:

December 31, 2017

5,587

467

16

8,488

December 31, 2018

6,669

600

20

10,389

December 31, 2019

7,229

731

21

11,740

Proved undeveloped reserves:

December 31, 2017

5,511

522

22

8,773

December 31, 2018

4,756

452

26

7,622

December 31, 2019

4,265

460

21

7,153

Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2017, 2018 and 2019 in the above table include the following:

2017 Changes in Reserves

Extensions, discoveries, and other additions of 2,148 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales.
Purchases of 373 Bcfe related to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales.
Net upward revisions of 176 Bcfe include:
Upward revisions of 345 Bcfe related to improved well performance.
Net downward revisions of 188 Bcfe related to revisions to our five-year development plan.  This figure includes upward revisions of 2,092 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2016 to proved undeveloped at December 31, 2017 due to their addition to our five-year development plan, and downward revisions of 2,280 Bcfe for locations that were not developed within five years of initial booking as proved reserves. 
Upward revisions of 132 Bcfe were due to increases in prices for natural gas, NGLs, and oil.
Downward revisions of 113 Bcfe are due to a decrease in our assumed future ethane recovery.
We produced 822 Bcfe during the year ended December 31, 2017.

2018 Changes in Reserves

Extensions, discoveries, and other additions of 2,781 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales.
Net downward revisions of 1,042 Bcfe include:
Downward revisions of 433 Bcfe related to well performance.
Net downward revisions of 742 Bcfe related to optimization to our five-year development plan.  This figure includes upward revisions of 1,722 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan, and downward revisions of 2,464 Bcfe for locations that were not developed within five years of initial booking as proved reserves.
Upward revisions of 18 Bcfe were due to increases in prices for natural gas, NGLs, and oil.
Upward revisions of 115 Bcfe are due to an increase in our assumed future ethane recovery.

We produced 989 Bcfe during the year ended December 31, 2018.

2019 Changes in Reserves

Extensions, discoveries, and other additions of 3,705 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales.
Net downward revisions of 1,648 Bcfe include:
Upward revisions of 63 Bcfe related to well performance.
Net downward revisions of 1,705 Bcfe related to optimization to our five-year development plan.  This figure includes upward revisions of 595 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan, and downward revisions of 2,300 Bcfe for locations that were not developed within five years of initial booking as proved reserves.
Downward revisions of 157 Bcfe were due to increases in prices for natural gas, NGLs, and oil.
Upward revisions of 315 Bcfe are due to an increase in our assumed future ethane recovery.
Downward revisions of 164 Bcfe are due to the deconsolidation of Antero Midstream Partners. Deconsolidation of Antero Midstream Partners resulted in Antero Resources recording the full fees paid to Antero Midstream Partners for services rendered and no longer including future capital expenditures associated with Antero Midstream Partners’ assets in future development costs. Prior to deconsolidation, Antero Resources’ consolidated reserves included the elimination of full fees paid by Antero Resources to Antero Midstream Partners and the inclusion of the operating costs and capital incurred by Antero Midstream Partners.

We produced 1,175 Bcfe during the year ended December 31, 2019.

The following table sets forth the Standardized measure of the discounted future net cash flows attributable to the Company’s proved reserves. Future cash inflows were computed by applying historical 12 month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the Standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of available NOL carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

Year ended December 31,

(in millions)

2017

2018

2019

 

Future cash inflows

$

55,824

64,199

54,228

Future production costs

 

(26,375)

(30,007)

(36,524)

Future development costs

 

(3,312)

(3,453)

(2,772)

Future net cash flows before income tax

 

26,137

30,739

14,932

Future income tax expense

 

(4,104)

(5,505)

(1,639)

Future net cash flows

 

22,033

25,234

13,293

10% annual discount for estimated timing of cash flows

 

(13,406)

(14,756)

(7,824)

Standardized measure of discounted future net cash flows

$

8,627

10,478

5,469

The 12-month weighted average prices used to estimate the Company’s total equivalent reserves were as follows (per Mcfe):

December 31, 2017

$

3.23

December 31, 2018

$

3.56

December 31, 2019

$

2.87

(f) Changes in Standardized measure of Discounted Future Net Cash Flow

Year ended December 31,

(in millions)

2017

2018

2019

Sales of oil and gas, net of productions costs

$

(1,469)

(2,051)

(1,116)

Net changes in prices and production costs (1)

 

3,918

707

(6,729)

Development costs incurred during the period

 

627

755

758

Net changes in future development costs (2)

 

229

37

(92)

Extensions, discoveries and other additions

 

1,448

1,925

782

Acquisitions

 

258

Divestitures

Revisions of previous quantity estimates

 

734

(53)

(1,011)

Accretion of discount

 

368

1,018

1,259

Net change in income taxes

 

(1,159)

(563)

1,513

Changes in timing and other

 

386

76

(373)

Net increase (decrease)

 

5,340

1,851

(5,009)

Beginning of year

 

3,287

8,627

10,478

End of year

$

8,627

10,478

5,469

(1) Includes $3.3 billion in increased production costs due to the deconsolidation of Antero Midstream Partners.

(2) Includes $185 million in increased future development costs due to the deconsolidation of Antero Midstream Partners.