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Antero Resources Corporation (AR) (“Antero” or the “Company”) today released its third quarter 2014 financial results. The relevant financial statements are included in Antero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, which has been filed with the Securities and Exchange Commission (“SEC”).

Third Quarter 2014 and Other Highlights:

  • Net daily gas equivalent production averaged 1,080 MMcfe/d, a 91% increase over the prior year quarter
  • Included net daily liquids production of 25,000 Bbl/d, a 217% increase over the prior year quarter
  • Liquids comprised 28% of total product revenues before hedges and 14% of total equivalent volumes, increases of 54% and 66% over the prior year quarter, respectively 
  • Realized natural gas price after hedging averaged $4.31 per Mcf, a $0.25 premium to Nymex Henry Hub
  • Realized NGL price (C3+) averaged $46.66 per barrel, approximately 48% of Nymex WTI
  • Realized natural gas equivalent price averaged $4.91 per Mcfe including NGLs, oil and hedges, an $0.85 premium to Nymex Henry Hub
  • Adjusted net income was $72 million, or $0.27 per basic and diluted share, a 47% increase over the prior year quarter
  • Adjusted EBITDAX was $292 million, a 59% increase over the prior year quarter
  • Priced initial public offering of midstream MLP raising $1.0 billion in gross proceeds
  • Added 32,000 net acres in the core of the Marcellus and Utica Shale plays resulting in 520,000 total net acres in the Appalachian Basin

Recent Developments

Antero Midstream Partners LP IPO Pricing and New Midstream Credit Facility

On November 4, 2014, Antero Midstream Partners LP (the “Partnership”) announced the pricing of its initial public offering of 40,000,000 common units representing limited partner interests in the Partnership at $25.00 per common unit.  The Partnership has also granted the underwriters a 30-day option to purchase up to an additional 6,000,000 common units. The common units began trading on the New York Stock Exchange today under the symbol “AM.” The offering is expected to close on November 10, 2014, subject to the satisfaction of customary closing conditions.

The assets of the Partnership initially include gathering and compression assets that service Antero’s Appalachian production.  Antero’s fresh water distribution business was retained at Antero Resources subject to an option on behalf of the Partnership to potentially acquire these assets at a later date.

Antero and its affiliates own 73.7% of the 151,881,914 outstanding common and subordinated units (or 69.7% if the underwriters exercise in full their option to purchase additional common units) and the remaining 26.3% is owned by the public (or 30.3% if the underwriters exercise in full their option to purchase additional common units).

Total gross proceeds from the offering will be $1 billion and net proceeds will be $947 million (or approximately $1.1 billion if the underwriters exercise in full their option to purchase additional common units), and Antero will receive $696 million (or $838 million if the underwriters exercise in full their option to purchase additional common units) as reimbursement of certain capital expenditures incurred and repayment for outstanding indebtedness with the Partnership.  The Partnership will retain $250 million of the net proceeds for general partnership purposes.

Upon closing the IPO, a new fully undrawn $1 billion credit facility will be in place at the Partnership for future funding needs.  Wells Fargo Bank, N.A. and JPMorgan Chase Bank, N.A. are co-lead arrangers for the midstream credit facility which includes 17 banks in total.  The term of the LIBOR-based facility is five years.

Antero Resources Borrowing Base Increase

On October 16, 2014, Antero announced that the borrowing base under its upstream credit facility had been increased to $4.0 billion, a $1.0 billion increase over Antero’s previous borrowing base.  In addition, lender commitments under the facility were increased by $500 million to $3.0 billion.  The $3.0 billion commitment can be expanded to the full $4.0 billion borrowing base upon bank approval.

JPMorgan Chase Bank, N.A and Wells Fargo Bank, N.A. are co-lead managers for Antero’s upstream credit facility which includes 26 banks in total.  As of September 30, 2014, on a pro forma basis to give effect to the lender commitment and borrowing base increase as well as proceeds from the IPO of the Partnership, the Company would have had approximately $800 million drawn under the credit facility and $332 million in letters of credit outstanding, resulting in approximately $1.9 billion of available liquidity and approximately $2.9 billion of unused borrowing base capacity.

Marcellus Processing Update

MarkWest recently placed in service Sherwood 5, a 200 MMcf/d cryogenic processing plant at the Sherwood facility located in Doddridge County, West Virginia.  This now gives Antero access to 950 MMcf/d of firm processing capacity in the Marcellus.  The Company has also committed to Sherwood 6 and 7, two additional 200 MMcf/d cryogenic processing plants.  Sherwood 6 is expected to go on line in the second quarter of 2015 and Sherwood 7 is expected to go on line in the third quarter of 2015.  In total, Antero has committed to 1.35 Bcf/d of firm cryogenic processing capacity in the Marcellus.  Ethane is currently being rejected at the Sherwood facility and sold in the residue gas stream which results in Antero receiving a Btu premium.

Marcellus and Utica Acreage Update

Since the second quarter 2014 operations update release on July 17, 2014, Antero has increased its Marcellus acreage position by 17,000 net acres resulting in 386,000 total net acres in the southwestern core of the Marcellus Shale play.  Pro forma for these net acreage additions, approximately 30% of Antero’s total net acreage was associated with proved locations and approximately 10% with proved developed locations at mid-year 2014.  Approximately 73% of the Marcellus total net acreage, or 282,000 net acres, is believed to contain processable rich gas assuming an 1100 Btu cutoff.

Additionally, since the second quarter 2014 operations update release, Antero has increased its Utica acreage position by 15,000 net acres resulting in 134,000 total net acres in the core of the Utica Shale play.  Included in the net acreage additions is a recently closed acquisition with an undisclosed third-party for a consolidated 12,000 net acre position in the rich gas core totaling $185 million.  The Company funded this transaction using its credit facility.  Pro forma for these net acreage additions, approximately 10% of Antero’s total net acreage was associated with proved locations and approximately 4% with proved developed locations at mid-year 2014.  Approximately 76% of the Utica total net acreage, or 102,000 net acres, is believed to contain processable rich gas assuming an 1100 Btu cutoff.

Third Quarter 2014 Financial Results

For the three months ended September 30, 2014, Antero reported net income from continuing operations of $204 million, or $0.78 per basic and diluted share, compared to net income from continuing operations of $118 million, or $0.45 per basic and diluted share, in the third quarter of 2013.  The GAAP net income for the third quarter of 2014 included the following items:

  • Non-cash gains on unsettled hedges of $252 million ($156 million net of tax)
  • Non-cash stock compensation expense primarily for outstanding profits interests awards, that are non-dilutive to public stockholders, of $24 million ($21 million net of tax)
  • Impairment of unproved properties of $5 million ($3 million net of tax)

Excluding these items, the Company’s non-GAAP results for the third quarter of 2014 were as follows:

  • Adjusted net income from continuing operations of $72 million, or $0.27 per basic and diluted share, a 47% increase compared to $49 million, or $0.19 per basic and diluted share, in the third quarter of 2013
  • Adjusted EBITDAX of $292 million, a 59% increase compared to $183 million in the third quarter of 2013
  • Adjusted EBITDAX margin of $2.93 per Mcfe, a 16% decrease compared to $3.51 per Mcfe in the third quarter of 2013

For reconciliations of adjusted net income from continuing operations, adjusted EBITDAX and adjusted EBITDAX margin to the most comparable GAAP measures, please see “Non-GAAP Financial Measures.”

Net production for the third quarter of 2014 averaged a Company record 1,080 MMcfe/d, an increase of 91% from the third quarter of 2013.  Third quarter 2014 net liquids production averaged a Company record 25,009 Bbl/d, an increase of 217% from the third quarter of 2013.  Net production was comprised of 930 MMcf/d of natural gas (86%), 21,225 Bbl/d of NGLs (12%) and 3,784 Bbl/d of crude oil (2%).

Antero’s average realized natural gas price before hedging for the third quarter of 2014 was $3.63 per Mcf, a $0.43 negative differential to the Nymex Henry Hub average price for the period.  Approximately 39% of Antero’s third quarter 2014 natural gas production was priced at the TCO index and the remaining natural gas production was priced at various other index pricing points including Dominion South (35%), Nymex Henry Hub (10%), Chicago (10%) and Tetco M2 (6%).

For the third quarter of 2014, Antero realized a cash settled natural gas hedge gain of $58 million, or $0.68 per Mcf.  This cash settled natural gas hedge gain included $38 million associated with hedges at the Dominion South index, $19 million associated with hedges at the TCO index, and $1 million associated with Nymex Henry Hub hedges.  Antero’s average realized natural gas price after hedging for the third quarter of 2014 was $4.31 per Mcf, a $0.25 per Mcf premium to the Nymex Henry Hub average price for the period.

Antero’s average realized C3+ NGL price for the third quarter of 2014 was $46.66 per barrel, or approximately 48% of the Nymex WTI oil price average for the period, and the average oil price before hedges was $84.17 per barrel.

Average natural gas equivalent price including NGLs, oil and hedge settlements was $4.91 per Mcfe, a 5% decrease as compared to the third quarter of 2013.

Marketing revenue for the third quarter of 2014 was $18 million.  Antero’s marketing revenue was primarily associated with the sale of third-party gas purchased to utilize the Company’s excess firm transportation capacity on the Rockies Express Pipeline.

GAAP revenue for the third quarter of 2014 was $762 million as compared to $385 million for the third quarter of 2013.  GAAP revenue for the third quarter of 2014 included a $252 million non-cash gain on unsettled hedges while the third quarter of 2013 included a $115 million non-cash gain on unsettled hedges. Non-GAAP adjusted net revenue increased 90% to $511 million compared to the third quarter of 2013, including cash settled hedge gains but excluding non-cash unsettled hedge gains.  Liquids production contributed 28% of natural gas, NGLs and oil revenue before hedges in the third quarter of 2014 compared to 18% during the third quarter of 2013.  Please see “Non-GAAP Financial Measures” for a reconciliation of GAAP revenue to Non-GAAP adjusted net revenue.

Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and production tax) for the third quarter of 2014 was $1.60 per Mcfe, representing a 14% increase compared to $1.40 per Mcfe in the prior year quarter due to the significant increase in liquids production.  Per unit general and administrative expense for the third quarter of 2014, excluding non-cash stock compensation expense, was $0.29 per Mcfe compared to $0.28 per Mcfe for the prior year quarter.  Per unit depreciation, depletion and amortization expense (“DD&A”) decreased 1% from the prior year quarter to $1.26 per Mcfe.

Marketing expense for the third quarter of 2014 was $32 million.  The largest components of marketing expense were the cost of purchasing third-party gas and the firm transport demand costs associated with the Company’s currently unused ATEX ethane pipeline capacity.

Adjusted EBITDAX of $292 million for the third quarter of 2014 was 59% higher than the prior year quarter due to increased production and revenue.  Adjusted EBITDAX margin for the quarter was $2.93 per Mcfe representing a 16% decrease over the prior year quarter due to lower commodity prices.  Cash flow from operations before changes in working capital was $245 million, a 74% increase compared to $141 million in the third quarter of 2013.

Paul Rady, Chairman and CEO, commenting on the Company’s third quarter production and Antero’s firm transportation portfolio, said, “Antero set a new net production record this quarter averaging almost 1.1 Bcfe/d.  Our net production also included a record 25,000 Bbl/d of liquids.  We continue to be on track with meeting our 2014 production guidance as well as our 45% to 50% growth targets for both 2015 and 2016.  To accommodate this growth profile, we have designed our firm transportation portfolio in a very strategic manner in order to provide us with attractively priced and geographically diverse end markets.  During the next two years we expect to utilize over 90% of our total contracted firm transport volumes for sales and marketing efforts with a minimal $0.02/Mcfe to $0.03/Mcfe of expected unutilized capacity charges.”

Glen Warren, President and CFO, commenting on the Company’s price realizations, said, “During the third quarter we realized a $0.25 per Mcf premium to Nymex for our natural gas production including hedges.  We forecast that we will continue to realize premium gas prices relative to Nymex through 2016 due to our firm transportation capacity to favorable markets including TCO, Gulf Coast and Chicago, our high Btu residue gas and our hedges.  Lastly, after including the impact of liquids value, we realized an $0.85 per Mcfe premium to Nymex for our gas-equivalent production.”

For a reconciliation of adjusted EBITDAX, adjusted EBITDAX margin and cash flow from operations before changes in working capital to the most comparable GAAP measures, please see “Non-GAAP Financial Measures.”

Capital Spending

Antero’s total capital expenditures for the three months ended September 30, 2014 were $1.1 billion, including drilling and completion costs of $621 million, gathering and compression costs of $145 million, fresh water distribution project costs of $57 million and leasehold costs of $279 million including the aforementioned $185 million acquisition of 12,000 net acres in the Utica Shale play.

Conference Call

A conference call is scheduled on Thursday, November 6, 2014 at 9:00 a.m. MT to discuss the results for the quarter.  A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter.  To participate in the call dial 877-300-8521 (U.S.), 855-669-9657 (Canada), or 412-317-6026 (International) and reference passcode 10053701. A telephone replay of the call will be available until November 16, 2014 at 9:00 a.m. MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the same passcode.

A simultaneous webcast of the call may be accessed over the internet atwww.anteroresources.com.  The webcast will be archived for replay on the Company’s website until November 16, 2014 at 9:00 a.m. MT.

Presentation

An updated company presentation will be posted to Antero’s website before the November 6, 2014 conference call.  Additionally, a separate conference call presentation will be posted to accompany certain planned comments to be made by management during the call.  These presentations can be found at www.anteroresources.com on the homepage.  Information on the Company’s website does not constitute a portion of this press release.

Non-GAAP Financial Measures

Adjusted net revenue as set forth in this release represents total revenue adjusted for unsettled hedge (gains) and losses.  Antero believes that adjusted net revenue is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net revenue is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total revenue as an indicator of financial performance.  The following table reconciles total revenue to adjusted net revenue:

Three months ended

Nine months ended

September 30,

September 30,

2013

2014

2013

2014

Total revenue

$

384,522

$

762,490

$

833,120

$

1,242,035

Commodity derivative (gains) losses

(161,968)

(308,975)

(285,510)

63,720

Cash receipts for settled derivatives

47,034

57,451

109,311

57,333

Adjusted net revenue

$

269,588

$

510,966

$

656,921

$

1,363,088

Adjusted net income from continuing operations as set forth in this release represents net income from continuing operations adjusted for certain items.  Antero believes that adjusted net income from continuing operations is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net income from continuing operations is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income from continuing operations as an indicator of financial performance.  The following table reconciles net income from continuing operations to adjusted net income from continuing operations:

Three months ended

Nine months ended

September 30,

September 30,

2013

2014

2013

2014

Net income from continuing operations

$

117,794

$

203,909

$

200,990

$

64,655

Non-cash commodity derivative (gains) losses on unsettled derivatives, net of tax

(70,990)

(155,984)

(108,830)

75,072

Impairment of unproved properties, net of tax

1,980

2,817

5,907

4,896

Stock compensation expense, net of tax

20,944

79,272

Loss on early extinguishment of debt, net of tax

12,642

Adjusted net income from continuing operations

$

48,784

$

71,686

$

98,067

$

236,537

Cash flow from operations before changes in working capital as set forth in this release represents net cash provided by operating activities before changes in working capital.  Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt.  Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry.  In turn, many investors use this published research in making investment decisions.  Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.

The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release:

Three months ended
September 30,

Nine months ended

September 30,

2013

2014

2013

2014

Net cash provided by operating activities

$

139,540

$

300,717

$

331,937

$

798,746

Net change in working capital

1,194

(55,621)

(13,529)

(96,153)

Cash flow from operations before changes in working capital

$

140,734

$

245,096

$

318,408

$

702,593

Adjusted EBITDAX is a non-GAAP financial measure that Antero defines as net income from continuing operations after adjusting for those items shown in the table below.  Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP.  Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.  Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.  Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero’s management team believes adjusted EBITDAX is useful to an investor in evaluating the Company’s financial performance because this measure:

  • is widely used by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods selected and book value of assets, capital structure and the method by which assets were acquired, among other factors;
  • helps investors to more meaningfully evaluate and compare the results of Antero’s operations from period to period by removing the effect of its capital structure from its operating structure; and
  • is used by the Company’s management team for various purposes, including as a measure of operating performance, in presentations to its board of directors, as a basis for strategic planning and forecasting and by its lenders pursuant to covenants under its credit facility and the indentures governing the Company’s senior notes.

There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero’s net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies.  The following table represents a reconciliation of the Company’s net income from continuing operations to adjusted EBITDAX, a reconciliation of adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before settled hedges to adjusted EBITDAX Margin:

Three months ended

Nine months ended

September 30,

September 30,

2013

2014

2013

2014

Net income from continuing operations

$

117,794

$

203,909

$

200,990

$

64,655

Commodity derivative fair value (gains) losses

(161,968)

(308,975)

(285,510)

63,720

Net cash receipts on settled derivative instruments

47,034

57,451

109,311

57,333

Interest expense

37,444

42,455

100,840

111,057

Loss on early extinguishment of debt

20,386

Income tax expense

67,370

135,035

120,695

75,919

Depreciation, depletion, amortization and accretion

65,963

124,944

159,447

321,915

Impairment of unproved properties

3,205

4,542

9,564

7,895

Exploration expense

5,372

7,476

17,034

21,176

Stock compensation expense

24,285

85,896

State franchise taxes

620

450

1,820

1,738

Adjusted EBITDAX from continuing operations

182,834

291,572

434,191

831,690

Net income from discontinued operations

3,100

3,100

2,210

Gain on sale of assets

(5,000)

(5,000)

(3,564)

Income tax expense

1,900

1,900

1,354

Adjusted EBITDAX from discontinued operations

Total adjusted EBITDAX

182,834

291,572

434,191

831,690

Interest expense

(37,444)

(42,455)

(100,840)

(111,057)

Exploration expense

(5,372)

(7,476)

(17,034)

(21,176)

Changes in current assets and liabilities

(1,194)

55,621

13,529

96,153

State franchise taxes

(620)

(450)

(1,820)

(1,738)

Other non-cash items

1,336

3,905

3,911

4,874

Net cash provided by operating activities

$

139,540

$

300,717

$

331,937

$

798,746

Three months ended

Nine months ended

September 30,

September 30,

Adjusted EBITDAX margin ($ per Mcfe):

2013

2014

2013

2014

Realized price before settled hedges

$

4.27

$

4.33

$

4.27

$

5.06

Gathering, compression, and water distribution revenues

0.05

0.05

Lease operating expense

(0.05)

(0.09)

(0.04)

(0.07)

Gathering, compression, processing and transportation costs

(1.12)

(1.29)

(1.15)

(1.26)

Marketing, net

(0.14)

(0.14)

Production taxes

(0.23)

(0.22)

(0.24)

(0.26)

General and administrative(1)

(0.27)

(0.29)

(0.30)

(0.30)

Adjusted EBITDAX margin before settled hedges

2.60

2.35

2.54

3.08

Cash receipts for settled hedges

0.91

0.58

0.85

0.23

Adjusted EBITDAX margin

$

3.51

$

2.93

$

3.39

$

3.31

(1) – excludes franchise taxes and stock compensation that are included in G&A

Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional oil and liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our website is located atwww.anteroresources.com.

This release includes “forward-looking statements”.  Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. All statements, other than historical facts included in this release, are forward-looking statements.  All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in Antero’s Annual Report on Form 10-K for the year ended December 31, 2013.

 

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2013 and September 30, 2014

(Unaudited)

(In thousands, except share amounts)

Assets

2013

2014

Current assets:

Cash and cash equivalents

$

17,487

6,308

Accounts receivable – trade, net of allowance for doubtful accounts of $1,251 in 2013 and 2014

30,610

66,755

Accrued revenue

96,825

144,014

Derivative instruments

183,000

280,959

Other

5,642

4,667

Total current assets

333,564

502,703

Property and equipment:

Natural gas properties, at cost (successful efforts method):

Unproved properties

1,513,136

1,915,683

Proved properties

3,621,672

5,605,619

Fresh water distribution systems

231,684

390,966

Gathering systems and facilities

584,626

1,064,855

Other property and equipment

15,757

32,593

5,966,875

9,009,716

Less accumulated depletion, depreciation, and amortization

(407,219)

(722,731)

Property and equipment, net

5,559,656

8,286,985

Derivative instruments

677,780

458,209

Other assets, net

42,581

67,983

Total assets

$

6,613,581

9,315,880

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2013 and September 30, 2014

(Unaudited)

(In thousands, except share amounts)

Liabilities and Stockholders’ Equity

2013

2014

Current liabilities:

Accounts payable

$

370,640

598,538

Accrued liabilities

77,126

178,840

Revenue distributions payable

96,589

169,446

Deferred income tax liability

69,191

106,721

Derivative instruments

646

Other

8,037

10,491

Total current liabilities

622,229

1,064,036

Long-term liabilities:

Long-term debt

2,078,999

4,137,866

Deferred income tax liability

278,580

318,323

Derivative instruments

86

Other long-term liabilities

35,113

44,147

Total liabilities

3,014,921

5,564,458

Commitments and contingencies

Stockholders’ equity:

Common stock, $0.01 par value; authorized – 1,000,000,000 shares; issued and outstanding 262,049,659 shares and 262,051,067 shares, respectively

2,620

2,621

Preferred stock, $0.01 par value; authorized – 50,000,000 shares; none issued

Additional paid-in capital

3,402,180

3,488,076

Accumulated earnings

193,860

260,725

Total stockholders’ equity

3,598,660

3,751,422

Total liabilities and stockholders’ equity

$

6,613,581

9,315,880

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Three Months Ended September 30, 2013 and 2014

(Unaudited)

(In thousands, except per share amounts)

2013

2014

Revenue:

Natural gas sales

$

182,125

310,390

Natural gas liquids sales

31,956

91,111

Oil sales

8,473

29,304

Gathering, compression, and water distribution

4,875

Marketing

17,835

Commodity derivative fair value gains

161,968

308,975

Total revenue

384,522

762,490

Operating expenses:

Lease operating

2,697

8,680

Gathering, compression, processing, and transportation

58,383

128,531

Production and ad valorem taxes

11,851

21,726

Marketing

32,192

Exploration

5,372

7,476

Impairment of unproved properties

3,205

4,542

Depletion, depreciation, and amortization

65,697

124,624

Accretion of asset retirement obligations

266

320

General and administrative (including stock compensation expense of $24,210 in 2014)

14,443

53,000

Total operating expenses

161,914

381,091

Operating income

222,608

381,399

Other expenses:

Interest

(37,444)

(42,455)

Income from continuing operations before income taxes and discontinued operations

185,164

338,944

Provision for income tax expense

(67,370)

(135,035)

Income from continuing operations

117,794

203,909

Discontinued operations:

Income from sale of discontinued operations, net of income tax expense of $1,900 in 2013

3,100

Net income and comprehensive income

$

120,894

203,909

Earnings per common share:

Continuing operations

$

0.45

0.78

Discontinued operations

0.01

Total

$

0.46

0.78

Earnings per common share – assuming dilution

Continuing operations

$

0.45

0.78

Discontinued operations

0.01

Total

$

0.46

0.78

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Nine Months Ended September 30, 2013 and 2014

(Unaudited)

(In thousands, except per share amounts)

2013

2014

Revenue:

Natural gas sales

$

476,403

936,877

Natural gas liquids sales

59,772

244,807

Oil sales

11,435

89,059

Gathering, compression, and water distribution

11,964

Marketing

23,048

Commodity derivative fair value gains (losses)

285,510

(63,720)

Total revenue

833,120

1,242,035

Operating expenses:

Lease operating

5,222

18,570

Gathering, compression, processing, and transportation

148,023

315,878

Production and ad valorem taxes

30,578

64,123

Marketing

58,119

Exploration

17,034

21,176

Impairment of unproved properties

9,564

7,895

Depletion, depreciation, and amortization

158,650

320,984

Accretion of asset retirement obligations

797

931

General and administrative (including stock compensation expense of $85,821 in 2014)

40,727

162,342

Total operating expenses

410,595

970,018

Operating income

422,525

272,017

Other expenses:

Interest

(100,840)

(111,057)

Loss on early extinguishment of debt

(20,386)

Total other expenses

(100,840)

(131,443)

Income from continuing operations before income taxes and discontinued operations

321,685

140,574

Provision for income tax expense

(120,695)

(75,919)

Income from continuing operations

200,990

64,655

Discontinued operations:

Income from sale of discontinued operations, net of income tax expense of $1,900 and $1,354, respectively

3,100

2,210

Net income and comprehensive income

$

204,090

66,865

Earnings per common share:

Continuing operations

$

0.77

0.25

Discontinued operations

0.01

0.01

Total

$

0.78

0.26

Earnings per common share – assuming dilution

Continuing operations

$

0.77

0.25

Discontinued operations

0.01

0.01

Total

$

0.78

0.26

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2013 and 2014

(Unaudited)

(In thousands)

2013

2014

Cash flows from operating activities:

Net income

$

204,090

66,865

Adjustment to reconcile net income to net cash provided by operating activities:

Depletion, depreciation, amortization, and accretion

159,447

321,915

Impairment of unproved properties

9,564

7,895

Derivative fair value (gains) losses

(285,510)

63,720

Cash receipts for settled derivatives

109,311

57,333

Deferred income tax expense

120,695

75,919

Stock compensation expense

85,896

Loss on early extinguishment of debt

20,386

Gain on sale of discontinued operations

(5,000)

(3,564)

Deferred income tax expense – discontinued operations

1,900

1,354

Other

3,911

4,874

Changes in assets and liabilities:

Accounts receivable

(11,727)

(36,145)

Accrued revenue

(39,453)

(47,189)

Other current assets

1,702

975

Accounts payable

(4,602)

530

Accrued liabilities

44,720

105,278

Revenue distributions payable

22,889

72,857

Other

(153)

Net cash provided by operating activities

331,937

798,746

Cash flows used in investing activities:

Additions to unproved properties

(342,832)

(518,247)

Drilling and completion costs

(1,165,248)

(1,723,657)

Additions to fresh water distribution systems

(101,838)

(156,467)

Additions to gathering systems and facilities

(240,119)

(406,666)

Additions to other property and equipment

(3,225)

(12,539)

Change in other assets

(11,622)

(6,896)

Net cash used in investing activities

(1,864,884)

(2,824,472)

Cash flows from financing activities:

Issuance of senior notes

231,750

1,102,500

Repayment of senior notes

(260,000)

Borrowings on bank credit facility, net

1,295,500

1,217,000

Make-whole premium on debt extinguished

(17,383)

Payments of deferred financing costs

(8,334)

(27,570)

Other

6,626

Net cash provided by financing activities

1,525,542

2,014,547

Net decrease in cash and cash equivalents

(7,405)

(11,179)

Cash and cash equivalents, beginning of period

18,989

17,487

Cash and cash equivalents, end of period

$

11,584

6,308

Supplemental disclosure of cash flow information:

Cash paid during the period for interest

$

70,221

67,299

Supplemental disclosure of noncash investing activities:

Increase in accounts payable for additions to property and equipment

$

134,525

227,368

 

OPERATING DATA

The following table sets forth selected operating data for the three months ended September 30, 2013 compared to the three months ended September 30, 2014:

Three Months Ended

September 30,

Amount of
Increase

2013

2014

(Decrease)

Percent Change

(in thousands, except per unit and production data)

Operating revenues:

Natural gas sales

$

182,125

310,390

128,265

70

%

NGL sales

31,956

91,111

59,155

185

%

Oil sales

8,473

29,304

20,831

246

%

Gathering, compression, and water distribution

4,875

4,875

*

Marketing

17,835

17,835

*

Commodity derivative fair value gains

161,968

308,975

147,007

*

Total operating revenues

384,522

762,490

377,968

98

%

Operating expenses:

Lease operating

2,697

8,680

5,983

222

%

Gathering, compression, processing, and transportation

58,383

128,531

70,148

120

%

Production and ad valorem taxes

11,851

21,726

9,875

83

%

Marketing

32,192

32,192

*

Exploration

5,372

7,476

2,104

39

%

Impairment of unproved properties

3,205

4,542

1,337

42

%

Depletion, depreciation, and amortization

65,697

124,624

58,927

90

%

Accretion of asset retirement obligations

266

320

54

20

%

General and administrative (before stock compensation)

14,443

28,790

14,347

99

%

Stock compensation

24,210

24,210

*

Total operating expenses

161,914

381,091

219,177

135

%

Operating income

222,608

381,399

158,791

71

%

Other Expenses:

Interest expense

(37,444)

(42,455)

(5,011)

13

%

Income before income taxes and discontinued operations

185,164

338,944

153,780

83

%

Income tax expense

(67,370)

(135,035)

(67,665)

100

%

Income from continuing operations

117,794

203,909

86,115

73

%

Income from discontinued operations

3,100

(3,100)

*

Net income

$

120,894

203,909

83,015

69

%

Adjusted EBITDAX

$

182,834

291,572

108,738

59

%

Production data:

Natural gas (Bcf)

48

86

38

79

%

NGLs (MBbl)

637

1,953

1,316

206

%

Oil (MBbl)

87

348

261

299

%

Combined (Bcfe)

52

99

47

91

%

Daily combined production (MMcfe/d)

566

1,080

514

91

%

Average prices before effects of hedges:

Natural gas (per Mcf)

$

3.82

$

3.63

$

(0.19)

(5)

%

NGLs (per Bbl)

$

50.13

$

46.66

$

(3.47)

(7)

%

Oil (per Bbl)

$

97.10

$

84.17

$

(12.93)

(13)

%

Combined (per Mcfe)

$

4.27

$

4.33

$

0.06

1

%

Average realized prices after effects of hedges:

Natural gas (per Mcf)

$

4.81

$

4.31

$

(0.50)

(10)

%

NGLs (per Bbl)

$

50.13

$

46.66

$

(3.47)

(7)

%

Oil (per Bbl)

$

94.71

$

82.47

$

(12.24)

(13)

%

Combined (per Mcfe)

$

5.18

$

4.91

$

(0.27)

(5)

%

Average Costs (per Mcfe):

Lease operating

$

0.05

$

0.09

$

0.04

80

%

Gathering, compression, processing, and transportation

$

1.12

$

1.29

$

0.17

15

%

Production and ad valorem taxes

$

0.23

$

0.22

$

(0.01)

(4)

%

Depletion, depreciation, amortization, and accretion

$

1.27

$

1.26

$

(0.01)

(1)

%

General and administrative (before stock compensation)

$

0.28

$

0.29

$

0.01

4

%

 

OPERATING DATA

The following table sets forth selected operating data for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2014:

Nine Months Ended

September 30,

Amount of
Increase

2013

2014

(Decrease)

Percent Change

(in thousands, except per unit and production data)

Operating revenues:

Natural gas sales

$

476,403

936,877

460,474

97

%

NGL sales

59,772

244,807

185,035

310

%

Oil sales

11,435

89,059

77,624

679

%

Gathering, compression, and water distribution

11,964

11,964

*

Marketing

23,048

23,048

*

Commodity derivative fair value gains (losses)

285,510

(63,720)

(349,230)

*

Total operating revenues

833,120

1,242,035

408,915

49

%

Operating expenses:

Lease operating

5,222

18,570

13,348

256

%

Gathering, compression, processing, and transportation

148,023

315,878

167,855

113

%

Production and ad valorem taxes

30,578

64,123

33,545

110

%

Marketing

58,119

58,119

*

Exploration

17,034

21,176

4,142

24

%

Impairment of unproved properties

9,564

7,895

(1,669)

(17)

%

Depletion, depreciation, and amortization

158,650

320,984

162,334

102

%

Accretion of asset retirement obligations

797

931

134

17

%

General and administrative (before stock compensation)

40,727

76,521

35,794

88

%

Stock compensation

85,821

85,821

*

Total operating expenses

410,595

970,018

559,423

136

%

Operating income

422,525

272,017

(150,508)

(36)

%

Other Expenses:

Interest expense

(100,840)

(111,057)

(10,217)

10

%

Loss on early extinguishment of debt

(20,386)

(20,386)

*

Total other expenses

(100,840)

(131,443)

(30,603)

30

%

Income before income taxes and discontinued operations

321,685

140,574

(181,111)

(56)

%

Income tax expense

(120,695)

(75,919)

44,776

(37)

%

Income from continuing operations

200,990

64,655

(136,335)

(68)

%

Income from discontinued operations

3,100

2,210

(890)

(29)

%

Net income

$

204,090

66,865

(137,225)

(67)

%

Adjusted EBITDAX

$

434,191

831,690

397,499

92

%

Production data:

Natural gas (Bcf)

120

217

97

81

%

NGLs (MBbl)

1,197

4,602

3,405

285

%

Oil (MBbl)

122

1,010

888

728

%

Combined (Bcfe)

128

251

123

96

%

Daily combined production (MMcfe/d)

470

920

450

96

%

Average prices before effects of hedges:

Natural gas (per Mcf)

$

3.96

$

4.31

$

0.35

9

%

NGLs (per Bbl)

$

49.95

$

53.20

$

3.25

7

%

Oil (per Bbl)

$

93.76

$

88.15

$

(5.61)

(6)

%

Combined (per Mcfe)

$

4.27

$

5.06

$

0.79

19

%

Average realized prices after effects of hedges:

Natural gas (per Mcf)

$

4.87

$

4.58

$

(0.29)

(6)

%

NGLs (per Bbl)

$

49.95

$

53.20

$

3.25

7

%

Oil (per Bbl)

$

90.28

$

86.57

$

(3.71)

(4)

%

Combined (per Mcfe)

$

5.12

$

5.29

$

0.17

3

%

Average Costs (per Mcfe):

Lease operating

$

0.04

$

0.07

$

0.03

75

%

Gathering, compression, processing, and transportation

$

1.15

$

1.26

$

0.11

10

%

Production and ad valorem taxes

$

0.24

$

0.26

$

0.02

8

%

Depletion, depreciation, amortization, and accretion

$

1.24

$

1.28

$

0.04

3

%

General and administrative (before stock compensation)

$

0.32

$

0.30

$

(0.02)

(6)

%