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EX-31.1 - EX-31.1 - Antero Resources Finance Corpa11-9567_1ex31d1.htm
EX-31.2 - EX-31.2 - Antero Resources Finance Corpa11-9567_1ex31d2.htm

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2011

 

OR

 

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from            to            

 

Commission file number 333-164876

 

ANTERO RESOURCES FINANCE CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware

 

90-0522247

(State or other jurisdiction of

 

(IRS Employer Identification No.)

incorporation or organization)

 

 

 

1625 17th Street
Denver, Colorado

 

80202

(Address of principal executive offices)

 

(Zip Code)

 

(303) 357-7310

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x  Yes  o No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o  Yes  o No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x
(Do not check if a smaller reporting company)

 

Smaller reporting company o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o  Yes  x No

 

 

 




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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used , the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010 on file with the Securities and Exchange Commission (Commission File No. 333-164876).  These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

 

Forward-looking statements may include statements about our:

 

·                  business strategy;

 

·                  reserves;

 

·                  financial strategy, liquidity and capital required for our development program;

 

·                  realized natural gas, natural gas liquids (NGLs),  and oil prices;

 

·                  timing and amount of future production of natural gas, NGLs, and oil;

 

·                  hedging strategy and results;

 

·                  future drilling plans;

 

·                  competition and government regulations;

 

·                  pending legal or environmental matters;

 

·                  marketing of natural gas, NGLs, and oil;

 

·                  leasehold or business acquisitions;

 

·                  costs of developing our properties and gathering and other midstream operations;

 

·                  general economic conditions;

 

·                  credit markets;

 

·                  uncertainty regarding our future operating results; and

 

·                  plans, objectives, expectations and intentions contained in this report that are not historical.

 

We caution 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 our 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 our Annual Report on Form 10-K For the Year Ended December 31, 2010 on file with the Securities and Exchange Commission (Commission File No. 333-164876)  and in Part II, Item 1A-“Risk Factors” of this Quarterly Report on Form 10-Q.

 

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Table of Contents

 

Reserve engineering is a process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.

 

Should one or more of the risks or uncertainties described in the Annual Report on Form 10-K or in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

 

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

 

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

 

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Table of Contents

 

PART I - FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

ANTERO RESOURCES LLC

 

Consolidated Balance Sheets

 

December 31, 2010 and March 31, 2011

 

(In thousands)

 

 

 

2010

 

2011

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

 8,988

 

 

Accounts receivable — trade, net of allowance for doubtful accounts of $272 and $181 in 2010 and 2011, respectively

 

26,371

 

26,817

 

Accrued revenue

 

29,468

 

29,086

 

Prepaid expenses

 

7,087

 

9,590

 

Derivative instruments

 

82,960

 

76,656

 

Inventories

 

2,031

 

2,176

 

Total current assets

 

156,905

 

144,325

 

Property and equipment:

 

 

 

 

 

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

 

 

 

 

 

Unproved properties

 

737,358

 

737,481

 

Producing properties

 

1,762,206

 

1,867,002

 

Gathering systems and facilities

 

85,404

 

95,092

 

Other property and equipment

 

5,975

 

6,387

 

 

 

2,590,943

 

2,705,962

 

Less accumulated depletion, depreciation, and amortization

 

(431,181

)

(464,850

)

Property and equipment, net

 

2,159,762

 

2,241,112

 

Derivative instruments

 

147,417

 

76,455

 

Other assets, net

 

22,203

 

21,528

 

Total assets

 

$

 2,486,287

 

2,483,420

 

 

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ANTERO RESOURCES LLC

 

Consolidated Balance Sheets

 

December 31, 2010 and March 31, 2011

 

(In thousands)

 

 

 

2010

 

2011

 

Liabilities and Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

82,436

 

92,896

 

Accrued expenses

 

21,746

 

36,883

 

Revenue distributions payable

 

29,917

 

29,643

 

Advances from joint interest owners

 

1,478

 

1,044

 

Derivative instruments

 

4,212

 

2,165

 

Deferred income tax liability

 

12,694

 

11,782

 

Total current liabilities

 

152,483

 

174,413

 

Long-term liabilities:

 

 

 

 

 

Bank credit facility

 

100,000

 

170,000

 

Senior notes

 

527,632

 

527,556

 

Long-term note

 

25,000

 

25,000

 

Asset retirement obligations

 

5,374

 

5,589

 

Deferred income tax liability

 

77,489

 

69,979

 

Other long-term liabilities

 

3,322

 

3,271

 

Total liabilities

 

891,300

 

975,808

 

Equity:

 

 

 

 

 

Members’ equity

 

1,489,806

 

1,461,366

 

Accumulated earnings

 

105,181

 

46,246

 

Total equity

 

1,594,987

 

1,507,612

 

Total liabilities and equity

 

$

2,486,287

 

2,483,420

 

 

See accompanying notes to consolidated financial statements.

 

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Table of Contents

 

ANTERO RESOURCES LLC

 

Consolidated Statements of Operations

 

Three Months Ended March 31, 2010 and 2011

 

(In thousands)

 

 

 

2010

 

2011

 

Revenue:

 

 

 

 

 

Natural gas sales

 

$

51,727

 

60,858

 

Natural gas liquids sales

 

2,225

 

5,585

 

Oil sales

 

2,114

 

2,528

 

Realized and unrealized gains (losses) on commodity derivative instruments, including unrealized gains (losses) of $98,812 and $(77,266) in 2010 and 2011, respectively

 

111,083

 

(48,028

)

Gas gathering and processing revenue

 

6,413

 

 

Total revenue

 

173,562

 

20,943

 

Operating expenses:

 

 

 

 

 

Lease operating expenses

 

4,598

 

7,301

 

Gathering, compression and transportation

 

10,141

 

17,150

 

Production taxes

 

2,670

 

3,128

 

Exploration expenses

 

1,352

 

3,129

 

Impairment of unproved properties

 

2,262

 

2,318

 

Depletion, depreciation and amortization

 

32,996

 

33,669

 

Accretion of asset retirement obligations

 

73

 

96

 

General and administrative

 

4,412

 

6,361

 

Total operating expenses

 

58,504

 

73,152

 

Operating income (loss)

 

115,058

 

(52,209

)

Other income (expense):

 

 

 

 

 

Interest expense

 

(13,292

)

(15,053

)

Realized and unrealized gains (losses) on interest derivative instruments, net (including unrealized gains of $1,525 and $2,046 in 2010 and 2011, respectively)

 

(1,602

)

(95

)

Total other income (expense)

 

(14,894

)

(15,148

)

Income (loss) before income taxes

 

100,164

 

(67,357

)

Income tax (expense) benefit

 

(11,318

)

8,422

 

Net income (loss)

 

88,846

 

(58,935

)

Noncontrolling interest in net loss (income) of consolidated subsidiary

 

(1,241

)

 

Net income (loss) attributable to Antero equity owners

 

$

87,605

 

(58,935

)

 

See accompanying notes to consolidated financial statements.

 

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Table of Contents

 

ANTERO RESOURCES LLC

 

Consolidated Statements of Cash Flows

 

Three Months Ended March 31, 2010 and 2011

 

(In thousands)

 

 

 

2010

 

2011

 

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

 

$

88,846

 

(58,935

)

Adjustment to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

Depletion, depreciation, and amortization

 

32,996

 

33,669

 

Dry hole costs

 

374

 

1,964

 

Impairment of unproved properties

 

2,262

 

2,318

 

Accretion of asset retirement obligations

 

73

 

96

 

Accretion of bond discount (premium), net

 

(81

)

(76

)

Amortization and write-off of deferred financing costs

 

1,005

 

782

 

Unrealized (gains) losses on derivative instruments, net

 

(100,337

)

75,219

 

Deferred taxes

 

11,318

 

(8,422

)

Changes in current assets and liabilities:

 

 

 

 

 

Accounts receivable

 

3,464

 

(447

)

Accrued revenue

 

(5,128

)

382

 

Other current assets

 

36

 

(2,648

)

Accounts payable

 

848

 

11,838

 

Accrued expenses

 

13,161

 

15,135

 

Revenue distributions payable

 

2,921

 

(274

)

Advances from joint interest owners

 

231

 

(434

)

Net cash provided by operating activities

 

51,989

 

70,167

 

Cash flows from investing activities:

 

 

 

 

 

Additions to unproved properties

 

(5,801

)

(6,069

)

Drilling costs

 

(57,023

)

(104,402

)

Additions to gathering systems and facilities

 

(2,809

)

(9,688

)

Additions to other property and equipment

 

(172

)

(412

)

Increase in other assets

 

(184

)

(107

)

Net cash used in investing activities

 

(65,989

)

(120,678

)

Cash flows from financing activities:

 

 

 

 

 

Issuance of senior notes

 

156,000

 

 

Borrowings on bank credit facility

 

 

70,000

 

Payments on bank credit facility

 

(142,080

)

 

Payments of deferred financing costs

 

(4,243

)

 

Distribution to members

 

 

(28,440

)

Other

 

(32

)

(37

)

Net cash provided by financing activities

 

9,645

 

41,523

 

Net increase in cash and cash equivalents

 

(4,355

)

(8,988

)

Cash and cash equivalents, beginning of year

 

10,669

 

8,988

 

Cash and cash equivalents, end of year

 

$

6,314

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid during the year for interest

 

$

4,306

 

1,468

 

Supplemental disclosure of noncash investing activities:

 

 

 

 

 

Changes in accounts payable for additions to properties, systems and facilities

 

$

9,585

 

(1,378

)

 

See accompanying notes to consolidated financial statements.

 

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ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(1)                     Organization

 

Antero Resources LLC, a limited liability company, and its consolidated subsidiaries (collectively referred to as the Company, we, or our) are engaged in the exploration for and the production of natural gas, natural gas liquids (NGLs), and oil onshore in the United States in unconventional reservoirs, which can generally be characterized as fractured shales and tight sand formations. Our properties are primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Arkoma Basin in Oklahoma, and the Piceance Basin in Colorado. We also have certain midstream gathering and pipeline operations, which are ancillary to our interests in producing properties in these basins. Our corporate headquarters are in Denver, Colorado.

 

Our consolidated financial statements as of December 31, 2010 and March 31, 2011 include the accounts of Antero Resources LLC, and its directly and indirectly owned subsidiaries. The subsidiaries include Antero Resources Corporation (Antero Arkoma), Antero Resources Piceance Corporation (Antero Piceance), Antero Resources Pipeline Corporation (Antero Pipeline), Antero Resources Appalachian Corporation and its subsidiary, Antero Resources Bluestone LLC (Antero Appalachian), and Antero Resources Finance Corporation (Antero Finance) (collectively referred to as the Antero Entities).

 

(2)                     Basis of Presentation and Significant Accounting Policies

 

(a)                      Basis of Presentation

 

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to interim financial information and should be read in the context of the December 31, 2010 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2010 consolidated financial statements have been filed with the SEC in Antero Resources Finance Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010.

 

The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (GAAP) for interim financial information, and accordingly, do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of March 31, 2011, and the results of its operations and its cash flows for the three months ended March 31, 2010 and 2011. All significant intercompany accounts and transactions have been eliminated. Operating results for the period ended March 31, 2011 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results, and other factors.

 

The Company’s exploration and production activities are accounted for under the successful efforts method.

 

As of the date these financial statements were filed with the Securities and Exchange Commission, the company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified.

 

(Continued)

 

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ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(b)                      Use of Estimates

 

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates.

 

The Company’s financial statements are based on a number of significant judgments, assumptions, and estimates, including estimates of gas and oil reserve quantities, which are the basis for the calculation of depreciation, depletion, and amortization, present value of future reserves, and impairment of oil and gas properties. Reserve estimates are by their nature inherently imprecise.

 

(c)                       Risks and Uncertainties

 

Historically, the market for natural gas has experienced significant price fluctuations. Prices for natural gas have been particularly volatile in recent years. The price fluctuations can result from variations in weather, levels of production in a given region, availability of transportation capacity to other regions of the country, and various other factors. Increases or decreases in prices received could have a significant impact on the Company’s future results of operations.

 

(d)                      Cash and Cash Equivalents

 

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents.  The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these investments.

 

At March 31, 2011, Accounts payable in the Consolidated Balance Sheets include credit balances from outstanding checks in zero balance cash accounts.  These credit balances are book overdrafts and are included as a component of Accounts payable in the Consolidated Statements of Cash Flows in deriving Net cash provided by operating activities.

 

(e)                       Derivative Financial Instruments

 

In order to manage its exposure to oil and gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, collar agreements, and other similar agreements relating to natural gas expected to be produced. From time to time, the Company also enters into derivative contracts to mitigate the effects of interest rate fluctuations. To the extent legal right of offset with a counterparty exists, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative position.

 

The Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives are classified as revenues, and changes in the fair value of interest rate derivatives are classified as other income (expense).

 

(f)                         Fair Value Measurements

 

Authoritative accounting guidance defines fair value, establishes a framework for measuring fair value, and requires disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties, and other long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or

 

(Continued)

 

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Table of Contents

 

ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. Instruments that are valued using Level 2 inputs include nonexchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, and interest rate swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures. The Company utilizes its counterparties to assess the reasonableness of its prices and valuation techniques. To the extent a legal right of offset with a counterparty exists, the derivative assets and liabilities are reported on a net basis.

 

(g)                      Income Taxes

 

Antero Resources LLC and each of its subsidiaries file separate federal and state income tax returns. Antero Resources LLC is a partnership for income tax purposes and therefore is not subject to federal or state income taxes. The tax on the income of Antero Resources LLC is borne by the individual members through the allocation of taxable income.

 

The Company and its subsidiaries have combined net operating loss carryforwards (NOLs) as of December 31, 2010 of approximately $509 million. The Company’s deferred tax assets relate primarily to NOLs and its deferred tax liabilities relate primarily to oil and gas properties and unrealized gains on derivative instruments. In assessing the realizability of deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more likely than not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Due to the lack of historical profitable operations and based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will not realize the benefits of all of these deductible differences and has recorded valuation allowances in those subsidiaries having net deferred tax assets to the extent deferred tax assets exceed their deferred tax liabilities. The amount of deferred tax assets considered realizable could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. The Company’s income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 34% to consolidated income for the three month periods ended March 31, 2010 and 2011 primarily because of changes in the valuation allowance resulting from deferred tax liabilities arising in the period.

 

(Continued)

 

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ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(h)                      Impairment of Unproved Properties

 

Unproved properties with significant acquisition costs are assessed for impairment on a property-by-property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Other unproved properties are assessed for impairment on an aggregate basis.

 

Impairment of unproved properties during each of the three months ended March 31, 2011 and 2010 was $2.3 million.

 

(i)                         Industry Segment and Geographic Information

 

We have evaluated how the Company is organized and managed and have identified one operating segment—the exploration and production of oil, natural gas, and natural gas liquids. We consider our gathering, processing, and marketing functions as ancillary to our oil and gas producing activities. All of our assets are located in the United States and all of our revenues are attributable to United States customers.

 

(3)                     Credit Facilities

 

(a)                      Bank Credit Facility

 

In May 2011, we and our lenders entered into an agreement to amend our senior secured revolving bank credit facility (Credit Facility). The amendment provides for increasing the Credit Facility from $1.0 billion to $1.5 billion. The borrowing base was increased from $550 million to $900 million. Current lender commitments total $750 million and can be increased to the full $900 million borrowing base upon approval of the lending bank group.  The maturity date of the Credit Facility was extended to May 2016. The borrowing base is redetermined semiannually and the borrowing base depends on the amount of our proved oil and gas reserves and estimated cash flows from these reserves and our hedge positions. The next redetermination is scheduled to occur in October 2011.

 

The Credit Facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and leverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with its financial debt covenants as of December 31, 2010 and March 31, 2011.

 

As of March 31, 2011, the Company had an outstanding balance under the Credit Facility of $170 million, with a weighted average interest rate of 2.75%, and outstanding letters of credit of approximately $18.5 million. As of December 31, 2010, the Company had an outstanding balance under the Credit Facility of $100 million, with a weighted average interest rate of 2.56%, and outstanding letters of credit of approximately $18.1 million.

 

(Continued)

 

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ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(b)                      Senior Notes

 

On November 17, 2009, an indirect wholly owned finance subsidiary of Antero Resources LLC, Antero Finance, issued $375 million of 9.375% senior notes due December 1, 2017 at a discount of $2.6 million. In January 2010, the Company issued an additional $150 million of the same series of 9.375% senior notes at a premium of $6 million. The notes are unsecured and subordinate to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes are guaranteed on a full and unconditional basis and joint and severally by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Antero Resources LLC has no independent assets or operations. Interest on the notes is payable on June 1 and December 1 of each year. Antero Finance may redeem all or part of the notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015. In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 109.375%. At any time prior to December 1, 2013, Antero Finance may also redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium. If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders. Antero Resources Corporation, the stand-alone parent entity, has insignificant independent assets and no operations. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from its subsidiaries, except those imposed by applicable law.

 

(c)                       Treasury Management Facility

 

On September 14, 2010, the Company executed a stand-alone revolving note with a lender under the senior credit facility which provides for up to $7.5 million of cash management obligations in order to facilitate the Company’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the Credit Facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on September 12, 2011. There were no borrowings outstanding under this facility at December 31, 2010 or March 31, 2011.

 

(d)                      Note Payable

 

The Company assumed a $25 million unsecured note payable in the business acquisition consummated on December 1, 2010. The note bears interest at 9% and is due December 1, 2013.

 

(Continued)

 

9



Table of Contents

 

ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(4)                     Ownership Structure

 

At December 31, 2010 and March 31, 2011, the outstanding units in Antero Resources LLC are summarized as follows:

 

 

 

Units

 

 

 

authorized

 

 

 

and issued

 

Class I units

 

 

107,281,058

 

Class A and B units

 

40,007,463

 

Class A and B profits units

 

19,726,873

 

 

 

 

167,015,394

 

 

At March 31, 2011, 164,927 units are outstanding and not vested under the terms of the preferred and common stock awards in the Antero Entities for which they were exchanged.

 

None of the three classes of outstanding units are entitled to current cash distributions or are convertible into indebtedness. The Company has no obligation to repurchase these units at the election of the unitholders.

 

In the event of a distribution from Antero Resources LLC, amounts available for distribution are distributed according to a formula set forth in the LLC agreement that takes into account the relative priority of the various classes of units outstanding. In the event of a distribution due to the disposition of an individual Antero Entity, a portion of the proceeds is allocated to the employees of the Company based on a requisite return financial threshold. In general, distributions are made first to holders of the Class I units until they have received their investment amount and an 8% special allocation and then, as a group, to the holders of all classes of units together. The Class I units participate on a pro rata basis with the other classes of units in funds available for distributions in excess of the Class I unit investment and special allocation amounts.

 

At December 31, 2010 and March 31, 2011, the Class I units have an aggregate liquidation priority, including the special allocation of 8% per annum, of $1.86 billion and $1.89 billion, respectively.

 

During the three months ended March 31, 2011, the Company distributed $28.4 million to its members to cover their tax liabilities resulting from the sale of the Company’s Oklahoma midstream assets during the fourth quarter of 2010.

 

(5)                     Financial Instruments

 

The carrying values of trade receivables, trade payables, and the Credit Facility at December 31, 2010 and March 31, 2011 approximated market value. The carrying value of the Credit Facility at December 31, 2010 and March 31, 2011 approximated fair value because the variable interest rates are reflective of current market conditions.

 

Based on Level 2 market data, the fair value of the Company’s senior notes was approximately $549 million and $572 million at December 31, 2010 and March 31, 2011, respectively.

 

(Continued)

 

10



Table of Contents

 

ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(6)                     Asset Retirement Obligations

 

The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2011 (in thousands):

 

Asset retirement obligations — beginning of period

 

$

5,374

 

Obligations incurred

 

119

 

Accretion expense

 

96

 

Asset retirement obligations — end of period

 

$

5,589

 

 

(7)                     Derivative Instruments and Risk Management Activities

 

(a)                      Commodity Derivatives

 

The Company periodically enters into natural gas derivative contracts with counterparties to hedge the price risk associated with a portion of its production. These derivatives are not held for trading purposes. To the extent that changes occur in the market prices of natural gas, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the change in market prices of natural gas recognized upon the ultimate sale of the natural gas produced.

 

For the three months ended March 31, 2010 and 2011, the Company was party to natural gas fixed price swaps. When actual commodity prices exceed the fixed price provided by the swap contracts, the Company pays the excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price, the Company receives the difference from the counterparty. The Company’s natural gas swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently.

 

As of March 31, 2011, derivative positions with JP Morgan, BNP Paribas, Dominion Field Services, Wells Fargo, Credit Agricole, Credit Suisse, Barclays, Union Bank, and KeyBank accounted for approximately 46%, 23%, 11%, 5%, 4%, 4%, 3%, 3%, and 1%, respectively, of the net fair value of our commodity derivative assets position. The Company has no collateral from any counterparties. All but one of our commodity and interest rate derivative positions are with institutions that have a position in our Credit Facility and are secured by the collateral pledged on the Credit Facility and cross default provisions between the Credit Facility and the derivative instruments. At March 31, 2011, there are no past due receivables from or payables to any of our counterparties.

 

As of March 31, 2011, the Company has entered into fixed price natural gas swaps in order to hedge a portion of its natural gas production from April 1, 2011 through December 31, 2015 as summarized in the following table. Hedge agreements referenced to the Centerpoint and Transco Zone 4 indices are for production in the Arkoma Basin. Hedge agreements referenced to the CIG and NYMEX-WTI indices are for production in the Piceance Basin. Hedge agreements referenced to the CGTAP and Dominion indices are for production from the Appalachian Basin.

 

(Continued)

 

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Table of Contents

 

ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

 

 

 

 

 

 

Weighted

 

 

 

 

 

 

 

average

 

 

 

Natural gas

 

Oil

 

index

 

 

 

MMbtu/day

 

Bbls/day

 

price

 

Nine months ending

 

 

 

 

 

 

 

December 31, 2011:

 

 

 

 

 

 

 

CIG

 

45,000

 

 

 

$

5.39

 

Transco zone 4

 

55,000

 

 

 

5.99

 

CGTAP

 

75,546

 

 

 

5.61

 

Dominion

 

4,097

 

 

 

8.16

 

NYMEX-WTI

 

 

 

300

 

88.75

 

 

 

 

 

 

 

 

 

Year ending December 31, 2012:

 

 

 

 

 

 

 

CIG

 

55,000

 

 

 

$

5.51

 

Transco zone 4

 

45,000

 

 

 

6.60

 

CGTAP

 

65,556

 

 

 

6.02

 

Dominion

 

43,318

 

 

 

5.37

 

NYMEX-WTI

 

 

 

300

 

90.20

 

 

 

 

 

 

 

 

 

Year ending December 31, 2013:

 

 

 

 

 

 

 

CIG

 

60,000

 

 

 

$

5.54

 

Transco zone 4

 

40,000

 

 

 

6.51

 

CGTAP

 

42,631

 

 

 

6.36

 

Dominion

 

71,702

 

 

 

5.36

 

NYMEX-WTI

 

 

 

300

 

90.30

 

 

 

 

 

 

 

 

 

Year ending December 31, 2014:

 

 

 

 

 

 

 

CIG

 

50,000

 

 

 

$

5.84

 

Transco zone 4

 

20,000

 

 

 

6.51

 

CGTAP

 

70,000

 

 

 

6.26

 

Dominion

 

60,000

 

 

 

5.47

 

Centerpoint

 

10,000

 

 

 

6.20

 

 

 

 

 

 

 

 

 

Year ending December 31, 2015:

 

 

 

 

 

 

 

CIG

 

50,000

 

 

 

$

5.26

 

Transco zone 4

 

20,000

 

 

 

5.58

 

Dominion

 

140,000

 

 

 

5.76

 

 

(Continued)

 

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ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(b)                      Interest Rate Derivatives

 

The Company has entered into various floating-to-fixed interest rate swap derivative contracts to manage exposures to changes in interest rates from variable rate obligations under the second lien term loan (repaid in 2009) and the Credit Facility. Under the swaps, the Company makes payments to the swap counterparty when the variable LIBOR three-month rate falls below the fixed rate or receives payments from the swap counterparty when the variable LIBOR three-month rate goes above the fixed rate. The Company has one outstanding swap agreement at March 31, 2011 are summarized as follows:

 

 

 

Covering

 

 

 

Notional amount of swap

 

periods

 

Fixed rate

 

$ 225 million

 

May 2007 to July 1, 2011

 

4.11

%

 

When the Company retired the floating rate second lien term loan of $225 million out of the proceeds from the rate 9.375% senior notes in November 2009, it did not terminate the $225 million floating-to-fixed rate swap associated with this debt; therefore, this swap does not have debt associated with it.

 

(Continued)

 

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Table of Contents

 

ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(c)                       Summary

 

The following is a summary of the fair values of our derivative instruments, which are not designated as hedges for accounting purposes and where such values are recorded in the consolidated balance sheets as of December 31, 2010 and March 31, 2011.

 

 

 

2010

 

2011

 

 

 

Balance sheet

 

 

 

Balance sheet

 

 

 

 

 

location

 

Fair value

 

location

 

Fair value

 

 

 

 

 

(In thousands)

 

 

 

(In thousands)

 

Asset derivatives not designated as hedges for accounting purposes:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Current assets

 

$

82,960

 

 

 

$

76,656

 

Commodity contracts

 

Long-term assets

 

147,417

 

 

 

76,455

 

Total asset derivatives

 

 

 

$

230,377

 

 

 

$

153,111

 

 

 

 

 

 

 

 

 

 

 

Liability derivatives not designated as hedges for accounting purposes:

 

 

 

 

 

 

 

 

 

Interest rate contracts

 

Current liabilities

 

$

4,212

 

Current liabilities

 

$

2,165

 

 

(Continued)

 

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Table of Contents

 

ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

The following is a summary of realized and unrealized gains (losses) on derivative instruments and where such values are recorded in the consolidated statements of operations for the three months ended March 31, 2010 and 2011.

 

 

 

 

 

Three months

 

Three months

 

 

 

Statement of

 

ended

 

ended

 

 

 

operations

 

March 31,

 

March 31,

 

 

 

location

 

2010

 

2011

 

Realized gains on commodity contracts

 

Revenue

 

$

12,271

 

29,238

 

Unrealized gains (losses) on commodity contracts

 

Revenue

 

98,812

 

(77,266

)

Total gains on commodity contracts

 

 

 

111,083

 

(48,028

)

Realized losses on interest rate contracts

 

Other expenses

 

(3,127

)

(2,141

)

Unrealized gains on interest rate contracts

 

Other expenses

 

1,525

 

2,046

 

Total losses on interest rate contracts

 

 

 

(1,602

)

(95

)

Net gains (losses) on derivative contracts

 

 

 

$

109,481

 

(48,123

)

 

The following table summarizes the valuation of investments and financial instruments by the fair value hierarchy described in note 1 at March 31, 2011:

 

 

 

Fair value measurements using

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

prices

 

 

 

 

 

 

 

 

 

in active

 

Significant

 

 

 

 

 

 

 

markets for

 

other

 

Significant

 

 

 

 

 

identical

 

observable

 

unobservable

 

 

 

 

 

assets

 

inputs

 

inputs

 

 

 

Description

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Total

 

 

 

 

 

 

 

 

 

 

 

Derivatives asset (liability):

 

 

 

 

 

 

 

 

 

Fixed price commodity swaps

 

$

 

153,111

 

 

153,111

 

Interest rate swaps

 

 

(2,165

)

 

(2,165

)

 

 

$

 

150,946

 

 

150,946

 

 

(Continued)

 

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Table of Contents

 

ANTERO RESOURCES LLC

 

Notes to Consolidated Financial Statements

 

December 31, 2010 and March 31, 2011

 

(8)                     Contingencies

 

The Company is party to various legal proceedings and claims in the ordinary course of its business. The Company believes certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on its consolidated financial position, results of operations, or liquidity.

 

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Item 2.           Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the historical audited financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2010 on file with the Securities and Exchange Commission (Commission File No. 333-164876 .  The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in commodity prices, 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 our ability to access them and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2010 on file with the Securities and Exchange Commission and Part II, Item 1A.”Risk Factors” of this report. We do not undertake any obligation to publicly update any forward-looking statements.

 

Antero Resources Finance Corporation, which was formed to be the issuer of the $525 million principal amount of senior notes due 2017, is an indirect wholly owned subsidiary of Antero Resources LLC. In this section, references to “Antero,” “we,” “the Company,” “us,” “our” and “operating entities” refer to the corporations that conduct Antero Resources LLC’s operations (Antero Resources Corporation, Antero Resources Midstream Corporation (through November 5, 2010), Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation, Antero Resources Appalachian Corporation, and, beginning December 1, 2010, Antero Resources Bluestone LLC), unless otherwise indicated or the context otherwise requires. For more information on our organizational structure, see “Items 1 and 2. Business and Properties—Business—Corporate Sponsorship and Structure” included in our Annual Report on Form 10-K for the year ended December 31, 2010 on file with the Securities and Exchange Commission or note 1 to the consolidated financial statements included elsewhere in this report.

 

Overview

 

Our Company

 

Antero Resources is an independent oil and natural gas company engaged in the exploration, development and production of natural gas and oil properties located onshore in the United States.  We focus on unconventional reservoirs, which can generally be characterized as fractured shales and tight sand formations.  Our properties are primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Arkoma Basin in Oklahoma and the Piceance Basin in Colorado.  Our corporate headquarters are in Denver, Colorado.

 

Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays.  Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to profitably grow our reserves and production, primarily through internally generated projects on our existing acreage.  As of December 31, 2010, our estimated proved reserves were 3,231 Bcfe, consisting of 2,544 Bcf of natural gas, 104 MMBbl of NGLs, and 10 MMBbl of oil.  As of December 31, 2010, 79% of our proved reserves were natural gas, 14% were proved developed and 87% were operated by us.  From December 31, 2006 through December 31, 2010, we grew our estimated proved reserves from 87 Bcfe to 3,231 Bcfe.  In addition, we grew our average daily production from 31 MMcfe/d for the year ended December 31, 2007 to 133 MMcfe/d for the year ended December 31, 2010.  For the year ended December 31, 2010, we generated cash flow from operations of $125.8 million, net income of $230.2 million and EBITDAX of $197.7 million.  For the three months ended March 31, 2011, we generated cash flow from operations of $70.2 million, a net loss of $58.9 million, and EBITDAX of $64.6 million.  See “Non-GAAP Financial Measure” included elsewhere in this report for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss).

 

We have assembled a diversified portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and a repeatable drilling opportunities.  Our drilling opportunities are focused in the Marcellus Shale of the Appalachian Basin, the Woodford Shale of the Arkoma Basin (the Arkoma Woodford), the Fayetteville Shale of the Arkoma Basin, the Mesaverde tight sands, and the Mancos and Niobrara Shales in the Piceance Basin.  From inception, we have drilled and operated 380 wells through

 

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December 31, 2010 with a success rate of approximately 97%.  Our drilling inventory consists of approximately 15,000 potential well locations, all of which are unconventional resource opportunities.  For information on the possible limitations on our ability to drill our potential locations, see “Item 1A.  Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2010 on file with the Securities and Exchange Commission.

 

We believe we have secured sufficient long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in each of our core operating areas to accommodate our existing production.  We own gathering lines and compression in the Appalachian Basin and gathering lines in the Piceance Basin.

 

On November 5, 2010, we sold our Oklahoma midstream assets and received approximately $259 million of net cash proceeds from the sale and realized a gain of approximately $148 million.  We used the proceeds to pay down advances on our senior secured revolving bank credit facility (Credit Facility) and thereby increase availability on our Credit Facility for working capital, drilling activities and property acquisitions.  We entered into long-term contracts with the purchaser of the midstream assets to continue to gather and process the Company’s Oklahoma gas production.  The terms of the Antero Resources LLC limited liability company operating agreement require us to make distributions sufficient to cover the members’ tax liabilities for taxable gains that are allocated to the members.  As a result of the gain on the sale of the midstream assets, we distributed $28.4 million to the members subsequent to December 31, 2010.

 

During the year ended December 31, 2010, we incurred approximately $332 million of capital expenditures for exploration and development of natural gas and oil properties.  Capital expenditures for exploration and development were allocated 48% to our Marcellus shale project in the Appalachian basin 33% to the Arkoma basin, and 19% to the Piceance Basin. Total capital expenditures during the year ended December 31, 2010, including exploration and development, leasehold acquisition, and gathering systems, were $423 million.  Our revised capital expenditure budget for 2011 as approved by our Board of Directors is $559 million, which includes $452 million for drilling and completion, $65 million for leasehold acquisitions, and $42 million for construction of gathering pipelines and facilities. Approximately 73% of the budget is allocated to the Marcellus Shale, 14% is allocated to the Woodford Shale and Fayetteville Shale, and 13% is allocated to the Piceance Basin.  For the three months ended March 31, 2011, our capital expenditures were approximately $121 million.  Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, commodity prices and drilling results.

 

As of March 31, 2011, we have entered into hedging contracts covering a total of approximately 359.2 Bcfe of our natural gas and oil production from April 1, 2011 through December 31, 2015 at a weighted average index price of $5.85 per Mcfe.  For the nine months ending December 31, 2011, we have hedged approximately 49.9 Bcfe of our production at a weighted average index price of $5.82 per Mcfe.

 

In May 2011, we and our lenders entered into an agreement to amend our Credit Facility.  The amendment provides for increasing the maximum Credit Facility from $1.0 billion to $1.5 billion.  The borrowing base was increased from $550 million to $900 million.  Current lender commitments total $750 million and can be increased to the full $900 million borrowing base upon approval of the lending bank group.  The maturity date of the Credit Facility was extended to May 2016.  The borrowing base is redetermined semiannually and the borrowing base depends on the amount of our proved oil and gas reserves and estimated cash flows from these reserves and our hedge positions.  The next redetermination is scheduled to occur in October 2011.

 

We operate in one industry segment, which is the exploration, development and production of natural gas, NGLs, and oil, and all of our operations are conducted in the United States. Our gathering assets are primarily dedicated to supporting the natural gas volumes we produce.

 

Source of Our Revenues

 

Our production revenues are entirely from the continental United States and currently are comprised of approximately 88% natural gas, 8% natural gas liquids, and 4% oil. Natural gas and oil prices are inherently volatile and are influenced by many factors outside of our control. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a significant portion of our natural gas production. We currently use fixed price natural gas and oil swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At each period end we estimate the fair value of these swaps and recognize an unrealized gain or loss. We have not elected hedge accounting and, accordingly, the unrealized gains and losses on open positions are reflected currently in earnings. During the three months ended March 31, 2010 and 2011, we recognized significant unrealized commodity gains or losses on these swaps.  We expect continued volatility in the fair value of these swaps.

 

Principal Components of Our Cost Structure

 

·                  Lease operating and gathering, compression and transportation expenses.  These are daily costs incurred to bring natural gas and oil out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such

 

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costs also include maintenance, repairs and workover expenses related to our natural gas and oil properties.  Cost levels for these expenses can vary based on industry drilling and production activity levels and the resulting demand fluctuations for oilfield services.

 

·                  Production taxes.  Production taxes consist of severance and ad valorem taxes and are paid on produced natural gas and oil based on a percentage of market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities.

 

·                  Exploration expense.  These are geological and geophysical costs, including delay rentals and the costs of unsuccessful exploratory dry holes and unsuccessful leasing efforts.

 

·                  Impairment of unproved and proved properties.  These costs include unproved property impairment and costs associated with lease expirations. We could also record impairment charges for proved properties if the carrying value were to exceed estimated future cash flows. Through March 31, 2011, it has not been necessary to record any impairment for proved properties.

 

·                  Depreciation, depletion and amortization.  This includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and allocate these costs to each unit of production using the units of production method.

 

·                  General and administrative expense.  These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees, and legal compliance.

 

·                  Interest expense.  We finance a portion of our working capital requirements and acquisitions with borrowings under our Credit Facility. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We also have fixed interest at 9.375% on the senior notes having a principal balance of $525 million. We will likely continue to incur significant interest expense as we continue to grow. We have also entered into variable to fixed interest rate swaps to mitigate the effects of interest rate changes. We do not designate these swaps as hedges and therefore do not accord them hedge accounting treatment. Realized and unrealized gains or losses on these interest rate derivative instruments are included as a separate line item in other income (expense).

 

·                  Income tax expense.  Each of the operating entities files separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. We are subject to state and federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income or franchise taxes where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis. Collectively, the operating entities have generated net operating loss carryforwards which expire at various dates from 2024 through 2030. We have not recognized the full value of these net operating losses on our balance sheets because our management team believes it is more likely than not that we will not realize a future benefit equal to the full amount of the loss carryforward over time. The amount of deferred tax assets considered realizable, however, could change in the near term as we generate taxable income or estimates of future taxable income are reduced.

 

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Table of Contents

 

Results of Operations

 

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2011

 

The following table sets forth selected operating data for the three months ended March 31, 2010 compared to the three months ended March 31, 2011:

 

 

 

Three Months
Ended
March 31,

 

Amount of
Increase

 

Percent

 

 

 

2010

 

2011

 

(Decrease)

 

Change

 

 

 

(in thousands, except per unit and production data)

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

51,727

 

$

60,858

 

$

9,131

 

18

%

Natural gas liquids sales

 

2,225

 

5,585

 

3,360

 

151

%

Oil sales

 

2,114

 

2,528

 

414

 

20

%

Realized commodity derivative gains

 

12,271

 

29,238

 

16,967

 

138

%

Unrealized commodity derivative gains (losses)

 

98,812

 

(77,266

)

(176,078

)

 

*

Gathering and processing

 

6,413

 

 

(6,413

)

(100

)%

Total operating revenues

 

173,562

 

20,943

 

(152,619

)

(88

)%

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating expense

 

4,598

 

7,301

 

2,703

 

59

%

Gathering, compression and transportation

 

10,141

 

17,150

 

7,009

 

69

%

Production taxes

 

2,670

 

3,128

 

458

 

17

%

Exploration expense

 

1,352

 

3,129

 

1,777

 

131

%

Impairment of unproved properties

 

2,262

 

2,318

 

56

 

2

%

Depletion depreciation and amortization

 

32,996

 

33,669

 

673

 

2

%

Accretion of asset retirement obligations

 

73

 

96

 

23

 

32

%

Expenses related to business acquisition

 

 

195

 

195

 

 

*

General and administrative

 

4,412

 

6,166

 

1,754

 

40

%

Total operating expenses

 

58,504

 

73,152

 

14,648

 

25

%

Operating income (loss)

 

115,058

 

(52,209

)

(167,267

)

 

*

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest expense

 

(13,292

)

(15,053

)

(1,761

)

(13

)%

Realized interest rate derivative losses

 

(3,127

)

(2,141

)

986

 

(32

)%

Unrealized interest rate derivative gains

 

1,525

 

2,046

 

521

 

34

%

Total other expense

 

(14,894

)

(15,148

)

(254

)

(2

)%

Income (loss) before income taxes

 

100,164

 

(67,357

)

(167,521

)

 

*

Deferred income tax (expense) benefit

 

(11,318

)

8,422

 

19,740

 

 

*

Net income (loss)

 

88,846

 

(58,935

)

(147,781

)

 

*

Non-controlling interest in net income of consolidated subsidiary

 

(1,241

)

 

1,241

 

(100

)%

Net income (loss) attributable to Antero members

 

$

87,605

 

$

(58,935

)

$

(146,540

)

 

*

Production data:

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

10

 

15

 

5

 

50

%

Oil (MBbl)

 

32

 

32

 

 

%

NGLs (MBbl)(1)

 

134

 

126

 

(8

)

(6

)%

Combined (Bcfe)

 

11

 

16

 

5

 

47

%

Daily combined production (MMcfe/d)

 

118

 

173

 

55

 

47

%

Average prices before effects of hedges(2):

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

5.39

 

$

4.16

 

$

(1.23

)

(23

)%

Natural gas liquids (per Bbl)

 

49.89

 

44.38

 

(5.51

)

(11

)%

Oil (per Bbl)

 

$

66.27

 

$

79.60

 

$

13.33

 

20

%

Combined (per Mcfe)

 

$

5.57

 

$

4.43

 

$

(1.14

)

(20

)%

Average realized prices after effects of hedges(2):

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

6.66

 

$

6.17

 

$

(0.49

)

(7

)%

Natural gas liquids (per Bbl)

 

49.89

 

44.38

 

(5.51

)

(11

)%

Oil (per Bbl)

 

$

66.27

 

$

74.94

 

$

8.67

 

13

%

Combined (per Mcfe)

 

$

6.79

 

$

6.31

 

$

(0.48

)

(7

)%

Average Costs (per Mcfe):

 

 

 

 

 

 

 

 

 

Lease operating costs

 

$

0.46

 

$

0.47

 

$

0.01

 

2

%

Gathering, compression and transportation

 

$

1.01

 

$

1.10

 

$

0.09

 

9

%

Production taxes

 

$

0.27

 

$

0.20

 

$

(0.07

)

(26

)%

Depletion, depreciation amortization and accretion

 

$

3.28

 

$

2.16

 

$

(1.12

)

(34

)%

General and administrative

 

$

0.44

 

$

0.40

 

$

(0.04

)

(9

)%

 


(1)                                  Effective January 1, 2011, we began realizing the value of our processed NGLs from the Piceance Basin as a result of a new processing agreement.  Because of their greater current significance, we have begun reporting our NGL revenues from both

 

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the Piceance and Arkoma Basins separately from natural gas sales in the first quarter of 2011.  We have also reclassified NGL revenues realized in the prior year period from natural gas sales.

 

In 2010, NGL quantities include NGLs retained by our midstream business as compensation for processing third-party gas under long-term contracts.  These quantities are not reflected in the per Mcfe data in this table. Our midstream business was sold in November 2010.

 

(2)                                  Average prices shown in the table reflect both of the before-and-after effects of our realized commodity hedging transactions. Our calculation of such after-effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGL production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.  This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

 

*              Not meaningful or applicable

 

Natural gas, NGLs, and oil sales.  Revenues from production of natural gas, natural gas liquids, and oil increased from $56 million for the three months ended March 31, 2010 to $69 million for the three months ended March 31, 2011, an increase of $13 million, or 23%. Our production increased by 47% from 11 Bcfe for the three months ended March 31, 2010 to 16 Bcfe for the three months ended March 31, 2011 and prices decreased by 20%, before the effect of realized hedge gains. The net increase in revenues resulted from increased production volumes, which accounted for a $31 million increase in revenues (calculated as the increase in year-to-year volumes times the prior year average price) net of decreased revenues of $18 million caused by commodity price declines (calculated as the decrease in year-to-year average price times current year production volumes).

 

Commodity hedging activities.  To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our natural gas production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive accounting hedge treatment and all mark-to-market gains or losses, as well as realized gains or losses on the derivative instruments, are recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate from the fixed price we will receive on future production. For the three months ended March 31, 2010 and 2011, our hedges resulted in realized gains of $12 million and $29 million, respectively. For the three months ended March 31, 2010 and 2011, our hedges resulted in unrealized gains (losses) of $99 million and $(77) million, respectively.  Derivative asset or liability positions at the end of any accounting period may reverse to the extent natural gas strip prices increase or decrease from their levels at the end of the accounting period or as gains or losses are realized through settlement.

 

Gathering and processing revenues.  Because we sold our Oklahoma midstream assets in the fourth quarter of 2010, we had no gathering and processing revenues for the three months ended March 31, 2011.  Gathering and processing revenues were $6 million for the three months ended March 31, 2010.

 

Lease operating expenses.  Lease operating expenses increased from $5 million for the three months ended March 31, 2010 to $7 million for the three months ended March 31, 2011, an increase of 59%, primarily because of increased total production, increased workover expenses in the Piceance Basin, and increased operating expenses on non-operated properties.  On a per unit basis, lease operating expenses increased in total from $0.46 per Mcfe for the three months ended March 31, 2010 to $0.47 for the three months ended March 31, 2011.

 

Gathering, compression and transportation.  Gathering, compression and transportation expense increased from $10 million for the three months ended March 31, 2010 to $17 million for the three months ended March 31, 2011 primarily due to an increase in production volumes and increased costs on firm transportation commitments.  On a total per unit basis, these expenses increased from $1.01 per Mcfe for the three months ended March 31, 2010 to $1.10 per Mcfe for the three months ended March 31, 2011.

 

Production taxes.  Total production taxes increased by approximately $0.5 million for the three months ended March 31, 2011 compared to the prior year period, primarily as a result of the increased production.  On a per unit basis, production taxes per Mcfe decreased by 26% from $0.27 to $0.20 per Mcfe.  Production taxes as a percentage of natural gas, NGL, and oil revenues were 4.8% for the three months ended March 31, 2010 compared to 4.5% for the three months ended March 31, 2011 because of lower commodity prices. Production taxes are primarily based on the wellhead values of production and the applicable rates vary across the areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the applicable production tax rates then in effect.

 

Exploration expense.  Exploration expense increased from $1 million for the three months ended March 31, 2010 to $3 million for the three months ended March 31, 2011 primarily because of an increase in dry hole costs.

 

Impairment of unproved properties.  Impairment of unproved properties was approximately $2 million for both of the three months ended March 31, 2010 and 2011.  We charge impairment expense for expired or soon to expire leases when we determine they are impaired through lack of drilling activities or based on other factors, such as remaining lease terms, reservoir performance, commodity price outlooks or future plans to develop the acreage.

 

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Depreciation, depletion and amortization (DD&A).  DD&A increased from $33 million for three months ended March 31, 2010 to $34 million for the three months ended March 31, 2011.  DD&A per Mcfe decreased by 34% from $3.28 per Mcfe during the three months ended March 31, 2010 to $2.16 per Mcfe during the three months ended March 31, 2011, primarily as a result of increased reserves in 2010.

 

We evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. No impairment expenses were recorded for the three months ended March 31, 2010 or 2011 for proved properties.

 

General and administrative.  General and administrative expense increased from $4 million for the three months ended March 31, 2010 to $6 million for the three months ended March 31, 2011 primarily as a result of increased staffing levels related to growth in levels of exploration and production as well as an increase in other expenses related to the growth of the Company.  On a per unit basis, general and administrative expense decreased by 9%, from $0.44 per Mcfe during the three months ended March 31, 2010 to $0.40 per Mcfe during the three months ended March 31, 2011 due to 47% production growth.

 

Interest expense and realized and unrealized gains and losses on interest rate derivatives.  Interest expense increased from $13 million for the three months ended March 31, 2010 to $15 million during the three months ended March 31, 2011 due to increased borrowings on the Credit Facility.  Additionally, the full amount of the 9.375% senior notes of $525 million was not outstanding during the entire three months ended March 31, 2010.  Interest expense includes approximately $1 million of non-cash amortization of deferred financing costs for the three months ended March 31, 2010 and 2011, respectively.

 

We have entered into various variable-to-fixed interest rate swap agreements that hedge our exposure to interest rate variations on our Credit Facility and the previously outstanding second lien term loan facility. At March 31, 2011, one of these swaps remains outstanding with a notional amount of $225 million and a fixed pay rate of 4.11%.  This swap expires in July 2011.  During the three months ended March 31, 2011, we realized a loss on interest rate swap agreements of $2 million; whereas, during the three months ended March 31, 2010, we had a realized loss on interest rate swap agreements of $3 million. At March 31, 2011, the estimated fair value of our interest rate swap agreement was a liability of $2 million, which is included in current liabilities. As of March 31, 2011, we were in a liability position on the interest rate swap because of the large decline in interest rates since entering into the agreement.

 

Income tax expense.  Income tax expense reflects the fact that each of the operating entities files separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. None of the operating entities has taxable income in either the current or prior years, which is primarily attributable to the differing book and tax treatment of unrealized derivative gains and intangible drilling costs. Accordingly, valuation allowances have generally been established against net operating loss (NOLs) carryforwards to the extent that such NOLs exceed net deferred tax liabilities, resulting in no income tax expense or benefit for those subsidiaries having deferred tax assets in excess of deferred tax liabilities. We have not recognized the full value of these NOLs on our balance sheet because our management team believes it is more likely than not that we will not realize a future benefit for the full amount of the loss carryforwards over time.

 

Certain subsidiaries had net deferred tax liabilities at March 31, 2011, resulting from unrealized gains on commodity derivatives and basis differences in assets.  The credit for deferred income tax expense of $8 million during the three months ended March 31, 2011 resulted from the decline in the unrealized gains on commodity derivatives during the quarter.

 

At December 31, 2010, the operating entities had a combined total of approximately $509 million of NOLs, which expire starting in 2024 and through 2030.  Congress recently proposed legislation that would eliminate or limit future deductions for intangible drilling costs and could significantly affect our future taxable position. The impact of any change will be recorded in the period that legislation is enacted.

 

Cash Flow Provided by Operating Activities

 

Net cash provided by operating activities was $52 million and $70 million for the three months ended March 31, 2010 and 2011, respectively. The increase in cash flow from operations from the three months ended March 31, 2010 to the three months ended March 31, 2011 was primarily the result of increased production volumes and revenues, net of the increase in cash operating costs, interest expense, and changes in working capital levels.

 

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil production. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide

 

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Table of Contents

 

economic activity, weather, infrastructure, capacity to reach markets and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see Item 3. “—Quantitative and Qualitative Disclosure About Market Risk” below.

 

Cash Flow Used in Investing Activities

 

During the three months ended March 31, 2010 and 2011, we had cash flows used in investing activities of $66 million and $121 million, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increase in cash used in investing activities for the three months ended March 31, 2011 compared to the three months ended March 31, 2010 was a result of higher levels of drilling activity. We expect that our cash used in investing activities will increase for the remainder of 2011 compared to the rate of spending during the first quarter based on our current capital budget and planned drilling activities.

 

Our revised capital budget for 2011 is $559 million. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

 

Cash Flow Provided by Financing Activities

 

Net cash provided by financing activities during the three months ended March 31, 2011 of $42 million was primarily the result of borrowings on the Credit Facility of $70 million, net of $28 million of distributions to members.  The distribution to members was required by the limited liability operating agreement to cover income taxes owed by the members as a result of the gain realized on the sale of the Oklahoma midstream assets in the fourth quarter of 2010.  Net cash provided by financing activities of $10 million during the three months ended March 31, 2010, was primarily the result of the issuance of $156 million of senior notes, net of $4 million of related issuance costs and $142 million of repayments on the Credit Facility.

 

Credit Facility.  In May 2011, we and our lenders entered into an agreement to amend our Credit Facility.  The amendment provides for increasing the Credit Facility $1.0 billion to $1.5 billion.  The borrowing base was increased from $550 million to $900 million.  Current lender commitments total $750 million and can be increased to the full $900 million borrowing base upon approval of the lending bank group.  The maturity date of the Credit Facility was extended to May 2016.  The borrowing base is redetermined semiannually and the borrowing base depends on the amount of our proved oil and gas reserves and estimated cash flows from these reserves and our hedge positions.  The next redetermination is scheduled to occur in October 2011.

 

As of March 31, 2011, we had borrowings outstanding under our Credit Facility of $170 million and letters of credit outstanding of approximately $19 million.  As of December 31, 2010, we had $118 million of outstanding borrowings and letters of credit.  The credit facility is secured by mortgages on substantially all of our properties and guarantees from the operating entities. Interest is payable at a variable rate based on LIBOR or the prime rate based on our election at the time of borrowing.

 

The Credit Facility contains certain covenants, including restrictions on indebtedness, asset sales, investments, liens, dividends, and certain other transactions without the prior consent of the lenders.  We are required to maintain the following two financial ratios:

 

·                  a current ratio, which is the ratio of our consolidated current assets to our consolidated current liabilities, of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

 

·                  a leverage ratio, which is the ratio of our consolidated funded indebtedness (minus amounts of unsatisfied capital calls) as of the end of such fiscal quarter to our consolidated EBITDAX for the trailing four fiscal quarter period, of not greater than 4.50 to 1.0 until the fiscal quarter ending March 31, 2012, when the maximum leverage ratio will decrease to 4.0 to 1.0.

 

We were in compliance with such covenants and ratios as of December 31, 2010 and as of March 31, 2011.

 

As of December 31, 2010 and March 31, 2011, borrowings and letters of credit outstanding under our Credit Facility totaled $118 million and $189 million, respectively, and had a weighted average interest rate (excluding the impact of our interest rate swaps) of 2.56% and 2.75%, respectively.

 

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Senior Notes.  We have $525 million of 9.375% senior notes outstanding which are due December 1, 2017.  The notes are unsecured and subordinate to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.  The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries.  Interest on the notes is payable on June 1 and December 1 each year.  Antero Finance may redeem all or part of the notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015.  In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 109.375%.  At any time prior to December 1, 2013, Antero Finance may also redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium.  If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders.

 

The senior notes indenture contains restrictive covenants and a minimum interest coverage ratio requirement of 2.25:1.  We were in compliance with such covenants and the coverage ratio requirement as of December 31, 2010 and March 31, 2011.

 

Treasury Management Facility.  On September 14, 2010, the Company executed a stand-alone revolving note with a lender under the Credit Facility which provides for up to $7.5 million of cash management obligations in order to facilitate the Company’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the Credit Facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on September 12, 2011. At March 31, 2011 there were no outstanding borrowings under this facility.

 

Note Payable.  The Company assumed a $25 million unsecured note payable in the business acquisition consummated on December 1, 2010.  The note bears interest at 9% and is due December 1, 2013.

 

Interest Rate Hedges.  We have entered into variable to fixed interest rate swap agreements which hedge our exposure to interest rate variations on our Credit Facility and previously outstanding second lien term loan facility. At March 31, 2011, we had one interest rate swap outstanding for a notional amount of $225 million with a fixed pay rate of 4.11% with a term expiring in July 2011. During the three months ended March 31, 2010 and 2011, we had realized losses on interest rate swap agreements of $3 and $2 million, respectively, and unrealized gains of approximately $2 million in each year.    We did not settle the interest rate swap related to the $225.0 million second lien term facility when it was repaid in November 2009; therefore, the interest rate swap outstanding at December 31, 2010 and March 31, 2011 does not have debt associated with it.

 

Non-GAAP Financial Measure

 

“EBITDAX” is a non-GAAP financial measure that we define as net income before interest, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized hedge gains or losses, franchise taxes, stock compensation and interest income. “EBITDAX,” as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. EBITDAX does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, and other commitments and obligations. However, our management team believes EBITDAX is useful to an investor in evaluating our operating performance because this measure:

 

·                  is widely used by investors in the natural gas and oil 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 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 our operations from period to period by removing the effect of our capital structure from our operating structure; and

 

·                  is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under our Credit Facility. EBITDAX is used as a measure of our operating performance pursuant to a covenant under the indenture governing our $525 million principal amount of 9.375% senior notes due 2017.

 

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There are significant limitations to using EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating EBITDAX reported by different companies. The following table represents a reconciliation of our net income to EBITDAX for the year ended December 31, 2010 and the three months ended March 31, 2010 and 2011:

 

 

 

Year Ended
December 31,

 

Three Months Ended
March 31,

 

 

 

2010

 

2010

 

2011

 

 

 

 

 

(in thousands)

 

Net income (loss) attributable to Antero members

 

$

228,628

 

$

 87,605

 

$

 (58,935

)

Unrealized (gains) losses on derivative contracts

 

(170,571

)

(98,812

)

77,266

 

Gain on sale of Oklahoma midstream assets

 

(147,559

)

 

 

 

 

Interest expense and other

 

59,140

 

14,894

 

15,148

 

Provision (benefit) for income taxes

 

30,009

 

11,318

 

(8,422

)

Depreciation, depletion, amortization and accretion

 

134,272

 

33,069

 

33,765

 

Impairment of unproved properties

 

35,859

 

2,262

 

2,318

 

Exploration expense

 

24,794

 

1,352

 

3,129

 

Other

 

3,106

 

37

 

366

 

EBITDAX

 

$

197,678

 

$

 51,725

 

$

 64,635

 

 

Critical Accounting Policies and Estimates

 

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Our more significant accounting policies and estimates include the successful efforts method of accounting for oil and gas production activities, estimates of natural gas and oil reserve quantities and standardized measures of future cash flows, and impairment of unproved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments in our Annual Report on Form 10-K for the year end December 31, 2010 on file with the Securities and Exchange Commission. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. Also, see Note 2 of the notes to our audited consolidated financial statements, included in the Form 10-K for a discussion of additional accounting policies and estimates made by management.

 

New Accounting Pronouncements

 

There were no new accounting pronouncements issued during the three months ended March 31, 2011 that had a significant effect on the Company’s financial reporting.

 

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Table of Contents

 

Off-Balance Sheet Arrangements

 

Currently, we do not have any off-balance sheet arrangements other than operating leases.

 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

 

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

 

Commodity Price Risk and Hedging Activities

 

Our primary market risk exposure is in the price we received for our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

 

To mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our natural gas and oil production when management believes that favorable future prices can be secured. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the Centerpoint East, CIG Hub, Transco Zone 4 and Columbia Gas Transmission (CGTAP), and Dominion South Indices.

 

Our financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas price fluctuations. The counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price. These contracts may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference.

 

At December 31, 2010 and March 31, 2011, we had in place natural gas and oil swaps covering portions of production from 2011 through 2015. Our hedge position as of March 31, 2011 is summarized in note 7 to our consolidated financial statements included elsewhere in this report.  Our Credit Facility allows us to hedge up to 85% of our estimated production from proved reserves for up to 12 months in the future, 80% for 13 to 24 months in the future, 75% for 25 to 36 months in the future, 70% for 37 to 48 months in the future and 65% for 49 to 60 months in the future. Based on our production for the three months ended March 31, 2011 and our fixed price swap contracts in place during that period, our income before taxes for the three months ended March 31, 2011 would have decreased by approximately $0.2 million for each $0.10 decrease per MMBtu in natural gas prices.

 

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value in accordance with United States GAAP and are included in the consolidated balance sheets as assets or liabilities. Fair values are adjusted for non-performance risk. Because we do not designate these hedges as accounting hedges, we do not receive accounting hedge treatment and all mark-to-market gains or losses as well as realized gains or losses on the derivative instruments are recognized in our results of operations. We present realized and unrealized gains or losses on commodity derivatives in our operating revenues as “Realized and unrealized gains (losses) on commodity derivative instruments.”

 

Mark-to-market adjustments of derivative instruments produce earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments. Our cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. At December 31, 2010, the estimated fair value of our commodity derivative instruments was a net asset of $230 million comprised of current and noncurrent assets. At March 31, 2011, the estimated fair value of our commodity derivative instruments was a net asset of $153 million comprised of current and noncurrent assets.

 

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By removing price volatility from a portion of our expected natural gas production through December 2015, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

 

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have economic hedges in place with nine different counterparties, all but one of which are lenders in our Credit Facility. As of March 31, 2011, derivative positions with JP Morgan, BNP Paribas, Dominion Field Services, Wells Fargo, Credit Agricole, Credit Suisse,  Barclays, Union Bank, and KeyBank accounted for approximately 46%, 23%, 11%, 5%, 4%,  4%, 3%, 3%, and 1%,  respectively, of the net fair value of our commodity derivative assets position. We believe all of these institutions currently are acceptable credit risks. Other than as provided by the Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our contracts, nor are they required to provide credit support to us. As of March 31, 2011, we have no past due receivables from or payables to any of our counterparties.

 

Interest Rate Risks and Hedges

 

During the three months ended March 31, 2011, we had indebtedness outstanding under our Credit Facility, which has a floating interest rate. The average annual interest rate incurred on this indebtedness for the three months ended March 31, 2011, was approximately 2.7%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2011, would have resulted in an estimated $300,000 increase in interest expense for the three months ended March 31, 2011 before giving effect to interest rate swaps. During the three months ended March 31, 2011, a significant part of our indebtedness consisted of fixed rate 9.375% senior notes due 2017 having an outstanding principal amount of $525 million.

 

Item 4.  Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures

 

Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2011.

 

Changes in Internal Control Over Financial Reporting

 

There has been no change in our internal control over financial reporting during the three months ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

PART II—OTHER INFORMATION

 

Item 1.  Legal Proceedings.

 

We are party to various legal proceedings and claims in the ordinary course of its business. We believe certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on our consolidated financial position, results of operations, or liquidity. For a discussion of certain legal matters in which we are involved, see “Item 3. Legal Proceedings” in our Annual Report on Form 10-K for the year ended December 31, 2010 on file with the Securities and Exchange Commission (File No. 333-164876).  Other than as described below there have been no material changes to the legal matters described in the Form 10-K.

 

We have received orders for compliance from federal regulatory agencies relating to certain of our activities in West Virginia. The orders allege that certain of our operations are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States. We are currently investigating these matters and any outcome cannot be predicted with certainty. No fine or penalty relating to these matters has been proposed at this time, and our management team does not expect these matters to have a material adverse effect on our financial statements.

 

Item 1A.  Risk Factors.

 

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010 on file with the Securities and Exchange Commission (File No. 333-164876). The risks described in the Annual Report on Form 10-K could

 

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materially and adversely affect our business, financial condition, cash flows, and results of operations.  There have been no material changes to the risks described in the Annual Report on Form 10-K. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

 

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

 

There were no sales of unregistered equity securities during the period covered by this report.

 

Item 3.  Defaults upon Senior Securities.

 

Not applicable.

 

Item 4.  (Removed and Reserved.)

 

Item 5.  Other Information.

 

Not applicable.

 

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Item 6.  Exhibits.

 

Exhibit
Number

 

Description of Exhibits

3.1

 

Certificate of Incorporation of Antero Resources Finance Corporation (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).

3.2

 

Bylaws of Antero Resources Finance Corporation (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).

3.3

 

Certificate of Formation of Antero Resources LLC (incorporated by reference to Exhibit 3.3 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).

3.4

 

Amended and Restated Limited Liability Company Agreement of Antero Resources LLC dated as of December 1, 2010 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on December 3, 2010).

4.1

 

Indenture dated as of November 17, 2009 among Antero Resources Finance Corporation, the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).

4.2

 

Registration Rights Agreement dated as of November 17, 2009 among Antero Resources Finance Corporation, the several guarantors named therein, and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4 No. (Commission File No. 333-164876) filed on February 12, 2010).

4.3

 

Registration Rights Agreement dated as of January 19, 2010 among Antero Resources Finance Corporation, the several guarantors named therein, and the initial purchasers named therein (incorporated by reference to Exhibit 4.3 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).

4.4

 

Registration Rights Agreement dated as of November 3, 2009 by and among Antero Resources LLC and the other parties named therein (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4 No. (File No. 333-164876) filed on February 12, 2010).

10.1*

 

First Amendment to the Fourth Amended And Restated Credit Agreement, dated as of May 12, 2011, among Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation and Antero Resources Appalachian Corporation, as Borrowers, certain subsidiaries of Borrowers, as Guarantors, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent.

31.1*

 

Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

31.2*

 

Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

32.1*

 

Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

32.2*

 

Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

 


The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32.1 and 32.2) with this Form 10-Q.

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

ANTERO RESOURCES FINANCE CORPORATION

 

 

 

 

 

 

Date: May 16, 2011

By:

/s/ GLEN C. WARREN, JR.

 

 

Glen C. Warren, Jr.

 

 

President and Chief Financial Officer

 

 

(Duly Authorized Officer and Principal Financial Officer)

 

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