Antero Resources Reports 2010 Results, Operating Update and 2011 Outlook

Highlights:

- Net production averaged 133 MMcfed in 2010, up 27% from 2009

- Consolidated EBITDAX of $198 million in 2010

- Net production is currently 190 MMcfed including NGLs

- 7 Antero-operated drilling rigs currently running in core areas

- Proved reserves increased 183% to 3.2 Tcfe at year-end 2010, 21% are liquids

- All-in 2010 F&D cost of $0.28 per Mcfe and 3-year all-in F&D cost of $0.59 per Mcfe

- Increased hedge position to 376 Bcfe at $5.99 NYMEX-equivalent average through 2015

Mar 30, 2011, 22:03 ET from Antero Resources

DENVER, March 30, 2011 /PRNewswire/ -- Antero Resources today announced its 2010 results.  Antero continued to execute its strategy of low cost production and reserve growth in its core areas while hedging its future revenues to protect its capital program and balance sheet.  

Full Year 2010

Year-over-year, average natural gas prices before hedging rose 22% to $4.32 per Mcf.  However, due to lower hedged prices in 2010 relative to 2009, average realized gas prices including natural gas liquids (NGLs) and hedges declined by 13% to $5.93 per Mcf.  Average realized gas-equivalent prices including oil, NGLs and hedges also declined 13% to $6.02 per Mcfe.  In 2010, Antero realized natural gas hedging gains of $74 million, or $1.59 per Mcf.  The decrease in realized prices after hedging was more than offset by a 27% increase in production in 2010, resulting in net revenue growth of 12% to $301 million (excluding unrealized commodity derivative gains and losses and the gain on sale of Arkoma midstream assets).  Reported GAAP earnings including unrealized commodity derivative gains of $171 million, the gain on the sale of Arkoma midstream assets of $148 million and property impairments of $36 million, resulted in net income of $230 million in 2010.  Cash flow from operations before changes in working capital decreased by 15% to $128 million in 2010, primarily due to lower realized prices including hedges and higher interest expense driven by the issuance of senior notes in late 2009 and early 2010.  

EBITDAX for 2010 was $198 million, a 2% decrease from 2009 despite solid net revenue growth due to lower realized prices including hedges and higher expenses for workovers in the Piceance and Arkoma.  See "Non-GAAP Financial Measures" for reconciliations of cash flow from operations before changes in working capital to net cash provided by operating activities and EBITDAX to net income.  Antero's capital spending in 2010 totaled $423 million, comprised of $332 million in drilling costs (includes $32 million of cost incurred in 2009 but paid in 2010), $41 million for leasehold, $47 million in gathering costs and $3 million for other capital costs.

Net Production for 2010 totaled 49 Bcfe, comprised of 46 Bcf (94%) of natural gas and 0.5 million barrels (6%) of natural gas liquids (NGLs) and oil, representing a 27% increase over 2009.  Net daily production averaged 133 MMcfed for the year as compared to 105 MMcfed for 2009, while realized prices after hedging declined 13% to $6.02 per Mcfe.  Per unit cash costs (lease operating, gathering, compression and transportation and production tax) for 2010 were $1.72 per Mcfe, a 21% increase over 2009 primarily driven by an $8 million or $0.16 per Mcfe increase in workover expenses.  Per unit depreciation, depletion and amortization expense decreased 26% from the prior year to $2.88 per Mcfe.  General and administrative expense for the year was $0.47 per Mcfe.

Fourth Quarter 2010

Fourth quarter 2010 net revenue (excluding unrealized derivative gains and losses and the gain on the sale of the Arkoma midstream assets) increased by 25% over 2009 to $84 million, primarily driven by a 42% increase in net production.  Reported fourth quarter GAAP earnings including an unrealized commodity derivative loss of $47 million, the gain on sale of midstream assets of $148 million and property impairments of $4 million, resulted in net income of $90 million.  Cash flow from operations before changes in working capital decreased by 16% to $32 million, primarily due to higher cash costs including one-time acquisition expenses and higher interest expense.  EBITDAX for the fourth quarter was $52 million, a 6% increase over 2009.  Net production increased by 42% to 147 MMcfed while realized gas-equivalent prices after hedging declined 9% to $6.12 per Mcfe.  Per unit depreciation, depletion and amortization expense decreased 28% from the prior year to $2.47 per Mcfe.

Reserves

Proved reserves at December 31, 2010 totaled 3.2 Tcfe comprised of 2.5 Tcf of natural gas, 104 million barrels of NGLs and 10 million barrels of crude oil.  Reserves increased 2.1 Tcfe or 183% compared to the prior year.  All-in finding and development costs averaged $0.28 per Mcfe in 2010, while drill bit only finding costs averaged $0.16 per Mcfe.  Antero's three-year weighted average all-in finding and development cost from all sources through 2010 was $0.59 per Mcfe.  Antero has elected to report NGLs separately from natural gas, beginning with its 2010 year-end reserve report.  Due to the execution of a gas processing agreement for its Piceance gas production in December 2010, Antero believes that separate disclosure of NGLs will provide more transparency to its production and reserve reporting.  At year-end 2010, 79% of Antero's proved reserves by volume were natural gas, 19% were NGLs and 2% were crude oil compared to 99% natural gas and 1% oil as of year-end 2009. The percentage of proved undeveloped reserves increased to 86% as compared to 76% at year-end 2009.  Independent petroleum consultants engineered over 99% of the Company's proved reserves by volume.  See "Non-GAAP Financial Measures" for explanation of finding and development cost per unit.


Summary of Changes in Proved Reserves

(in Bcfe)






Balance at December 31, 2009



1,141







     Extensions, discoveries, book NGLs and additions

1,712


     Purchases



172


     Price and performance revisions



253


     Sales




     Production (excluding 3rd party NGLs)



(47)






Balance at December 31, 2010 



3,231



The current SEC rules require that reserve calculations be based on the average first of month prices throughout the previous calendar year.  Accordingly, NYMEX prices for 2010 averaged $4.38/MMBtu, while the benchmark producing basin average natural gas prices were $4.18 per MMBtu in the Arkoma Basin, $3.93 per MMBtu in the Piceance Basin and $4.51 per MMBtu in Appalachian Basin.

Commodity Hedges

Antero has hedged 376 Bcfe of future production using fixed price swaps covering the period from January 2011 through December 2015 at an average NYMEX-equivalent price of $5.99 per MMBtu.  Antero has hedged 80% to 90% of 2011 estimated production at a NYMEX-equivalent price of $6.01 per MMBtu. Virtually all of Antero's financial hedges are tied to the local basin. For presentation purposes, these basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market. Antero has eight different counterparties to its hedge contracts, all but one of which are lenders in Antero's bank credit facility. All of Antero's commodity hedges are simple fixed price swaps and over 99% are natural gas hedges.  The following table summarizes Antero's current commodity hedge position.




Natural gas equivalent


NYMEX-

Equivalent

Calendar Year


MMBtu/day


index price

2011


179,430


$6.01

2012


213,385


$6.05

2013


217,444


$6.02

2014


210,000


$6.09

2015


210,000


$5.76




2011 Capital Budget and Outlook

Antero's revised capital budget for 2011 is $559 million and includes $452 million for drilling and completion, $65 million for leasehold acquisitions and $42 million for the construction of gathering pipelines and facilities.  The budget was revised in March to fund leasehold opportunities in Antero's core areas.  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.  During 2011, Antero plans to operate five drilling rigs in the Marcellus Shale, one drilling rig in the Woodford Shale and one drilling rig in the Piceance Basin.  The capital budget is expected to be funded internally from operating cash flow and through the use of the undrawn capacity under Antero's bank credit facility.  Antero also anticipates closing on approximately $10 million in non-core upstream asset divestitures in the second quarter of 2011, the proceeds of which will also be used to fund the capital budget.  At December 31, 2010, Antero had $404 million of available borrowing capacity under its bank credit facility and $9 million of cash on hand, resulting in total liquidity of $413 million.  These figures are net of a $29 million tax distribution to Antero unit holders made in February 2011 following the sale of the Arkoma midstream assets in November 2010.

Antero periodically provides guidance on certain factors that affect future financial performance.  As of March 31, 2011 we are using the following key assumptions in our projections for 2011:


2011 Outlook


2011 NYMEX Gas Price ($/MMBtu)

$4.50

2011 WTI Oil Price ($/Bbl)

$95.00

2011 Net Production (MMcfed)

200 – 215 MMcfe/d

EBITDAX ($MMs)

$290 – $320 million

Cash Production Costs ($/Mcfe)

$1.55 – $1.70/Mcfe

G&A ($/Mcfe)

$0.40/Mcfe




Antero Operations  

Antero's current gross operated production is 222 MMcfd and 190 MMcfed net (including non-operated production), comprised of 180 MMcfd of gas and 1,700 Bbl/d of NGLs net.

Marcellus Shale – Antero is operating five drilling rigs in the Marcellus Shale play, all of which are drilling in northern West Virginia.  The Company has 128 MMcfd of gross operated production primarily from 34 horizontal wells online resulting in 90 MMcfd of net production.  We estimate that an additional 20 MMcfd of gross operated deliverability from two completed wells is waiting on pipeline and facilities completion.  Antero expects to turn these two wells to sales by June when the Jarvisville Lateral is completed as a southerly extension to the Bobcat Lateral (formerly known as the Clarksburg Lateral) and 46 MMcfd of compression capacity is commissioned at a new third party owned compressor station.  The Tichenal Lateral, a southerly extension to the Jarvisville Lateral, is expected to be completed in July which will add another 46 MMcfd of compression capacity to the system.  Antero has nine additional horizontal Marcellus wells either completing or waiting on completion.  

Antero has 169,000 net acres in the Marcellus Shale play of which only 8% was classified as proved at year-end 2010.

Woodford Shale – Antero is operating one drilling rig in the Arkoma Basin Woodford Shale play.  Antero has 60 MMcfd of gross operated production from 124 wells online and 64 MMcfed of net production including non-operated production. The Company's net non-operated production in the Arkoma is estimated to be 30 MMcfed.  We have five non-operated wells drilling with a combined 75% working interest on our Arkoma acreage.  Antero has one horizontal well waiting on completion.

Antero has an existing gas processing agreement in the Woodford Shale under which a portion of the Company's operated and non-operated gas production is processed. Antero estimates that 9% of its year end 2010 Woodford Shale proved reserves are liquids, primarily comprised of NGLs.  Antero has 71,000 net acres in the Arkoma Woodford Shale play.

Piceance Basin – Antero has one operated drilling rig running in the Piceance Basin.  Our gross operated production in the Piceance is currently 35 MMcfd (28 MMcfed net including 1 MMcfed of non-operated production) from 168 wells online.  Antero has 13 vertical Mesaverde wells waiting on completion in its Rifle rich gas area.

Antero recently entered into a long-term gas processing agreement with a third party midstream company in the Piceance Basin allowing it to realize a processing margin on its Piceance gas production effective January 1, 2011. Antero believes that virtually all of its Piceance Mesaverde gas production is liquids-rich gas that can be processed under current market conditions.  Antero estimates that over 35% of its year end 2010 Piceance proved reserves are liquids, primarily comprised of NGLs.  Antero has 68,000 net acres in the Piceance.

Fayetteville Shale – Antero has three non-operated Fayetteville Shale wells drilling with a combined 1% working interest.  The Company has 8 MMcfd of net production and 5,600 net acres in the Fayetteville Shale play.

Complete financial statements are included in Antero Resources Finance Corporations Annual Report on Form 10-K for the year ended December 31, 2010, which has been filed with the Securities and Exchange Commission.

Non-GAAP Financial Measures

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



Twelve months ended

December 31,


  2010


 2009





Net cash provided by operating activities

$125,791


$149,307

  Net change in working capital

2,698


2,648

Cash flow from operations before changes in working capital

$128,489


$151,955




EBITDAX is a non-GAAP financial measure that we define as net income before interest expense and other income or expense, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized hedge gains or losses, gain or loss on sale, franchise taxes, noncontrolling interest and stock compensation.  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, and 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 senior secured revolving credit facility.  EBITDAX is also used as a measure of operating performance pursuant to a covenant under the indenture governing our 9.375% senior notes.

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 twelve months ended December 31, 2010 and 2009:



Twelve months ended

December 31,


2010


2009

Net income (loss)

$228,628


$(106,169)

Unrealized loss (gain) on commodity derivative contracts

(170,571)


61,186

Gain on sale of Oklahoma midstream assets

(147,559)



Interest expense and other

59,140


41,038

Provision (benefit) for income taxes

30,009


(2,605)

Depreciation, depletion, amortization and accretion

134,272


140,078

Impairment of unproved properties

35,859


54,204

Exploration expense

24,794


10,228

Stock compensation expense

-


2,822

Franchise taxes included in general and administrative expenses

562


851

Expenses related to acquisition of business

2,544



Noncontrolling interest in Centrahoma processing

-


(363)

EBITDAX

$197,678


$201,270




The cash prices realized for oil, NGLs and natural gas production including the amounts realized on cash settled derivatives is a critical component in the Company's performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various hedging and derivative transactions, such information is now reported in various lines of the income statement.

Antero has disclosed several per unit capital cost metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost including all-in finding and development cost per unit and drill bit only finding cost per unit.  It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core areas at lower costs than our competition. 

Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on costs incurred excluding asset retirement obligations and certain non-cash items and divided by proved reserve additions (extensions, discoveries and additions shown in the summary of changes in proved reserves table) adjusted for the changes in proved reserves for performance revisions and/or price revisions as stated in each instance in the release. This calculation does not include the future development costs required for the development of proved undeveloped reserves.

The finding and development cost per unit is a statistical indicator that has limitations, including its  predictive and comparative value.  In addition, since the finding and development cost per unit does not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. This reserve metric may not be comparable to similarly titled measurements used by other companies.

Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional natural gas properties primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Arkoma Basin in Oklahoma and the Piceance Basin in Colorado.

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


ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2009 and 2010

(In thousands)





2009


2010


Assets






Current assets:






Cash and cash equivalents                                             


$

10,669


8,988


Accounts receivable – trade, net of allowance for doubtful accounts of $424 and $272 in 2009 and 2010, respectively


35,897


30,971


Accrued revenue                                                     


17,459


24,868


Prepaid expenses                                                    


7,419


7,087


Derivative instruments                                                 


22,105


82,960


Inventories                                                          


1,295


2,031


Total current assets                                              


94,844


156,905


Property and equipment:






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






Unproved properties                                                


596,694


737,358


Producing properties                                               


1,340,827


1,762,206


Gathering systems and facilities                                         


185,688


85,404


Other property and equipment                                           


3,302


5,975




2,126,511


2,590,943


Less accumulated depletion, depreciation, and amortization                   


(322,992)


(431,181)


Property and equipment, net                                       


1,803,519


2,159,762


Derivative instruments                                                   


18,989


147,417


Other assets, net                                                       


19,214


22,203


Total assets                                                     


$

1,936,566


2,486,287



(Continued)



ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2009 and 2010

(In thousands)




2009


2010


Liabilities and Equity






Current liabilities:






Accounts payable                                                    


$

48,594


82,436


Accrued expenses                                                   


24,572


21,746


Revenue distributions payable                                           


29,304


29,917


Advances from joint interest owners                                     


1,400


1,478


Derivative instruments                                                 


8,623


4,212


Deferred income tax liability                                             



12,694


Total current liabilities                                               


112,493


152,483


Long-term liabilities:






Bank credit facility                                                    


142,080


100,000


Senior notes                                                         


372,397


527,632


Long-term note                                                       



25,000


Derivative instruments                                                 


2,464



Asset retirement obligations                                             


3,487


5,374


Deferred income tax liability                                             


424


77,489


Other long-term liabilities                                               


4,114


3,322


Total liabilities                                                     


637,459


891,300


Equity:






Members' equity                                                     


1,392,833


1,489,806


Accumulated earnings (deficit)                                          


(123,447)


105,181


Total Antero equity                                                 


1,269,386


1,594,987


Noncontrolling interest in consolidated subsidiary                           


29,721



Total equity                                                       


1,299,107


1,594,987


Total liabilities and equity                                             


$

1,936,566


2,486,287






ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Statements of Operations

Years ended December 31, 2008, 2009, and 2010

(In thousands)




2008


2009


2010


Revenue:








Natural gas sales                                       


$

220,219


123,915


197,991


Oil sales                                             


9,496


5,706


8,471


Realized and unrealized gain on commodity derivative instruments (including unrealized gains (losses) of $90,301, $(61,186) and $170,571 in 2008, 2009, and 2010, respectively)


116,354


55,364


244,284


Gas gathering and processing revenue                     


20,421


23,005


20,554


Gain on sale of Oklahoma midstream assets                 




147,559


Total revenue                                     


366,490


207,990


618,859


Operating expenses:








Lease operating expenses                               


13,350


17,606


25,511


Gathering, compression, and transportation                 


29,033


28,190


45,809


Production taxes                                       


10,281


4,940


8,777


Exploration expenses                                   


22,998


10,228


24,794


Impairment of unproved properties                         


10,112


54,204


35,859


Depletion, depreciation, and amortization                    


124,821


139,813


133,955


Accretion of asset retirement obligations                    


176


265


317


Expenses related to business acquisition                   




2,544


General and administrative                               


16,171


20,843


21,952


Total operating expenses                           


226,942


276,089


299,518


Operating income (loss)                             


139,548


(68,099)


319,341


Other expense:








Interest expense                                       


(37,594)


(36,053)


(56,463)


Realized and unrealized losses on interest derivative instruments, net (including unrealized gains (losses) of $(13,817), $6,163, and $6,875 in 2008, 2009 and 2010, respectively)


(15,245)


(4,985)


(2,677)


Total other expense                                


(52,839)


(41,038)


(59,140)


Income (loss) before income taxes                    


86,709


(109,137)


260,201


Income tax (expense) benefit                               


(3,029)


2,605


(30,009)


Net income (loss)                                  


83,680


(106,532)


230,192


Noncontrolling interest in net loss (income) of consolidated subsidiary


276


363


(1,564)


Net income (loss) attributable to Antero equity owners     


$

83,956


(106,169)


228,628





ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years ended December 31, 2008, 2009, and 2010

(In thousands)




2008


2009


2010


Cash flows from operating activities:








Net income (loss)                                                   


$

83,680


(106,532)


230,192


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








Depletion, depreciation, and amortization                               


124,821


139,813


133,955


Dry hole costs                                                   


6,582


1,671


19,471


Impairment of unproved properties                                   


10,112


54,204


35,859


Accretion of asset retirement obligations                               


176


265


317


Accretion of bond discount (premium), net                             



26


(361)


Amortization and write-off of deferred financing costs                   


1,283


7,268


4,052


Stock compensation                                               


269


2,822



Unrealized (gains) losses on derivative instruments, net                   


(76,484)


55,023


(177,446)


Deferred taxes                                                   


3,029


(2,605)


30,009


Gain on sale of midstream assets                                    




(147,559)


Changes in current assets and liabilities:








Accounts receivable                                            


(17,641)


19,169


(4,306)


Accrued revenue                                               


(3,798)


1,346


(7,408)


Prepaid expenses                                               


(5,973)


196


1,079


Inventories                                                    


(1,005)


553


(818)


Accounts payable                                              


3,713


(16,730)


9,779


Accrued expenses                                             


5,984


1,470


(2,849)


Revenue distributions payable                                     


17,306


(2,159)


1,747


Advance from joint interest owners                                 


5,461


(6,493)


78


Net cash provided by operating activities                          


157,515


149,307


125,791


Cash flows from investing activities:








Proved property acquisitions                                           


(3,466)


(1,029)



Additions to unproved properties                                       


(457,879)


(16,118)


(41,277)


Drilling costs                                                       


(512,112)


(258,520)


(299,926)


Additions to gathering systems and facilities                              


(51,964)


(5,819)


(47,124)


Additions to other property and equipment                               


(1,674)


(188)


(2,647)


Increase in other assets                                              


(1,479)


(225)


(556)


Sale of noncontrolling interest in subsidiary                               


24,564




Proceeds from sale of midstream assets                                 




258,918


Net assets of business acquired, net of cash of $170                       




(96,060)


Net cash used in investing activities                              


(1,004,010)


(281,899)


(228,672)


Cash flows from financing activities:








Borrowings on treasury management revolving note payable, net             


(6,307)




Issuance of senior notes                                             



372,371


156,000


Borrowings on bank credit facility                                       


279,200


170,000


324,000


Payments on bank credit facility                                        


(72,000)


(424,500)


(366,080)


Repayment of second lien term note                                     



(225,000)




Payments of deferred financing costs                                   


(758)


(17,845)


(10,459)


Issuance of preferred stock                                           


670,000


105,000



Issuance of members' equity                                           



125,000



Net cash received (paid) from (to) noncontrolling interest                    


4,623


1,176


(2,507)


Return of capital to common stockholders                                



(345)



Equity issuance cost                                                 


(291)


(1,440)


(27)


Other                                                             


(117)


(125)


273


Net cash provided by financing activities                          


874,350


104,292


101,200


Net increase (decrease) in cash and cash equivalents               


27,855


(28,300)


(1,681)


Cash and cash equivalents, beginning of year                               


11,114


38,969


10,669


Cash and cash equivalents, end of year                                   


$

38,969


10,669


8,988


Supplemental disclosure of cash flow information:








Cash paid during the year for interest                                   


$

38,896


28,395


52,326


Supplemental disclosure of noncash investing activities:








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


$

14,653


(78,220)


32,028





Results of Operations

Year Ended December 31, 2009 Compared to Year Ended December 31, 2010

The following table sets forth selected operating data for the year ended December 31, 2009 compared to the year ended December 31, 2010:




Year Ended December 31,


(in thousands, except per unit data)


2009


2010


Amount of
Increase
(Decrease)


Percent
Change


Operating revenues:










Natural gas sales                           


$

123,915


197,991


74,076


60

%

Oil sales                                  


5,706


8,471


2,765


48

%

Realized commodity derivative gains            


116,550


73,713


(42,837)


(37)

%

Unrealized commodity derivative gains (losses)   


(61,186)


170,571


231,757



*

Gathering and processing revenue             


23,005


20,554


(2,451)


(11)

%

Gain on sale of Oklahoma midstream assets      



147,559


147,559



*

Total operating revenues                   


207,990


618,859


410,869


198

%

Operating expenses:










Lease operating expenses                   


17,606


25,511


7,905


45

%

Gathering, compression and transportation       


28,190


45,809


17,619


63

%

Production taxes                           


4,940


8,777


3,837


78

%

Exploration expenses                       


10,228


24,794


14,566


142

%

Impairment of unproved properties             


54,204


35,859


(18,345)


(34)

%

Depletion, depreciation and amortization         


139,813


133,955


(5,858)


(4)

%

Accretion of asset retirement obligations         


265


317


52


20

%

Expenses related to acquisition of business      



2,544


2,544



*

General and administrative                   


20,843


21,952


1,109


5

%

Total operating expenses                   


276,089


299,518


23,429


8

%

Operating income (loss)                   


(68,099)


319,341


387,440



*

Other income (expense):










Interest expense                           


(36,053)


(56,463)


(20,410)


57

%

Realized and unrealized interest rate derivative losses


(4,985)


(2,677)


2,308


(46)

%

Total other expense                       


(41,038)


(59,140)


(18,102)


44

%

Income (loss) before income taxes           


(109,137)


260,201


369,338



*

Income tax (expense) benefit                 


2,605


(30,009)


(32,614)



*

Net income (loss)                           


(106,532)


230,192


336,724



*

Non-controlling interest in net loss (income) of consolidated subsidiary


363


(1,564)


(1,927)



*

Net income (loss) attributable to Antero equity owners


$

(106,169)


228,628


334,797



*

Production data:










Natural gas (Bcf)                           


35.1


45.8


10.7


30

%

Oil (MBbl)                                 


114.0


127.5


13.5


12

%

NGLs (MBbl)                               


433.3


333.3


(100.0)


(23)

%

Combined (Bcfe)                           


38.4


48.6


10.2


27

%

Daily combined production (MMcfe/d)           


105.2


133.1


27.9


27

%

Average prices before effects of hedges:










Natural gas (per Mcf)                        


$

3.53


4.32


.79


22

%

Oil (per Bbl)                               


$

50.05


66.44


16.39


33

%

NGLs                                     


$

31.20


45.12


13.92


45

%

Combined (per Mcfe)                        


$

3.62


4.43


0.81


22

%

Average realized prices after-effects of hedges:










Natural gas (per Mcf)                        


$

6.85


5.93


(0.92)


(13)

%

Oil (per Bbl)                               


$

50.05


66.44


16.39


33

%

NGLs                                     


$

31.20


45.12


13.92


45

%

Combined (per Mcfe)                        


$

6.88


6.02


(0.86)


(13)

%

Average costs (per Mcfe):










Lease operating costs                       


$

0.49


0.55


0.06


12

%

Gathering, compression and transportation       


$

0.79


0.98


0.19


24

%

Production taxes                           


$

0.14


0.19


0.05


36

%

Depletion, depreciation, amortization            


$

3.91


2.88


(1.03)


(26)

%

General and administrative                   


$

0.58


0.47


(0.11)


(19)

%




SOURCE Antero Resources



RELATED LINKS

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