Antero Resources Reports Third Quarter 2010 Results, Operating Update

Highlights:

- Net production averaged 143 MMcfed (including NGLs from 3rd party processing), up 45% qtr/qtr

- Consolidated EBITDAX was $50.4 million, up 3% qtr/qtr

- Net debt/proved developed reserves declined 34% to $1.29/Mcfe at end of 3rd qtr, pro forma for $270 million Arkoma midstream sale

- Liquidity rose to $609 million at end of 3rd qtr, pro forma for Arkoma midstream sale and $150 million bank borrowing base increase

- Current gross operated production is 156 MMcfed (142 MMcfed net)

- 4 Antero-operated drilling rigs running including 3 rigs in the Appalachian Basin and 1 rig in the Arkoma Basin

News provided by

Antero Resources

Nov 15, 2010, 07:00 ET

DENVER, Nov. 15, 2010 /PRNewswire/ -- Antero Resources today released its third quarter 2010 results. Those financial statements are included in Antero Resources Finance Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, which has been filed with the Securities and Exchange Commission.

Recent Developments

On November 4, 2010, Antero entered into a new credit facility with a 13-bank syndicate led by J.P. Morgan Securities, LLC and Wells Fargo Securities, LLC. The new $1 billion revolving credit facility replaced Antero's existing $400 million revolving credit facility, has an initial borrowing base of $550 million and expires in November 2015. Closing of the new bank credit facility resulted in a $150 million increase in Antero's bank borrowing base.

On November 5, 2010, Antero closed the previously announced sale of its midstream assets, located in the Woodford Shale area of the Arkoma Basin, to Cardinal Midstream, LLC for $270 million in cash. Pro forma for the midstream closing and application of proceeds for the repayment of bank debt, Antero had $532 million of available and undrawn borrowing capacity under its new bank credit facility and $77 million of cash on hand resulting in total liquidity of $609 million at September 30, 2010. At November 5, 2010, Antero had $532 million of available borrowing capacity under the new credit facility and $49 million of cash on hand resulting in total liquidity of $581 million.


	At September 30, 2010
($ in Millions)	Latest twelve months(1)	As adjusted for $150mm borrowing base increase	As further adjusted for Arkoma midstream sale(2)
Summary Operating Results
Production (Bcfe)	44.6	44.6	42.2
EBITDAX	$ 195	195	171
Proved developed reserves (Bcfe) (3)	349	349	349
Capital Structure
Cash and cash equivalents	$ 0	0	77
Bank credit facility	156	156	0
Senior notes	525	525	525
Net debt	681	681	448

Credit Statistics
Net debt / EBITDAX	3.5x	3.5x	2.6x
EBITDAX / interest expense (4)	4.2x	4.2x	4.1x
Net debt / proved developed reserves ($/Mcfe) (3)	$ 1.96	1.96	1.29

Liquidity
Current revolver commitment	$ 400	550	550
Less: outstandings and letters of credit	(174)	(174)	(18)
Plus: cash and cash equivalents (5)	0	0	77
Liquidity	$ 226	376	609


(1) Latest twelve months calculated using fourth quarter 2009 and nine months ended September 30, 2010 EBITDAX.
(2) Removes 2.4 Bcfe of third party NGLs, $24 million of EBITDA derived from Arkoma midstream business and $10 million of credit facility interest expense. Includes realized gains and losses on commodity hedges.
(3) Reserves based on Antero estimated proved reserves at June 30, 2010.
(4) Excludes $4 million of interest rate swap losses and $7 million of amortization of deferred financing costs.
(5) $270 million Arkoma midstream business sale proceeds include deducts of $30 million and $7 million for tax distribution and other fees and expenses, respectively.

Financial Results

On a consolidated basis for the three months ended September 30, 2010, Antero realized net revenue of $75.0 million (including cash-settled derivatives but excluding unrealized derivative gains and losses), a 14% increase from the third quarter of 2009, primarily driven by increased production.

Reported GAAP earnings resulted in net income of $67.8 million which includes the following non-cash items:

$11.0 million charge for impairment of unproved properties due to lease expirations.
$108.4 million unrealized gain on commodity derivatives.

Driven by higher transportation costs and higher interest expense due to the issuance of the senior notes, as well as lower realized gas prices, cash flow from operations before changes in working capital, a non-GAAP measure, declined 4% from the prior-year quarter to $37.2 million. EBITDAX of $50.4 million for the third quarter of 2010 was 3% higher than the prior-year quarter due primarily to 50% higher natural gas production partially offset by higher transportation costs and 23% lower realized gas prices including hedges. See "Non-GAAP Financial Measures" below for the reconciliation of cash flow from operations before changes in working capital to net cash provided by operating activities and EBITDAX to net income.

Net Production for the quarter totaled 13.2 Bcfe, comprised of 12.3 Bcf of gas and 136,200 barrels of oil and natural gas liquids (NGLs), representing a 16% increase over the second quarter of 2010 and a 45% increase over the third quarter of 2009. Net daily production averaged 143 MMcfed for the quarter, a record high for Antero. While gas-equivalent realized prices before hedges increased 9% to $4.12 per Mcfe, wellhead gas-equivalent realized prices including cash-settled derivatives decreased 22% to $5.52 per Mcfe for third quarter 2010 compared to the third quarter of 2009. As a result of its commodity hedging program, Antero realized gains of $17.4 million during the third quarter of 2010, or $1.39 per Mcfe of production, from contracts hedging 100,000 MMBtud at a $6.29 NYMEX equivalent price. This represents a 37% decrease from the $27.9 million of realized hedging gains, $3.31 per Mcfe, in the prior year quarter.

Per unit cash production costs (lease operating, gathering, compression and transportation and production tax) for the third quarter 2010 were $1.56 per Mcfe, a 3% increase from the prior year quarter but a 12% improvement over the previous quarter. Per unit depreciation, depletion and amortization expense decreased 31% from the prior year quarter to $2.87 per Mcfe. On a per Mcfe basis, general and administrative expense for the third quarter 2010 was $0.42 per Mcfe, a 31% decrease from the third quarter of 2009, primarily due to a 45% increase in gas-equivalent production while G&A expense remained relatively flat.

As of today, for the last quarter of 2010 and through the end of 2014, Antero has hedged 198 Bcfe using fixed price swaps at an average NYMEX-equivalent price of $6.49 per MMBtu. Approximately 81% of our fourth quarter 2010 estimated production is hedged at a NYMEX-equivalent price of $6.54 per MMBtu. Over 75% of our 2011 estimated production is hedged at a NYMEX-equivalent price of $6.20 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 seven different counterparties to its hedge contracts, all of which are lenders in the Company's bank credit facility.

Antero Operations

Antero's current gross operated production is 156 MMcfd (approximately 142 MMcfed net, including non-operated production). During the first nine months of 2010, Antero completed 29 gross operated wells (26 net wells) and currently has 28 gross operated wells (26 net wells) in various stages of drilling, completion, waiting on completion or pipeline.

Marcellus Shale—Antero is operating three drilling rigs in the Marcellus Shale play, all of which are drilling in northern West Virginia. The Company has 63 MMcfd of gross operated production from 17 horizontal wells and one vertical well online resulting in 45 MMcfd of net production. Antero has nine additional horizontal wells waiting on completion. All of these wells waiting on completion are scheduled for fracs between late November and the end of February. Antero has 127,000 net acres in the Appalachian Basin Marcellus Shale play.

Antero has secured 150 MMBtud of firm transportation capacity in Appalachia on Columbia Gas Transmission to move our gas to market. The Clarksburg Lateral, which moves gas through the heart of Antero's West Virginia acreage to Columbia, went into service in September 2010. Our 100 MMcfd firm transportation commitment on the Clarksburg Lateral increases to 150 MMcfd in early 2011 when a connecting pipeline header, the Jarvisville Lateral, is scheduled to go into service.

Woodford Shale—Antero is operating one drilling rig in the Arkoma Woodford Shale play. The Company has 47 MMcfd of gross operated production from 115 operated horizontal wells online and 54 MMcfd of net production including net non-operated production. Antero has three operated horizontal Woodford wells in the process of completing. In addition, we have 11 non-operated wells drilling with a combined 114% working interest on our Arkoma acreage. Antero has 76,000 net acres in the Arkoma Woodford Shale play.

Fayetteville Shale—Antero has four non-operated Fayetteville Shale wells drilling with a combined 14% working interest. The Company has 9 MMcfd of net production and 6,000 net acres in the Fayetteville Shale play.

Piceance Basin—Antero recently layed down its one operated drilling rig in the Piceance Basin while waiting on permitting and completion of a new compressor station to increase takeaway capacity. Our gross operated production in the Piceance is currently 46 MMcfed (34 MMcfed net including one MMcfed of non-operated production) from 168 operated wells online. Antero has one vertical Mesaverde well waiting on completion in its Battlement Mesa area, nine vertical Mesaverde wells waiting on completion in its Gravel Trend area and two Castle Springs wells in the process of completion. We plan to frac several of these wells in December. Antero has 68,000 net acres in the Piceance Basin.

Capital Expenditures

Antero's capital budget for 2010 is $381 million excluding acquisitions. The budget is expected to be funded internally from operating cash flow and through the use of the wholly undrawn capacity under our new credit facility. The 2010 capital program includes $320 million for drilling and completion, $47 million for leasehold acquisitions and $14 million for the construction of gathering pipelines and facilities. Approximately 55% of the budget is allocated to the Marcellus Shale, 26% is allocated to the Woodford Shale and 19% is allocated to the Piceance. Antero plans to continue operating four drilling rigs for the remainder of 2010.

2010 Outlook

The following table provides Antero's forward-looking guidance based on its updated forecasts for 2010:


2010 Outlook
NYMEX Gas Price ($/MMBtu)	$4.25/MMBtu
Net Production (MMcfe/d)	130 - 140 MMcfe/d
EBITDAX ($MMs)	$200 - $215 million
Cash Production Costs ($/Mcfe)	$1.60 - $1.70/Mcfe
G&A ($/Mcfe)	$0.50/Mcfe

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 and exploration expense. 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:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2010	2009	2010
Net cash provided by operating activities	$25,653	45,607	118,231	106,511
Net change in working capital	9,899	(12,045)	(4,245)	(10,055)
Exploration expense	3,094	3,644	8,440	7,043
Cash flow from operations before changes in working capital	$38,646	37,206	122,426	103,499

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 derivative gains or losses, 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 outstanding 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 three and nine months ended September 30, 2010 and 2009:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2010	2009	2010
Net income (loss) attributable to Antero members	$(53,345)	67,780	(86,838)	138,979
Unrealized loss (gain) on commodity derivative contracts	44,293	(108,439)	70,742	(217,399)
Interest expense and other	9,215	15,281	27,266	44,363
Provision (benefit) for income taxes	0	25,107	(3,029)	39,287
Depreciation, depletion, amortization and accretion	34,873	35,965	109,181	101,374
Impairment of unproved properties	9,885	11,043	24,583	31,590
Exploration expense	3,094	3,644	8,440	7,043
Other	851	37	1,683	110
EBITDAX	$48,866	50,418	152,008	145,347

The cash prices realized for oil 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 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. Our website is www.anteroresources.com.

This release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

ANTERO RESOURCES LLC Consolidated Balance Sheets December 31, 2009 and September 30, 2010 (In thousands) (Unaudited)
	December 31,		September 30,
	2009		2010
Assets
Current assets:
Cash and cash equivalents	$	10,669	—
Accounts receivable — trade, net of allowance for doubtful accounts of $424 and $191, respectively	35,897		22,636
Accrued revenue	17,459		18,310
Prepaid expenses and drilling costs	7,419		16,937
Derivative instruments	22,105		87,496
Inventories	1,295		2,064
Assets held for sale	—		160,294
Total current assets	94,844		307,737
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties	596,694		579,845
Producing properties	1,340,827		1,614,397
Gathering systems and facilities	185,688		30,886
Other property and equipment	3,302		5,574
	2,126,511		2,230,702
Less accumulated depletion, depreciation, and amortization	(322,992)		(399,061)
Property and equipment, net	1,803,519		1,831,641
Derivative instruments	18,989		170,997
Other assets, net	19,214		16,202
Total assets	$	1,936,566	2,326,577

ANTERO RESOURCES LLC Consolidated Balance Sheets December 31, 2009 and September 30, 2010 (In thousands) (Unaudited)
	December 31,		September 30,
	2009		2010
Liabilities and Equity
Current liabilities:
Accounts payable	$	48,594	75,463
Accrued expenses	24,440		36,926
Revenue distributions payable	29,304		20,004
Advances from joint interest owners	1,400		1,847
Derivative instruments	8,623		6,312
Capital leases — current	132		152
Liabilities related to assets held for sale	—		19,231
Total current liabilities	112,493		159,935
Long-term liabilities:
Bank credit facility	142,080		155,994
Senior notes	372,397		528,110
Derivative instruments	2,464		—
Asset retirement obligations	3,487		3,934
Deferred tax payable	424		38,082
Other long-term liabilities	4,114		3,359
Total liabilities	637,459		889,414
Equity:
Members' equity	1,392,833		1,392,806
Accumulated earnings (deficit)	(123,447)		15,532
	1,269,386		1,408,338
Noncontrolling interest in consolidated subsidiary	29,721		28,825
Total equity	1,299,107		1,437,163
Total liabilities and equity	$	1,936,566	2,326,577

ANTERO RESOURCES LLC Consolidated Statements of Operations Three months ended September 30, 2009 and 2010 (In thousands) (Unaudited)
	2009		2010
Revenue:
Natural gas sales	$	30,008	49,870
Net realized and unrealized gains (losses) on commodity derivative instruments including unrealized gains (losses) of $(44,293) and $108,439, respectively	(16,437)		125,875
Oil sales	1,664		1,684
Gathering and processing revenue	6,209		5,973
Total revenue	21,444		183,402

Operating expenses:
Lease operating expenses	3,664		6,070
Gathering, compression, and transportation	7,522		11,210
Production taxes	1,565		2,187
Exploration expenses	3,094		3,644
Impairment of unproved properties	9,885		11,043
Depletion, depreciation, and amortization	34,805		35,886
Accretion of asset retirement obligations	68		79
General and administrative	5,122		5,296
Total operating expenses	65,725		75,415
Operating income (loss)	(44,281)		107,987

Other expense:
Interest expense, net	(7,184)		(14,526)
Net realized and unrealized losses on interest rate derivative instruments including unrealized gains of $1,114 and $1,302, respectively	(2,031)		(755)
Total other expense	(9,215)		(15,281)
Income (loss) before income taxes	(53,496)		92,706
Deferred income tax expense	—		(25,107)
Net income (loss)	(53,496)		67,599
Noncontrolling interest in net loss of consolidated subsidiary	151		181
Net income (loss) attributable to Antero members	$	(53,345)	67,780

ANTERO RESOURCES LLC Consolidated Statements of Operations Nine months ended September 30, 2009 and 2010 (In thousands) (Unaudited)
	2009		2010
Revenue:
Natural gas sales	$	91,603	146,709
Net realized and unrealized gains on commodity derivative instruments including unrealized gains (losses) of $(70,742) and $217,399, respectively	19,669		263,282
Oil sales	4,251		6,101
Gathering and processing revenue	15,902		18,462
Total revenue	131,425		434,554

Operating expenses:
Lease operating expenses	14,389		16,945
Gathering, compression, and transportation	19,183		32,108
Production taxes	4,393		6,789
Exploration expenses	8,440		7,043
Impairment of unproved properties	24,583		31,590
Depletion, depreciation, and amortization	108,987		101,147
Accretion of asset retirement obligations	194		227
General and administrative	14,396		14,464
Total operating expenses	194,565		210,313
Operating income (loss)	(63,140)		224,241

Other expense:
Interest expense, net	(23,410)		(41,783)
Net realized and unrealized losses on interest rate derivative instruments including unrealized gains of $3,811 and $4,776, respectively	(3,856)		(2,580)
Total other expense	(27,266)		(44,363)
Income (loss) before income taxes	(90,406)		179,878
Deferred income tax benefit (expense)	3,029		(39,287)
Net income (loss)	(87,377)		140,591
Noncontrolling interest in net loss (income) of consolidated subsidiary	539		(1,612)
Net income (loss) attributable to Antero members	$	(86,838)	138,979

ANTERO RESOURCES LLC Consolidated Statements of Cash Flows Nine months ended September 30, 2009 and 2010 (In thousands) (Unaudited)
	2009		2010
Cash flows from operating activities:
Net income (loss)	$	(87,377)	140,591
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization	108,987		101,147
Dry hole costs	760		2,981
Impairment of unproved properties	24,583		31,590
Accretion of asset retirement obligations	194		227
Amortization of bond premium	—		(287)
Amortization of deferred financing costs	2,410		3,095
Stock compensation	527		—
Unrealized losses (gains) on derivative instruments, net	66,931		(222,175)
Deferred tax expense (benefit)	(3,029)		39,287
Changes in current assets and liabilities:
Accounts receivable	22,262		951
Accrued revenue	7,588		(850)
Prepaid expenses and drilling costs	187		(9,749)
Inventories	745		(830)
Accounts payable	(18,666)		3,305
Accrued expenses	(679)		14,145
Revenue distributions payable	(758)		2,636
Advances from joint interest owners	(6,434)		447
Net cash provided by operating activities	118,231		106,511

Cash flows from investing activities:
Additions to unproved properties	(9,459)		(27,997)
Drilling costs	(216,862)		(239,257)
Gathering systems and facilities	(3,696)		(8,825)
Additions to other property and equipment	(144)		(2,391)
Decrease (increase) in other assets	159		(317)
Net cash used in investing activities	(230,002)		(278,787)

ANTERO RESOURCES LLC Consolidated Statements of Cash Flows Nine months ended September 30, 2009 and 2010 (In thousands) (Unaudited)
	2009		2010
Cash flows from financing activities:
Issuance of senior notes	$	—	156,000
Borrowings on bank credit facility	15,000		170,994
Payments on bank credit facility	(25,000)		(157,080)
Payments on capital lease obligations	(93)		(148)
Financing costs	(6,461)		(3,788)
Issuance of preferred stock	105,000		—
Other	(220)		443
Net cash from (to) noncontrolling interest	766		(2,508)
Net cash provided by financing activities	88,992		163,913
Net decrease in cash and cash equivalents	(22,779)		(8,363)
Cash classified as assets held for sale	—		(2,306)
Cash and cash equivalents, beginning of period	38,969		10,669
Cash and cash equivalents, end of period	$	16,190	—
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	(27,654)	(26,939)
Supplemental disclosure of noncash investing activities:
Net changes in accounts payable for additions to properties, systems, and facilities	$	(85,688)	23,819

Results of Operations *Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2010*
	Three Months Ended September 30,				Amount of Increase		Percent
	2009		2010		(Decrease)		Change
	(in thousands, except per unit data)
Operating revenues:
Natural gas sales	$	30,008	$	49,870	$	19,862	66%
Oil sales	1,664		1,684		20		1%
Realized commodity derivative gains	27,856		17,436		(10,420)		(37)%
Unrealized commodity derivative gains (losses)	(44,293)		108,439		152,732		*
Gathering and processing	6,209		5,973		(236)		(4)%
Total operating revenues	21,444		183,402		161,958		755%
Operating expenses:
Lease operating expense	3,664		6,070		2,406		66%
Gathering, compression and transportation	7,522		11,210		3,688		49%
Production taxes	1,565		2,187		622		40%
Exploration expense	3,094		3,644		550		18%
Impairment of unproved properties	9,885		11,043		1,158		12%
Depletion depreciation and amortization	34,805		35,886		1,081		3%
Accretion of asset retirement obligations	68		79		11		16%
General and administrative	5,122		5,296		174		3%
Total operating expenses	65,725		75,515		9,690		15%
Operating income (loss)	(44,281)		107,987		152,268
Other income (expense):
Interest expense	(7,184)		(14,526)		(7,342)		102%
Realized interest rate derivative losses	(3,145)		(2,056)		1,089		(35)%
Unrealized interest rate derivative gains	1,114		1,301		187		17%
Total other expense	(9,215)		(15,281)		(6,066)		66%
Income (loss) before income taxes	(53,496)		92,706		146,202		*
Deferred income tax (expense) benefit	—		(25,107)		(25,107)		*
Net income (loss)	(53,496)		67,599		121,095		*
Non-controlling interest in net income of consolidated subsidiary	151		181		30		20%
Net income (loss) attributable to Antero members	$	(53,345)	$	67,780	$	121,245	*
Production data:
Natural gas (Bcf)	8.2		12.3		4.1		50%
Oil (MBbl)	31.6		26.0		(5.6)		(18)%
NGLs (MBbl)(1)	113.8		110.2		(3.6)		(3)%
Combined (Bcfe)	9.1		13.2		4.1		45%
Daily combined production (MMcfe/d)	98.8		143.1		44.3		45%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	3.65	$	4.04	$	0.39	11%
Oil (per Bbl)	$	52.66	$	64.77	$	12.11	23%
Combined (per Mcfe)	$	3.77	$	4.12	$	0.35	9%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	7.04	$	5.45	$	(1.59)	(23)%
Oil (per Bbl)	$	52.66	$	64.77	$	12.11	23%
Combined (per Mcfe)	$	7.08	$	5.52	$	(1.56)	(22)%
Average Costs (per Mcfe):
Lease operating costs	$	0.44	$	0.49	$	0.05	11%
Gathering, compression and transportation	$	0.89	$	0.90	$	0.01	1%
Production taxes	$	0.19	$	0.17	$	(0.02)	(11)%
Depletion, depreciation amortization and accretion	$	4.14	$	2.88	$	(1.27)	(31)%
General and administrative	$	0.61	$	0.42	$	(0.19)	(31)%


(1) Represents NGLs retained by our midstream business as compensation for processing third-party gas under long term contracts. These amounts are not reflected in the per Mcfe data in this table.

(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 production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.

* Not meaningful or applicable

Results of Operations *Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2010*
	Nine Months Ended September 30,				Amount of Increase		Percent
	2009		2010		(Decrease)		Change
	(in thousands, except per unit data)
Operating revenues:
Natural gas sales	$	91,603	$	146,709	$	55,106	60%
Oil sales	4,251		6,101		1,850		44%
Realized commodity derivative gains	90,411		45,883		(44,528)		(49)%
Unrealized commodity derivative gains (losses)	(70,742)		217,399		288,141		*
Gathering and processing	15,902		18,462		2,560		16%
Total operating revenues	131,425		434,554		303,129		231%
Operating expenses:
Lease operating expense	14,389		16,945		2,556		18%
Gathering, compression and transportation	19,183		32,108		12,925		67%
Production taxes	4,393		6,789		2,396		55%
Exploration expense	8,440		7,043		(1,397)		(17)%
Impairment of unproved properties	24,583		31,590		7,007		29%
Depletion depreciation and amortization	108,987		101,147		(7,840)		(7)%
Accretion of asset retirement obligations	194		227		33		17%
General and administrative	14,396		14,464		68		*
Total operating expenses	194,565		210,313		15,748		8%
Operating income (loss)	(63,140)		224,241		287,381		*
Other income (expense):
Interest expense	(23,410)		(41,783)		18,373		78%
Realized interest rate derivative losses	(7,667)		(7,355)		(312)		(4)%
Unrealized interest rate derivative gains	3,811		4,775		(964)		25%
Total other expense	(27,266)		(44,363)		17,097		63%
Income (loss) before income taxes	(90,406)		179,878		270,284		*
Deferred income tax (expense) benefit	3,029		(39,287)		(42,316)		*
Net income (loss)	(87,377)		140,591		227,968		*
Non-controlling interest in net income of consolidated subsidiary	539		(1,612)		(2,151)		*
Net income (loss) attributable to Antero members	$	(86,838)	$	138,979	$	225,817	*
Production data:
Natural gas (Bcf)	26.3		32.7		6.4		24%
Oil (MBbl)	92.1		94.3		2.2		2%
NGLs (MBbl)(1)	341.3		301.6		(39.7)		(12)%
Combined (Bcfe)	28.9		35.1		6.2		21%
Daily combined production (MMcfe/d)	105.9		128.5		22.6		21%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	3.48	$	4.49	$	1.01	29%
Oil (per Bbl)	$	46.16	$	64.70	$	18.54	40%
Combined (per Mcfe)	$	3.57	$	4.59	$	1.02	29%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	6.92	$	5.89	$	(1.03)	(15)%
Oil (per Bbl)	$	46.16	$	64.70	$	18.54	40%
Combined (per Mcfe)	$	6.93	$	5.97	$	(0.96)	(14)%
Average Costs (per Mcfe):
Lease operating costs	$	0.54	$	0.51	$	(0.03)	(6)%
Gathering, compression and transportation	$	0.71	$	0.97	$	0.26	37%
Production taxes	$	0.16	$	0.20	$	0.04	25%
Depletion, depreciation amortization and accretion	$	4.06	$	3.04	$	(1.02)	(25)%
General and administrative	$	0.54	$	0.43	$	(0.11)	(20)%


(1) Represents NGLs retained by our midstream business as compensation for processing third-party gas under long term contracts. These amounts are not reflected in the per Mcfe data in this table.

(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 production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.

* Not meaningful or applicable