Edgar Filing: PETROLEUM DEVELOPMENT CORP

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2011

£ 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 000-07246

PETROLEUM DEVELOPMENT CORPORATION

(Exact name of registrant as specified in its charter)

(Doing Business as PDC Energy)



Nevada	95-2636730
(State of Incorporation)	(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000

Denver, Colorado 80203

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (303) 860-5800

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. Yes T 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). Yes £ 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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer £	Accelerated filer x
Non-accelerated filer £ (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). Yes £ No T

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 23,496,892 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 22, 2011.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

TABLE OF CONTENTS



	PART I - FINANCIAL INFORMATION	Page

Item 1.	Financial Statements	5
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
	1. Nature of Operations and Basis of Presentation
	2. Recent Accounting Standards
	3. Fair Value Measurements and Disclosures
	4. Derivative Financial Instruments
	5. Properties and Equipment
	6. Income Taxes
	7. Long-Term Debt
	8. Asset Retirement Obligations
	9. Commitments and Contingencies
	10. Stock-Based Compensation Plans
	11. Earnings Per Share
	12. Divestitures and Discontinued Operations
	13. Transactions with Affiliates
	14. Business Segments
	15. Subsequent Events
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	40

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	[Removed and Reserved]	40
Item 5.	Other Information	40
Item 6.	Exhibits	40

	SIGNATURES	42

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas, NGL and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures, including our ability to fund our 2011 capital plan, our compliance with our debt covenants and the indenture restrictions governing our senior notes, sufficient liquidity to meet our partnership repurchase obligation, the adequacy of our casualty insurance coverage, the impact of decreased commodity prices on future borrowing base redeterminations, the effectiveness of our derivative policies in achieving our risk management objectives, the decrease during the next twelve months of our liability for uncertain tax benefits, funding sources for our acquisitions, the acceleration of our capital spending program due to a rise in crude oil prices, the potential operational benefits and cost synergies due to the acquisition of certain partnerships and our management’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:


•	changes in production volumes and worldwide demand;


•	volatility of commodity prices for natural gas and crude oil;


•	changes in estimates of proved reserves;


•	inaccuracy of reserve estimates and expected production rates;


•	declines in the values of our natural gas and crude oil properties resulting in impairments;


•	the future cash flow, liquidity and financial position of the Company;


•	the timing and extent of our success in discovering, acquiring, developing and producing reserves;


•	our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;


•	reductions in the borrowing base under our credit facility;


•	risks incidental to the drilling and operation of natural gas and crude oil wells;


•	the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;


•	the effect of existing and future laws, governmental regulations and the political and economic climate of the U.S. as well as other oil producing countries throughout the world;


•	changes in environmental laws, the regulation and enforcement of those laws and the costs to comply with those laws;


•	the impact of environmental events, governmental responses to the events and our ability to insure adequately against such events;


•	competition in the oil and gas industry;


•	the success of the Company in marketing oil and gas;


•	the effect of natural gas and crude oil derivatives activities;


•	the availability and cost of capital to us;


•	our ability to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;


•	losses possible from pending or future litigation; and


•	the success of strategic plans, expectations and objectives for future operations of the Company.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this report, our annual report on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange Commission ("SEC") on February 24, 2011, as amended April 21, 2011 ("2010 Form 10-K"), and our other filings with the SEC for further information on risks and uncertainties that could affect the Company's business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement.

REFERENCES

Unless the context otherwise requires, references to "PDC," "PDC Energy," "the Company," "we," "us," "our," "ours" or "ourselves" in this report refer to the registrant, Petroleum Development Corporation and its consolidated entities. See Note 1, Nature of Operations and Basis of Presentation, to our condensed consolidated financial statements included in this report for a description of our consolidated entities.

References to "the three months ended 2011" refer to the three months ended March 31, 2011, as applicable. References to "the three months ended 2010" refer to the three months ended March 31, 2010, as applicable.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

Condensed Consolidated Balance Sheets

(unaudited; in thousands, except share and per share data)



	March 31, 2011			December 31, 2010 (1)
Assets
Current assets:
Cash and cash equivalents	$	14,699		$	54,372
Accounts receivable, net	62,512			53,978
Accounts receivable affiliates	14,989			11,448
Fair value of derivatives	40,190			42,953
Prepaid expenses and other current assets	20,415			14,072
Total current assets	152,805			176,823
Properties and equipment, net	1,152,957			1,120,038
Assets held for sale	—			5,191
Fair value of derivatives	37,234			44,464
Accounts receivable affiliates	7,518			8,478
Other assets	37,833			34,041
Total Assets	$	1,388,347		$	1,389,035

Liabilities and Equity
Liabilities
Current liabilities:
Accounts payable	$	52,262		$	47,271
Accounts payable affiliates	9,507			9,605
Production tax liability	16,099			16,226
Fair value of derivatives	42,266			29,998
Funds held for distribution	31,395			29,755
Accrued interest payable	5,069			10,051
Other accrued expenses	16,406			17,723
Total current liabilities	173,004			160,629
Long-term debt	296,709			295,695
Deferred income taxes	181,407			187,999
Asset retirement obligations	27,937			27,797
Fair value of derivatives	43,937			36,644
Accounts payable affiliates	10,297			12,111
Other liabilities	30,455			25,919
Total liabilities	763,746			746,794

Commitments and contingent liabilities

Equity
Shareholders' equity:
Preferred shares, par value $0.01 per share; authorized 50,000,000 shares; issued: none	—			—
Common shares, par value $0.01 per share; authorized 100,000,000 shares; issued: 23,478,611 in 2011 and 23,462,326 in 2010	235			235
Additional paid-in capital	211,482			209,198
Retained earnings	412,919			432,843
Treasury shares, at cost: 2,938 in 2011 and 2010	(111		)	(111		)
Total shareholders' equity	624,525			642,165
Noncontrolling interest in subsidiary	76			76
Total equity	624,601			642,241
Total Liabilities and Equity	$	1,388,347		$	1,389,035

__________

(1) Derived from audited 2010 balance sheet.

See accompanying Notes to Condensed Consolidated Financial Statements

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

Condensed Consolidated Statements of Operations

(unaudited; in thousands, except per share data)



	Three Months Ended March 31,
	2011			2010
Revenues:
Natural gas, NGL and crude oil sales	$	63,879		$	57,827
Sales from natural gas marketing	15,202			22,687
Commodity price risk management gain (loss), net	(23,882		)	43,222
Well operations, pipeline income and other	1,876			2,589
Total revenues	57,075			126,325

Costs, expenses and other:
Production costs	21,039			14,961
Cost of natural gas marketing	14,993			22,323
Exploration expense	2,151			6,418
General and administrative expense	13,873			10,694
Depreciation, depletion and amortization	32,357			27,458
Total costs, expenses and other	84,413			81,854

Income (loss) from operations	(27,338		)	44,471
Interest income	9			5
Interest expense	(9,062		)	(7,800		)

Income (loss) from continuing operations before income taxes	(36,391		)	36,676
Provision (benefit) for income taxes	(13,847		)	13,804
Income (loss) from continuing operations	(22,544		)	22,872
Income from discontinued operations, net of tax	2,620			797
Net income (loss)	(19,924		)	23,669
Less: net loss attributable to noncontrolling interests	—			(55		)
Net income (loss) attributable to shareholders	$	(19,924	)	$	23,724

Amounts attributable to Petroleum Development Corporation shareholders:
Income (loss) from continuing operations	$	(22,544	)	$	22,927
Income from discontinued operations, net of tax	2,620			797
Net income (loss) attributable to shareholders	$	(19,924	)	$	23,724

Earnings (loss) per share attributable to shareholders:
Basic
Income (loss) from continuing operations	$	(0.96	)	$	1.19
Income from discontinued operations	0.11			0.04
Net income (loss) attributable to shareholders	$	(0.85	)	$	1.23
Diluted
Income (loss) from continuing operations	$	(0.96	)	$	1.19
Income from discontinued operations	0.11			0.04
Net income (loss) attributable to shareholders	$	(0.85	)	$	1.23

Weighted average common shares outstanding:
Basic	23,428			19,191
Diluted	23,428			19,287

See accompanying Notes to Condensed Consolidated Financial Statements

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

Condensed Consolidated Statements of Cash Flows

(unaudited, in thousands)



	Three Months Ended March 31,
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	(19,924	)	$	23,669
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Unrealized (gain) loss on derivatives, net	27,745			(20,490		)
Depreciation, depletion and amortization	32,357			28,389
Amortization and impairment of unproved natural gas and crude oil properties	453			600
Exploratory dry hole costs	35			2,902
Loss (gain) from sale of leaseholds/assets	(3,928		)	270
Deferred income taxes	(14,024		)	11,632
Other	3,385			2,357
Changes in assets and liabilities	(10,623		)	2,016
Net cash provided by operating activities	15,476			51,345
Cash flows from investing activities:
Capital expenditures	(71,079		)	(32,581		)
Deconsolidation/change in ownership effect on cash and cash equivalents	(101		)	(3,074		)
Proceeds from sale of leaseholds/assets	9,952			16
Net cash used in investing activities	(61,228		)	(35,639		)
Cash flows from financing activities:
Proceeds from credit facility	—			64,000
Payment of credit facility	—			(85,000		)
Contribution by investing partner in PDCM	6,407			—
Other	(328		)	(190		)
Net cash provided by (used in) financing activities	6,079			(21,190		)
Net decrease in cash and cash equivalents	(39,673		)	(5,484		)
Cash and cash equivalents, beginning of period	54,372			31,944
Cash and cash equivalents, end of period	$	14,699		$	26,460

Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest	$	12,314		$	7,067
Income taxes, net of refunds	85			(33		)
Non-cash investing activities:
Change in accounts payable related to purchases of properties and equipment	5,832			6,056
Change in asset retirement obligation, with a corresponding increase to properties and equipment, net of disposals	229			207

See accompanying Notes to Condensed Consolidated Financial Statements

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(unaudited)

NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy is a domestic independent natural gas and crude oil company engaged in the exploration for and the acquisition, development, production and marketing of natural gas, natural gas liquids ("NGLs") and crude oil. As of March 31, 2011, we owned an interest in approximately 5,000 wells located primarily in the Rocky Mountain Region and the Permian and Appalachian Basins. We operate through two business segments: (1) natural gas and crude oil sales and (2) natural gas marketing.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, an entity in which we have a controlling financial interest and our proportionate share of PDC Mountaineer, LLC ("PDCM") and 29 of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. As of March 31, 2011, PDCM was consolidated at 52.7% and the 29 partnerships were consolidated at varying percentages.

As of December 31, 2010, PDCM was consolidated at 55.8%, representing our ownership interest. On January 1 and March 1, 2011, our joint venture partner made capital contributions of cash to PDCM of $7 million and $5 million, respectively. The contributions resulted in our ownership interest decreasing from 55.8% to 53.9%, then to 52.7%. Each change in our ownership interest resulted in a decrease in our proportionate share of net assets and any future earnings.

With the exception of our initial capital contribution in October 2009, we have not entered into any arrangement that would require us to provide financial support to PDCM. Further, we are not liable for any debts, obligations or liabilities of the joint venture and its creditors have no recourse against our general credit in the event of default. None of our affiliated partnerships’ wells were included in the joint venture.

The following table presents the carrying amount and classification of our proportionate share of PDCM's assets and liabilities included in our balance sheets.



	March 31, 2011		December 31, 2010
	(in thousands)

Cash and cash equivalents	$	1,808	$	1,560
Other current assets	2,560		3,206
Property, plant and equipment, net	103,018		101,679
Other assets	1,979		1,986
Total assets	$	109,365	$	108,431

Total current liabilities	$	6,622	$	4,641
Asset retirement obligations	8,322		8,681
Other liabilities	1,784		1,370
Equity	92,637		93,739
Total liabilities and equity	$	109,365	$	108,431

In our opinion, the accompanying financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2010 Form 10-K. Our accounting policies are described in the Notes to Consolidated Financial Statements in our 2010 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three months ended 2011, and the cash flows for the same period, are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are directly related to our discontinued operations. The reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. See Note 12 for additional information regarding our discontinued operations.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 2 - RECENT ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures. In January 2010, the FASB issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for our financial statements issued for the annual reporting period, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on our financial statements.

NOTE 3 - FAIR VALUE MEASUREMENTS AND DISCLOSURES

Derivative Financial Instruments

The following table presents, for each hierarchy level, our derivative assets and liabilities, both current and non-current portions, including the derivative assets and liabilities designated to our affiliated partnerships and our proportionate share of PDCM's derivative assets and liabilities, measured at fair value on a recurring basis.



	March 31, 2011								December 31, 2010
	Quoted Prices in Active Markets (Level 1)		Significant Unobservable Inputs (Level 3)			Total			Quoted Prices in Active Markets (Level 1)		Significant Unobservable Inputs (Level 3)			Total
	(in thousands)
Assets:
Commodity based derivatives contracts	$	58,740	$	18,624		$	77,364		$	64,138	$	23,168		$	87,306
Basis protection derivative contracts	—		60			60			—		111			111
Total assets	58,740		18,684			77,424			64,138		23,279			87,417
Liabilities:
Commodity based derivatives contracts	644		39,717			40,361			51		20,011			20,062
Basis protection derivative contracts	—		45,842			45,842			—		46,580			46,580
Total liabilities	644		85,559			86,203			51		66,591			66,642
Net asset (liability)	$	58,096	$	(66,875	)	$	(8,779	)	$	64,087	$	(43,312	)	$	20,775

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents a reconciliation of our Level 3 fair value measurements.



	Three Months Ended March 31,
	2011			2010
	(in thousands)

Fair value, net liability, beginning of period	$	(43,312	)	$	(28,994	)
Changes in fair value included in statement of operations line item:
Commodity price risk management gain (loss), net	(24,405		)	12,431
Sales from natural gas marketing	14			383
Cost of natural gas marketing	(6		)	(3,293		)
Changes in fair value included in balance sheet line item (1):
Accounts receivable affiliates	(104		)	(2,320		)
Accounts payable affiliates	(654		)	(4,538		)
Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net	720			(20,980		)
Sales from natural gas marketing	(75		)	—
Cost of natural gas marketing	947			(5		)
Fair value, net liability, end of period	$	(66,875	)	$	(47,316	)

Changes in unrealized gains (losses) relating to assets (liabilities) still held
as of period end, included in statement of operations line item:
Commodity price risk management gain (loss), net	$	(18,906	)	$	8,477
Sales from natural gas marketing	(7		)	353
Cost of natural gas marketing	(46		)	(3,604		)
	$	(18,959	)	$	5,226

__________

(1) Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.

See Note 4 for additional disclosure related to our derivative financial instruments.

Non-Derivative Financial Assets and Liabilities

The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

The portion of our long-term debt related to our credit facility approximates fair value due to the variable nature of its related interest rate. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of March 31, 2011, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2015 to be $151.9 million or 132.1% of par value and the portion related to our 12% senior notes due 2018 to be $229.9 million or 113.2% of par value. We determined these valuations based upon measurements of broker/dealer quotes and trading activity, respectively.

NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS

As of March 31, 2011, we had derivative instruments in place for a portion of our anticipated production through 2015 for a total of 43,533.4 BBtu of natural gas and 2,685.8 MBbls of crude oil.

The following table presents the location and fair value amounts of our derivative instruments on the balance sheets. These derivative instruments were comprised of commodity floors, collars and swaps, basis protection swaps and physical sales and purchases.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued



			Fair Value
Derivatives instruments not designated as hedges (1):		Balance sheet line item	March 31, 2011		December 31, 2010
			(in thousands)
Derivative assets:	Current
	Commodity contracts
	Related to natural gas and crude oil sales	Fair value of derivatives	$	30,500	$	32,837
	Related to affiliated partnerships (2)	Fair value of derivatives	8,471		8,231
	Related to natural gas marketing	Fair value of derivatives	1,171		1,811
	Basis protection contracts
	Related to natural gas marketing	Fair value of derivatives	48		74
			40,190		42,953
	Non Current
	Commodity contracts
	Related to natural gas and crude oil sales	Fair value of derivatives	26,845		32,270
	Related to affiliated partnerships (2)	Fair value of derivatives	10,297		12,111
	Related to natural gas marketing	Fair value of derivatives	80		46
	Basis protection contracts
	Related to natural gas marketing	Fair value of derivatives	12		37
			37,234		44,464
Total derivative assets			$	77,424	$	87,417

Derivative liabilities:	Current
	Commodity contracts
	Related to natural gas and crude oil sales	Fair value of derivatives	$	20,487	$	10,636
	Related to affiliated partnerships (3)	Fair value of derivatives	1,986		1,676
	Related to natural gas marketing	Fair value of derivatives	912		1,492
	Basis protection contracts
	Related to natural gas and crude oil sales	Fair value of derivatives	13,665		11,725
	Related to affiliated partnerships (3)	Fair value of derivatives	5,215		4,462
	Related to natural gas marketing	Fair value of derivatives	1		7
			42,266		29,998
	Non Current
	Commodity contracts
	Related to natural gas and crude oil sales	Fair value of derivatives	16,943		6,231
	Related to affiliated partnerships (3)	Fair value of derivatives	—		(3		)
	Related to natural gas marketing	Fair value of derivatives	33		30
	Basis protection contracts
	Related to natural gas and crude oil sales	Fair value of derivatives	19,442		21,905
	Related to affiliated partnerships (3)	Fair value of derivatives	7,518		8,481
	Related to natural gas marketing	Fair value of derivatives	1		—
			43,937		36,644
Total derivative liabilities			$	86,203	$	66,642

__________

(1)As of March 31, 2011, and December 31, 2010, none of our derivative instruments were designated as hedges.

(2) Our balance sheets include a corresponding payable to our affiliated partnerships of $18.8 million and $20.3 million as of March 31, 2011, and December 31, 2010, respectively.

(3) Our balance sheets include a corresponding receivable from our affiliated partnerships of $14.7 million and $14.6 million as of March 31, 2011, and December 31, 2010, respectively.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents the impact of our derivative instruments on our statements of operations.



	Three Months Ended March 31,
	2011									2010
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total			Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total
	(in thousands)
Commodity price risk management gain (loss), net
Realized gains	$	3,322		$	466		$	3,788		$	21,067		$	1,857		$	22,924
Unrealized gains (losses)	(3,322		)	(24,348		)	(27,670		)	(21,067		)	41,365			20,298
Total commodity price risk management gain (loss), net (1)	$	—		$	(23,882	)	$	(23,882	)	$	—		$	43,222		$	43,222
Sales from natural gas marketing
Realized gains	$	1,007		$	135		$	1,142		$	752		$	308		$	1,060
Unrealized gains (losses)	(1,007		)	(10		)	(1,017		)	(752		)	4,264			3,512
Total sales from natural gas marketing (2)	$	—		$	125		$	125		$	—		$	4,572		$	4,572
Cost of natural gas marketing
Realized losses	$	(770	)	$	(190	)	$	(960	)	$	(774	)	$	(322	)	$	(1,096	)
Unrealized gains (losses)	770			172			942			774			(4,094		)	(3,320		)
Total cost of natural gas marketing (2)	$	—		$	(18	)	$	(18	)	$	—		$	(4,416	)	$	(4,416	)

____________

(1) Represents realized and unrealized gains and losses on derivative instruments related to natural gas and crude oil sales.

(2) Represents realized and unrealized gains and losses on derivative instruments related to natural gas marketing.

Concentration of Credit Risk. We make extensive use of over-the-counter derivative instruments that enable us to manage a portion of our exposure to price volatility from producing and marketing natural gas and crude oil. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions, who are also major lenders in our credit facility agreement, as counterparties to our derivative contracts. To date, we have had no counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, the impact of the nonperformance of our counterparties on the fair value of our derivative instruments was not significant.

The following table presents the derivative counterparties that expose us to credit risk.



Counterparty Name	Fair Value of Derivative Assets As of March 31, 2011
	(in thousands)

JPMorgan Chase Bank, N.A. (1)	$	35,522
Crèdit Agricole CIB (1)	25,370
Wells Fargo Bank, N.A. (1)	13,667
Various (2)	2,865
Total	$	77,424

________________________

(1)Major lender in our credit facility, see Note 7.

(2)Represents a total of 19 counterparties, including two lenders in our credit facility.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 5 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net.



	March 31, 2011			December 31, 2010
	(in thousands)
Properties and equipment, net:
Natural gas and crude oil properties
Proved	$	1,488,520		$	1,429,667
Unproved	69,906			79,053
Total natural gas and crude oil properties	1,558,426			1,508,720
Pipelines and related facilities	34,203			34,262
Transportation and other equipment	32,456			32,410
Land, buildings and leasehold improvements	14,514			13,379
Construction in progress	54,260			42,128
	1,693,859			1,630,899
Accumulated DD&A	(540,902		)	(510,861		)
Properties and equipment, net	$	1,152,957		$	1,120,038

NOTE 6 - INCOME TAXES

We evaluate our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and enacted tax laws. The estimated annual effective tax rate is adjusted quarterly based upon actual results and updated operating forecasts; consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax on income or tax benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

The effective tax rate for continuing operations for the three months ended 2011, was 38.1% compared to 37.6% for the three months ended 2010. The tax benefit recognized for the three months ended 2011 has been limited to the amount expected to be realized during the year. The limitation was $1.2 million. The effective tax rate differs from the statutory rate primarily due to net permanent deductions, largely percentage depletion, increasing the tax benefit on loss for this period, while decreasing the tax provision on pretax income for the same prior year period. There were no significant discrete items recorded during each of the three months ended 2011 or 2010.

As of March 31, 2011, we had a gross liability for uncertain tax benefits of $1.2 million, which was substantially unchanged from December 31, 2010. If recognized, $1.1 million of this liability would affect our effective tax rate. This liability is reflected in other accrued expenses on our accompanying balance sheet. In 2010, the Internal Revenue Service ("IRS") commenced its examination of our 2007, 2008 and 2009 tax years. This examination is expected to be completed during the second quarter of 2011. Therefore, we expect the liability for uncertain tax benefits to decrease significantly during the next twelve-month period as items are either resolved without change, converted to amounts due to the IRS or removed due to the expiration of the statute of limitations.

As of the date of this filing, we are current with our income tax filings in all applicable state jurisdictions and currently have no state income tax returns in the process of examination.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 7 - LONG-TERM DEBT

Long-term debt consists of the following:



	March 31, 2011			December 31, 2010
	(in thousands)
Senior notes
3.25% Convertible senior notes due 2016:
Principal amount	$	115,000		$	115,000
Unamortized discount	(19,310		)	(20,252		)
3.25% Convertible senior notes due 2016, net of discount	95,690			94,748
12% Senior notes due 2018:
Principal amount	203,000			203,000
Unamortized discount	(1,981		)	(2,053		)
12% Senior notes due 2018, net of discount	201,019			200,947
Total senior notes	296,709			295,695
Total long-term debt	$	296,709		$	295,695

Senior Notes

3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million of 3.25% convertible senior notes due 2016 in a private placement. The maturity for the payment of principal is May 15, 2016. Interest at the rate of 3.25% per year is payable in cash semiannually in arrears on each May 15 and November 15, commencing on May 15, 2011. We allocated the gross proceeds of the convertible notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, with similar terms and priced on the same day we issued our convertible notes. The original issue discount and the deferred note issuance costs are being amortized to interest expense over the term of the debt using an effective interest rate of 7.4%. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the $1,000 principal amount of the convertible notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares.

12% Senior Notes Due 2018. In 2008, we issued $203 million of 12% senior notes due 2018 in a private placement. The maturity for the payment of principal is February 15, 2018. Interest at the rate of 12% per year is payable in cash semiannually in arrears on each February 15 and August 15. The senior notes were issued at a discount, 98.572% of the principal amount. The indenture governing the notes contains customary representations and warranties as well as typical restrictive covenants. The original issue discount and the deferred note issuance costs are being amortized to interest expense over the term of the debt using the effective interest method.

We were in compliance with all covenants related to our senior notes as of March 31, 2011, and expect to remain in compliance throughout the next twelve-month period.

Bank Credit Facilities

Subsequent to March 31, 2011, on May 6, 2011, we completed the redetermination of our corporate bank credit facility's borrowing base. Similarly, PDCM completed its redetermination on April 20, 2011. See Note 15 for further discussion.

Corporate Bank Credit Facility. We operate under a credit facility dated as of November 5, 2010, as amended December 22, 2010, with an aggregate revolving commitment or borrowing base of $321.2 million. The maximum allowable facility amount is $600 million. The credit facility is with certain commercial lending institutions and is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit.

Our credit facility borrowing base is subject to size redetermination semiannually based on a valuation of our reserves at December 31 and June 30 and is also subject to a redetermination upon the occurrence of certain events. The borrowing base of the credit facility will be the loan value assigned to the proved reserves attributable to our natural gas and crude oil interests, excluding proved reserves attributable to PDCM and our 29 affiliated partnerships. The credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of our other assets. Neither PDCM nor the various limited partnerships that we have sponsored and continue to serve as the managing general partner are guarantors of the credit facility.

Our outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees,

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015, or in the event that the borrowing base would fall below the outstanding balance. The credit facility contains covenants customary for agreements of this type.

We have outstanding an undrawn $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider. This letter of credit reduces the amount of available funds under our credit facility by an equal amount. We pay a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.0% per annum as of March 31, 2011) for the period the letter of credit remains outstanding. The letter of credit expires on May 22, 2012.

As of March 31, 2011, and December 31, 2010, we had no outstanding draws on our credit facility. We pay a fee of 0.5% per annum on the unutilized commitment on the available funds under our credit facility. As of March 31, 2011, the available funds under our credit facility were $302.5 million. The weighted average borrowing rate on our credit facility, including the letter of credit, was 0.6% per annum for the three months ended 2011 and 1.1% per annum for the three months ended 2010.

PDCM Credit Facility. PDCM has a credit facility dated as of April 30, 2010, with an initial borrowing base of $10 million. The credit facility is subject to and secured by PDCM's properties, including our proportionate share of such properties. The credit facility borrowing base is subject to size redetermination semiannually based upon a valuation of PDCM's reserves at December 31 and June 30; further, either PDCM or the lenders may request a redetermination upon the occurrence of certain events. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Appalachian assets. As of March 31, 2011, there were no amounts outstanding related to this credit facility.

As of March 31, 2011, both the Company and PDCM were in compliance with all bank credit facility covenants and expect to remain in compliance throughout the next twelve-month period.

NOTE 8 - ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in natural gas and crude oil properties.



	Amount
	(in thousands)

Balance at December 31, 2010 (1)	$	28,047
Change in ownership interest of PDCM	(485		)
Obligations incurred with development activites and assumed with acquisitions	450
Accretion expense	396
Obligations discharged with disposal of properties and asset retirements	(221		)
Balance at March 31, 2011	28,187
Less current portion	(250		)
Long-term portion	$	27,937

__________

(1)Includes $0.2 million as of December 31, 2010, related to assets held for sale.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Merger Agreements. In November 2010, pursuant to our previously announced partnership acquisition plan, we entered into separate merger agreements with three of our affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and the Rockies Region Private Limited Partnership (collectively, the "2005 Partnerships"). We serve as the managing general partner of each of the 2005 Partnerships. Definitive proxy statements for each of the 2005 Partnerships requesting approval for the applicable merger were mailed to the non-affiliated investor partners of the 2005 Partnerships on February 7, 2011. Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by limited partners of that partnership not owned by us (the "non-affiliated investor partners"), as well as the satisfaction of other customary closing conditions, then such partnership will merge with and into a wholly-owned subsidiary of ours. In light of the recent rise in commodity prices, in late February 2011, we reevaluated the initial aggregate merger consideration of $36.4 million agreed to in the merger agreements for the 2005 Partnerships and proposed to offer supplemental merger consideration of $6.9 million to the non-affiliated investor partners of the 2005 Partnerships. In early May 2011, we mailed the proxy supplements to the non-affiliated investor partners of the 2005 Partnerships. The special meetings whereby non-affiliated investor partners of the 2005 Partnerships will have an opportunity to vote and approve the applicable merger agreements are currently scheduled for June 15, 2011. If the required approvals are received from the non-affiliated investor partners at the special meetings and various other closing conditions are satisfied, we expect the aggregate purchase price to acquire the 2005 Partnerships to be $43.3 million. We expect to finance the acquisition of the 2005 Partnerships by borrowing funds under our revolving credit facility.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

Drilling Rig Contract. In order to secure the services of a drilling rig, PDCM entered into a commitment with a drilling contractor for the services of a drilling rig. The commitment expires in October 2012. Included in production costs in the statement of operations for the three months ended 2011, we recognized a charge of $0.5 million related to our proportionate share of rig laydown costs. As of March 31, 2011, our proportionate share of PDCM's related maximum commitment through October 2012 was $5.3 million.

Firm Transportation Agreements. We have entered into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell our natural gas and the natural gas of working interest owners, PDCM, our affiliated partnerships and other third parties. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. Satisfaction of the volume requirements include volumes produced by us, volumes purchased from third parties and volumes produced by our joint venture and affiliated partnerships. We record in our financial statements only our share of costs based upon our working interest in the wells; however, the costs of all volume shortfalls will be borne by PDC. As of March 31, 2011, we have a liability in the amount of $3.1 million included in other liabilities on the balance sheet related to an agreement in our Piceance Basin. We are currently working with the gas purchaser to renegotiate the terms and timing of our volume requirements under this agreement. If we are not able to renegotiate this agreement or meet all expected future volumes, we may need to record an additional liability.

The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm sales, processing and transportation agreements for pipeline capacity.



	For the Twelve Months Ending March 31,
Area	2012		2013		2014		2015		2016 Through Expiration		Total		Expiration Date

Volume (MMcf)
Piceance	32,466		32,872		29,399		23,584		65,969		184,290		May 31, 2021
Appalachian Basin (1)	4,587		11,776		15,992		15,992		114,653		163,000		August 31, 2022
NECO	3,200		1,825		1,825		1,825		3,200		11,875		December 31, 2016
Total	40,253		46,473		47,216		41,401		183,822		359,165

Dollar commitment (in thousands)	$	19,801	$	22,941	$	23,343	$	20,290	$	86,878	$	173,253

_____________

(1)

Includes a precedent agreement that becomes effective when a planned pipeline is placed in service, currently expected to be September 2012 and represents 10,629 MMcf of the total MMcf presented for each of the years ending March 31, 2013 and 2014, and 78,915 MMcf thereafter. This agreement will be null and void if the pipeline is not completed. In August 2009, we issued a letter of credit related to this agreement, see Note 7.

Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There are no assurances that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. With the exception of the royalty lawsuit discussed below, and although the results cannot be known with certainty, we believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.

Royalty Owner Class Action

Gobel et al v. Petroleum Development Corporation, Case No. 09-C-40 in U. S. District Court, Northern District of West Virginia, filed on January 27, 2009

David W. Gobel, individually and allegedly as representative of all royalty owners in the Company's West Virginia oil and gas wells, filed a lawsuit against the Company alleging that we failed to properly pay royalties (the "Gobel lawsuit"). The allegations state that the Company improperly deducted certain charges and costs before applying the royalty percentage. Punitive damages are requested in addition to breach of contract, tort and fraud allegations. On August 31, 2010, the federal judge issued an order remanding the case to state court. On October 27, 2010, the state court set a trial date of April 2012.

In April 2011, the Company entered into an oral settlement agreement with respect to this lawsuit. The oral settlement agreement has been approved by the Company's Board of Directors and involves the payment of a total of $8,750,000. The parties are currently drafting definitive documentation to reflect the oral agreement. There can be no assurance that such definitive documentation will be completed on terms satisfactory to the Company. A hearing has been set for June 6, 2011, for the court to consider preliminary approval of the settlement. For the three months ended 2011, the Company recorded a charge to general and administrative expense in the statement of operations of $1.6 million. As of March 31, 2011, the Company had the total oral settlement accrued and included in other accrued expenses on the accompanying balance sheet.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. As of March 31, 2011, and December 31, 2010, we had accrued environmental liabilities in the amount of $1.5 million and $1.7 million, respectively, included in other accrued expenses on the balance sheet. We are not aware of any environmental claims existing as of March 31, 2011, which have not been provided for or would otherwise have a material impact on our accompanying financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties.

Partnership Repurchase Provision. Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of March 31, 2011, the maximum annual repurchase obligation for 2011, based upon the minimum price described above, was approximately $8.5 million. We believe we have adequate liquidity to meet this obligation. For the three months ended 2011, amounts paid for the repurchase of partnership units pursuant to this provision were immaterial.

Employment Agreements with Executive Officers. We have employment agreements with our Chief Executive Officer, Chief Financial Officer and other executive officers. The employment agreements provide for annual base salaries, eligibility for performance bonus compensation and other various benefits, including retirement and severance benefits.

If, within two years following a change of control of the Company ("change in control period"), either the Company terminates the executive officer without cause or the executive officer terminates employment for good reason (what is referred to as a "double trigger"), then the severance benefits owed equals three times the sum of the executive's highest annual base salary during the previous two years of employment immediately preceding the termination date and the executive's highest annual bonus paid or, in the case of two executive officers, paid or payable during the same two-year period. For one executive, in this calculation, the target bonus will be used as the minimum value for the first two years of employment. Where the Company terminates the executive officer without cause or the executive officer terminates employment for good reason outside of the change in control period, the severance benefits range from two times to three times, specific to the executive officer, the benefits noted above. For this purpose, a change of control and good reason correspond to the respective definitions of change of control and good reason under IRC 409A and the supporting Treasury regulations, with some differences. Under any of the above circumstances, the executive officer is also entitled under his employment agreement to (i) vesting of any unvested equity compensation (excluding all long-term incentive shares), (ii) reimbursement for any unpaid expenses, (iii) retirement benefits earned under the current and/or previous agreements, (iv) continued coverage under our medical plan at the Company's cost for the federal COBRA health continuation coverage period and (v) payment of any earned and unpaid bonus amounts. In addition, the executive officer is entitled to receive any benefits that he would have otherwise been entitled to receive under our qualified retirement plan, although those benefits are not increased or accelerated.

In the event that an executive officer is terminated for just cause, we are required to pay the executive officer his base salary through the termination date plus a partial year bonus; incentive, deferred, retirement or other compensation; and to provide any other benefits, which have been earned or become payable as of the termination date.

In the event that an executive officer voluntarily terminates his employment for other than good reason, he is entitled to receive (i) his base salary and bonus, provided, however, that with respect to the bonus, for certain executive officers, there will be no proration of the bonus if such executive leaves prior to the last day of the year and, with respect to the remaining executive officers, there will be no proration of the bonus in the event such executive officer leaves prior to March 31 in the year of his termination, (ii) any incentive, deferred or other compensation which has been earned or has become payable, but which has not yet been paid under the schedule originally contemplated in the agreement under which they were granted, (iii) any unpaid expense reimbursement and (iv) any other payments for benefits earned under the employment agreement or our plans.

In the event of death or disability, the executive is entitled to receive certain benefits. For this purpose, the definition of "disability" corresponds to the definition under IRC 409A and the supporting Treasury regulations. The benefits will (i) in the case of death be paid in a lump sum and be equal to the base salary that would otherwise have been paid for a six-month period following the termination date and (ii) in the case of disability be up to thirteen weeks of ongoing base salary plus a lump sum equal to six months of base salary.

Partnership Casualty Losses. As Managing General Partner of 29 partnerships, we have a potential liability for casualty losses in excess of the partnership assets and insurance. We believe the casualty insurance coverage that we and our subcontractors carry is adequate to meet this potential liability.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 10 - STOCK-BASED COMPENSATION PLANS

The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented.



	Three Months Ended March 31,
	2011			2010
	(in thousands)

Total stock-based compensation expense	$	1,545		$	1,005
Income tax benefit	(587		)	(386		)
Net income (loss) impact	$	958		$	619

Stock Appreciation Rights ("SARs")

The SARs will vest ratably over a three-year period and may be exercised at any point after vesting through March 2021. Pursuant to the terms of the awards, upon exercise, the executives will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.

In March 2011, our Compensation Committee of our Board of Directors (the "Committee") awarded 31,552 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the assumptions presented in the table below. The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future.



	Three Months Ended
	March 31, 2011

Expected term of the award	6 years
Risk-free interest rate	2.5		%
Volatility	60.2		%
Weighted average grant date fair value per share	$	25.22

The following table presents the changes in our SARs for the three months ended 2011.



	Number of Shares Underlying SARs	Grant Date Market Price Per Share		Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)

Outstanding at December 31, 2010	57,282	$	24.44	9.3	$	—
Awarded	31,552	43.95		10.0	—
Outstanding at March 31, 2011	88,834	31.37		9.4	1,478
Vested and expected to vest at March 31, 2011	79,951	31.37		9.4	1,330
Exercisable at March 31, 2011	—	—		—	—

The total compensation cost related to SARs granted and not yet recognized in our statement of operations as of March 31, 2011, was $1.2 million. The cost is expected to be recognized over a weighted average period of two years.

Restricted Stock Awards

Time-Based Awards. The following table presents the changes in non-vested time-based awards for the three months ended 2011. In March 2011, the Committee awarded a total of 43,256 time-based restricted shares to our executive officers that vest ratably over a three-year period ending on March 12, 2014.

The total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our statements of operations as of March 31, 2011, was $9.9 million. This cost is expected to be recognized over a weighted average period of 2.4 years.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued



	Shares		Weighted Average Grant-Date Fair Value per Share

Non-vested at December 31, 2010	525,715		$	25.53
Granted	48,173		43.95
Vested	(30,137	)	29.26
Forfeited	(9,707	)	23.39
Non-vested at March 31, 2011	534,044		27.02



	As of/Three Months Ended
	March 31, 2011
	(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	1,400
Total intrinsic value of time-based awards non-vested	25,639
Market price per common share as of March 31	48.01

Market-Based Awards. The fair value of the market-based awards is amortized ratably over the requisite service period, primarily three years. Generally, the market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.

In March 2011, the Committee awarded a total of 13,531 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 11 peers. The shares are measured over a three-year period ending on December 31, 2013, and can result in a payout between zero and 200% of the total shares awarded. The weighted average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the weighted average assumptions presented in the table below.



	Three Months Ended
	March 31, 2011

Expected term of award	3 years
Risk-free interest rate	1.1		%
Volatility	74.2		%
Weighted average grant date fair value per share	$	58.53

Expected volatility was based on a blend of our historical and implied volatility. The expected lives of the awards were based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant or modification and extrapolated to approximate the life of the award. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future.

The following table presents the change in non-vested market-based awards for the three months ended 2011.



	Shares	Weighted Average Grant-Date Fair Value per Share

Non-vested at December 31, 2010	79,550	$	32.52
Granted	13,531	58.53
Non-vested at March 31, 2011	93,081	36.30

The total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our statement of operations as of March 31, 2011 was $0.8 million. This cost is expected to be recognized over a weighted average period of 2.7 years.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 11 - EARNINGS PER SHARE

The following is a reconciliation of weighted average diluted shares outstanding.



	Three Months Ended March 31,
	2011	2010
	(in thousands)

Weighted average common shares outstanding - basic	23,428	19,191
Dilutive effect of share-based compensation:
Restricted stock	—	88
Non employee director deferred compensation	—	8
Weighted average common and common share equivalents outstanding - diluted	23,428	19,287

The following table sets forth the weighted average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect.



	Three Months Ended March 31,
	2011	2010
	(in thousands)

Weighted average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	603	146
Stock options	10	10
SARs	64	—
Convertible debt	161	—
Non employee director deferred compensation	3	—
Total anti-dilutive common share equivalents	841	156

NOTE 12 - DIVESTITURES AND DISCONTINUED OPERATIONS

North Dakota. During the fourth quarter of 2010, we developed a plan to divest our North Dakota assets. The plan included 100% of our North Dakota assets, consisting of producing wells, undeveloped leaseholds and related facilities primarily located in Burke County. The plan received board approval and, in December 2010, we effected a letter of intent with an unrelated third party. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the North Dakota assets were reclassified as held for sale as of December 31, 2010, and the results of operations related to those assets have been separately reported as discontinued operations in the accompanying financial statements for both periods presented. In February 2011, we executed a purchase and sale agreement and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of affiliated partnerships' proceeds of $3.8 million, resulting in a pretax gain on sale of $3.9 million.

Selected financial information related to divested and discontinued operations. The table below presents selected operational information related to discontinued operations. While the reclassification of revenues and expenses related to discontinued operations for prior period had no impact upon previously reported net earnings, the statement of operations and operational data present the revenues, expenses and production volumes that were reclassified from the specified statement of operations line items to discontinued operations.

The following table presents statement of operations data related to our discontinued operations. The three months ended 2010 includes operations data related to the July 2010 divestiture of our Michigan assets.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued



	Three Months Ended March 31,
Statement of Operations - Discontinued Operations	2011			2010
	(dollars in thousands)
Revenues
Natural gas, NGL and crude oil sales	$	447		$	2,541
Sales from natural gas marketing	—			1,624
Well operations, pipeline income and other	10			256
Total revenues	457			4,421

Costs, expenses and other
Production costs	132			715
Cost of natural gas marketing	—			1,531
Depreciation, depletion and amortization	—			931
Gain on sale of leaseholds	(3,854		)	—
Total costs, expenses and other	(3,722		)	3,177

Income from discontinued operations	4,179			1,244
Provision for income taxes	1,559			447
Income from discontinued operations, net of tax	$	2,620		$	797

Operational Data

Production
Natural gas (MMcf)	8.7			368.5
Crude oil (MBbls)	3.8			12.0
Natural gas equivalent (MMcfe)	31.5			440.4

NOTE 13 - TRANSACTIONS WITH AFFILIATES

Amounts due from/to the affiliated partnerships are primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. We enter into derivative instruments for our own production as well as for our 29 affiliated partnerships' production. As of March 31, 2011, we had a payable to affiliates of $18.8 million representing their designated portion of the fair value of our gross derivative assets and a receivable from affiliates of $14.7 million representing their designated portion of the fair value of our gross derivative liabilities.

Our natural gas marketing segment manages the marketing of natural gas for PDCM and our affiliated partnerships with production in the Appalachian Basin. Our sales from natural gas marketing include $2.1 million and $1.1 million for the three months ended 2011 and 2010, respectively, related to the marketing of natural gas on behalf of PDCM and our affiliated partnerships. Our cost of natural gas marketing includes $2 million and $1.1 million for the three months ended 2011 and 2010, respectively, related to these sales.

We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $2.7 million in the three months ended 2011. Our statements of operations include only our proportionate share of these billings: $0.9 million, $0.1 million and $0.4 million are reflected in production costs, exploration expense and general and administrative expense, respectively.

We provide well operations and pipeline services to our affiliated partnerships. The majority of our revenue and expenses related to well operations and pipeline income are associated with services provided to our affiliated partnerships.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 14 - BUSINESS SEGMENTS

We separate our operating activities into two segments: natural gas and crude oil sales and natural gas marketing. All material inter-company accounts and transactions between segments have been eliminated.

The following tables present our segment information.



	Three Months Ended March 31,
	2011			2010
	(in thousands)
Revenues:
Natural gas and crude oil sales	$	41,873		$	103,635
Natural gas marketing	15,202			22,687
Unallocated	—			3
Total	$	57,075		$	126,325

Segment income (loss) before income taxes:
Natural gas and crude oil sales	$	(12,910	)	$	55,654
Natural gas marketing	209			357
Unallocated	(23,690		)	(19,335		)
Total	$	(36,391	)	$	36,676

	March 31, 2011			December 31, 2010
	(in thousands)
Segment assets:
Natural gas and crude oil sales	$	1,313,163		$	1,313,805
Natural gas marketing	15,170			16,338
Unallocated	60,014			53,701
Assets held for sale	—			5,191
Total	$	1,388,347		$	1,389,035

NOTE 15 - SUBSEQUENT EVENTS

On May 6, 2011, the biannual redetermination of our corporate bank credit facility's borrowing base, which was based upon our natural gas and crude oil reserves as of December 31, 2010, was completed. Based on the redetermination, our aggregate revolving commitment was increased to $350 million from $321.2 million. There were no other changes to our corporate bank credit facility as a result of the redetermination.

On April 20, 2011, PDCM entered into the first amendment to its credit agreement dated April 30, 2010. Pursuant to the amendment, its borrowing base was increased to $40 million from $10 million based on its December 31, 2010, reserves. In addition to the increase in borrowing base, the first amendment permits PDCM to enter into swap agreements on new properties which were not included in the most recent reserve report and which have been producing for at least 30 days.

See Note 9, Commitments and Contingencies - Litigation, for a discussion of the oral settlement agreement reached with regard to our West Virginia royalty lawsuit.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Operational Overview

During the three months ended 2011, we continued to execute our strategy to focus capital spending on our liquid-rich properties. We drilled 44 operated wells and participated in 11 non-operated drilling projects, of which 17 were completed and turned in line. We also executed 59 refrac/recompletion projects on 31 wells in the Wattenberg Field. Of the 44 wells drilled, three were horizontal Niobrara in the Wattenberg Field and six were in the recently acquired Permian Basin, all of which were in-process as of March 31, 2011. Our focus in the more liquid-rich areas will maximize drilling returns, given the recent surge in crude oil prices, as we pursue our targeted natural gas/crude oil production mix ratio of 65/35.

Our joint venture, PDCM, completed three additional successful Marcellus wells and now have a total of six horizontal wells producing. Our drilled wells continue to define the optimum area for our Marcellus development.

Financial Overview

Production from continuing operations for the three months ended 2011 increased by 20.4% compared to the three months ended 2010. Sales revenues increased $6.1 million or 10.5% due to our increased production, which was offset in part by the decrease in our average natural gas price per Mcf of $1.63 or 34.6%.

During the three months ended 2011, as we began to execute our 2011 capital spending plan, we drew down our December 31, 2010, cash balance, resulting in an available liquidity of $317.2 million as of March 31, 2011, compared to $356.9 million as of December 31, 2010. The excess cash balance as of December 31, 2010, was attributable to our double tranche offering of common equity and convertible debt in November 2010. Available liquidity is comprised of cash, cash equivalents and funds available under our credit facility. With our strong liquidity position, we anticipate that 2011 will be a year of increased capital spending, focused on organic growth in the liquid-rich areas of our Wattenberg Field and the Permian Basin along with the proposed acquisitions of our affiliated partnerships. We believe that our 2011 capital budget, excluding acquisitions, combined with our investment in 2010, will grow our production from continuing operations by 19% in 2011, while increasing the liquids portion of our production as a percentage of our total production and thereby enabling us to benefit from the crude oil to natural gas price differential.

On May 6, 2011, we completed the redetermination of our corporate bank credit facility's borrowing base, resulting in an increase in our March 31, 2011, available liquidity by $28.8 million. Similarly, PDCM completed its redetermination on April 20, 2011, resulting in an increase its March 31, 2011, available liquidity by $30 million. See Note 15, Subsequent Events, to the accompanying condensed consolidated financial statements.

Non-U.S. GAAP Financial Measures

We use "adjusted cash flow from operations," "adjusted net income (loss) attributable to shareholders" and "adjusted EBITDA," non-U.S. GAAP financial measures, for internal managerial purposes, when evaluating period-to-period comparisons and providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income, cash flows from operations, investing or financing activities, nor as a liquidity measure or indicator of operating results or cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-U.S. GAAP Financial Measures below for a detailed description of these measures as well as a reconciliation of each to the nearest U.S. GAAP measure.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results from continuing operations.



	Three Months Ended March 31,
	2011			2010		Change
	(dollars in thousands, except per unit data)
Production (1)
Natural gas (MMcf)	7,747.3			6,513.4		18.9	%
Crude oil (MBbls)	371.3			284.8		30.4	%
NGLs (MBbls)	166.9			149.1		11.9	%
Natural gas equivalent (MMcfe) (2)	10,976.6			9,116.4		20.4	%
Average MMcfe per day	122.0			101.3		20.4	%
Natural Gas, NGL and Crude Oil Sales
Natural gas	$	23,855		$	30,647	(22.2	)%
Crude oil	32,517			20,951		55.2	%
NGLs	7,507			6,229		20.5	%
Total natural gas, NGL and crude oil sales	$	63,879		$	57,827	10.5	%

Realized Gain (Loss) on Derivatives, net (3)
Natural gas	$	6,899		$	20,879	(67.0	)%
Crude oil	(3,111		)	2,045		(252.1	)%
Total realized gain on derivatives, net	$	3,788		$	22,924	(83.5	)%

Average Sales Price (excluding gain/loss on derivatives)
Natural gas (per Mcf)	$	3.08		$	4.71	(34.6	)%
Crude oil (per Bbl)	87.56			73.57		19.0	%
NGLs (per Bbl)	44.99			41.80		7.6	%
Natural gas equivalent (per Mcfe)	5.82			6.34		(8.2	)%

Average Sales Price (including gain/loss on derivatives)
Natural gas (per Mcf)	$	3.97		$	7.91	(49.8	)%
Crude oil (per Bbl)	79.20			80.74		(1.9	)%
NGLs (per Bbl)	44.99			41.80		7.6	%
Natural gas equivalent (per Mcfe)	6.16			8.86		(30.5	)%

Average Lifting Cost (per Mcfe) (4)	$	1.17		$	0.97	20.6	%

Natural Gas Marketing (5)	$	209		$	364	(42.6	)%

Other Costs and Expenses
Exploration expense	$	2,151		$	6,418	(66.5	)%
General and administrative expense	13,873			10,694		29.7	%
Depreciation, depletion and amortization	32,357			27,458		17.8	%

Interest Expense, net	$	9,053		$	7,795	16.1	%

Amounts may not recalculate due to rounding.

______________


(1)	Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage interest we own.


(2)	Six Mcf of natural gas equals one Bbl of crude oil or NGL.


(3)	Represents realized derivative gains and losses related to natural gas and crude oil sales segment, which do not include realized derivative gains and losses related to natural gas marketing.


(4)	Represents lease operating expenses on a per unit basis.


(5)	Represents sales from natural gas marketing, net of costs of natural gas marketing, including realized and unrealized derivative gains and losses related to natural gas marketing activities.

PETROLEUM DEVELOPMENT CORPORATION

(dba PDC Energy)

Natural Gas, NGL and Crude Oil Sales

The following tables present natural gas, NGL and crude oil production and average sales price by area.



	Three Months Ended March 31,
	2011	2010	Percentage Change
Production
Natural gas (MMcf)
Rocky Mountain Region (1)	6,787.5	5,873.2	15.6	%
Permian Basin (2)	81.1	—	*
Appalachian Basin	866.9	630.5	37.5	%
Other	11.8	9.7	21.6	%
Total	7,747.3	6,513.4	18.9	%
Crude oil (MBbls)
Rocky Mountain Region	320.0	284.1	12.6	%
Permian Basin (2)	50.1	—	*
Appalachian Basin	1.1	0.7	57.1	%
Other	0.1	—	*
Total	371.3	284.8	30.4	%
NGLs (MBbls)