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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, 2013

or

£ 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

PDC ENERGY, INC.

(Exact name of registrant as specified in its charter)

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 Website, 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 T 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  x	Accelerated filer  o
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: 30,341,302 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 19, 2013.

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PDC ENERGY, INC.

TABLE OF CONTENTS

	PART I - FINANCIAL INFORMATION		Page
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets (unaudited)		1
	Condensed Consolidated Statements of Operations (unaudited)		2
	Condensed Consolidated Statements of Cash Flows (unaudited)		3
	Notes to Condensed Consolidated Financial Statements		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		32
Item 4.	Controls and Procedures		35
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		35
Item 1A.	Risk Factors		35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		35
Item 3.	Defaults Upon Senior Securities		35
Item 4.	Mine Safety Disclosures		35
Item 5.	Other Information		35
Item 6.	Exhibits		36
	SIGNATURES		37

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q 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 ("U.S.") 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. These statements relate to, among other things: estimated natural gas, natural gas liquids (“NGLs”) and crude oil reserves; future production (including the components of such production), expenses, cash flows and liquidity; anticipated capital projects, expenditures and opportunities; future exploration and development activities; availability of additional midstream facilities and services, the timing of that availability and related benefits to us; availability of sufficient funding for our capital program and sources of that funding; our and PDC Mountaineer, LLC's ("PDCM") compliance with debt covenants, the borrowing base under our credit facility and the renewal of a letter of credit under that facility; the future effect of contracts, policies and procedures we believe to be customary; effectiveness of our derivative program in providing a degree of price stability; closing of, and expected proceeds from, our pending asset disposition; and our future strategies, plans and objectives.

The above statements 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, including economic conditions that might impact demand;

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

•	the impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;

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

•	changes in estimates of proved reserves;

•	inaccuracy of reserve estimates and expected production rates;

•	potential for production decline rates from our wells to be greater than expected;

•	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;

•	timing and receipt of necessary regulatory permits;

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

•	our future cash flows, liquidity and financial condition;

•	competition in the oil and gas industry;

•	availability and cost of capital to us;

•	reductions in the borrowing base under our revolving credit facility;

•	availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production, particularly in the Wattenberg Field, and the impact of these facilities on the prices we receive for our production;

•	our success in marketing natural gas, NGLs and crude oil;

•	effect of natural gas and crude oil derivatives activities;

•	impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;

•	cost of pending or future litigation;

•	effect that acquisitions we may pursue have on our capital expenditures;

•	potential obstacles to completing our pending asset disposition or other transactions, in a timely manner or at all, and purchase price or other adjustments relating to those transactions that may be unfavorable to us;

•	our ability to retain or attract senior management and key technical employees; and

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

 

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2012 ("2012 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 27, 2013, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, 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.

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REFERENCES

Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our," "ours" or "ourselves" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDCM, a joint venture currently owned 50% each by PDC and Lime Rock Partners, LP, formed for the purpose of exploring and developing the Marcellus Shale formation in the Appalachian Basin. Unless the context otherwise requires, references in this report to "Appalachian Basin" includes PDC's proportionate share of our affiliated partnerships' and PDCM's assets, results of operations, cash flows and operating activities. See Note 1, Nature of Operations and Basis of Presentation, to our condensed consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries.

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PDC ENERGY, INC.

Condensed Consolidated Balance Sheets

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

		March 31, 2013				December 31, 2012 (1)
Assets
Current assets:
Cash and cash equivalents		$	2,494			$	2,457
Restricted cash		3,948				3,942
Accounts receivable, net		65,822				64,880
Accounts receivable affiliates		5,087				4,842
Fair value of derivatives		29,850				52,042
Deferred income taxes		37,573				36,151
Prepaid expenses and other current assets		7,885				7,635
Total current assets		152,659				171,949
Properties and equipment, net		1,375,473				1,616,706
Assets held for sale		216,802				—
Fair value of derivatives		5,181				6,883
Other assets		31,698				31,310
Total Assets		$	1,781,813			$	1,826,848
Liabilities and Shareholders' Equity
Liabilities
Current liabilities:
Accounts payable		$	70,471			$	82,716
Accounts payable affiliates		3,394				5,296
Production tax liability		26,709				25,899
Fair value of derivatives		23,564				18,439
Funds held for distribution		32,406				34,228
Accrued interest payable		21,688				11,056
Other accrued expenses		16,521				25,715
Total current liabilities		194,753				203,349
Long-term debt		687,970				676,579
Deferred income taxes		128,699				148,427
Asset retirement obligation		34,296				61,563
Fair value of derivatives		13,046				10,137
Liabilities held for sale		28,346				—
Other liabilities		28,798				23,612
Total liabilities		1,115,908				1,123,667
Commitments and contingent liabilities
Shareholders' equity
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued		—				—
Common shares - par value $0.01 per share, 100,000,000 authorized, 30,337,524 and 30,294,224 issued as of March 31, 2013 and December 31, 2012, respectively		303				303
Additional paid-in capital		389,831				387,494
Retained earnings		276,150				315,568
Treasury shares - at cost, 8,788 and 5,059 as of March 31, 2013 and December 31, 2012, respectively		(379		)		(184		)
Total shareholders' equity		665,905				703,181
Total Liabilities and Shareholders' Equity		$	1,781,813			$	1,826,848

__________

(1) Derived from our audited 2012 balance sheet.

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Operations

(unaudited; in thousands, except per share data)

		Three Months Ended March 31,
		2013				2012
Revenues:
Natural gas, NGLs and crude oil sales		$	79,439			$	66,955
Sales from natural gas marketing		13,670				11,381
Commodity price risk management gain (loss), net		(22,355		)		11,501
Well operations, pipeline income and other		1,072				1,169
Total revenues		71,826				91,006
Costs, expenses and other:
Production costs		15,858				12,936
Cost of natural gas marketing		13,736				11,091
Exploration expense		1,689				1,872
Impairment of natural gas and crude oil properties		46,459				588
General and administrative expense		15,115				14,708
Depreciation, depletion, and amortization		27,949				27,912
Accretion of asset retirement obligations		1,148				727
Gain on sale of properties and equipment		(38		)		(154		)
Total cost, expenses and other		121,916				69,680
Income (loss) from operations		(50,090		)		21,326
Interest expense		(13,357		)		(10,444		)
Interest income		—				2
Income (loss) from continuing operations before income taxes		(63,447		)		10,884
Provision for income taxes		22,492				(4,120		)
Income (loss) from continuing operations		(40,955		)		6,764
Income from discontinued operations, net of tax		1,537				9,071
Net income (loss)		$	(39,418	)		$	15,835
Earnings per share:
Basic
Income (loss) from continuing operations		$	(1.35	)		$	0.29
Income from discontinued operations		0.05				0.38
Net income (loss)		$	(1.30	)		$	0.67
Diluted
Income (loss) from continuing operations		$	(1.35	)		$	0.28
Income from discontinued operations		0.05				0.38
Net income (loss)		$	(1.30	)		$	0.66
Weighted-average common shares outstanding:
Basic		30,270				23,609
Diluted		30,270				23,889

 

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(unaudited; in thousands)

		Three Months Ended March 31,
		2013				2012
Cash flows from operating activities:
Net income (loss)		$	(39,418	)		$	15,835
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Unrealized (gain) loss on derivatives, net		30,721				(1,533		)
Depreciation, depletion and amortization		30,207				39,814
Impairment of natural gas and crude oil properties		46,462				653
Accretion of asset retirement obligation		1,245				819
Stock-based compensation		2,602				1,946
Excess tax benefits from stock-based compensation		(242		)		(120		)
Gain on sale of properties and equipment		(38		)		(20,489		)
Amortization of debt discount and issuance costs		1,752				1,641
Deferred income taxes		(21,150		)		10,914
Other		206				230
Changes in assets and liabilities		(8,085		)		(5,411		)
Net cash from operating activities		44,262				44,299
Cash flows from investing activities:
Capital expenditures		(61,873		)		(107,029		)
Acquisition of oil and gas properties		—				(10,000		)
Proceeds from acquisition adjustments		7,579				—
Proceeds from sale of properties and equipment		38				184,646
Net cash from investing activities		(54,256		)		67,617
Cash flows from financing activities:
Proceeds from revolving credit facility		95,500				144,750
Payment of revolving credit facility		(85,000		)		(263,000		)
Payment of debt issuance costs		(14		)		—
Excess tax benefits from stock-based compensation		242				120
Purchase of treasury shares		(697		)		(369		)
Net cash from financing activities		10,031				(118,499		)
Net change in cash and cash equivalents		37				(6,583		)
Cash and cash equivalents, beginning of period		2,457				8,238
Cash and cash equivalents, end of period		$	2,494			$	1,655
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest		$	1,196			$	14,975
Income taxes		2				(1,100		)
Non-cash investing activities:
Change in accounts payable related to purchases of properties and equipment		$	8,413			$	(21,044	)
Change in asset retirement obligation, with a corresponding change to natural gas and crude oil properties, net of disposals		98				(1,962		)

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2013

(Unaudited)

NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy, Inc. ("PDC," "PDC Energy," "we," "us" or "the Company") is a domestic independent crude oil, NGL and natural gas company engaged in the exploration for and the acquisition, development, production and marketing of crude oil, NGLs and natural gas . PDC is focused operationally on the liquid-rich Wattenberg Field in the DJ Basin and, in the Appalachian Basin, on the liquid-rich Utica Shale and the dry-gas Marcellus Shale. As of March 31, 2013, we owned an interest in approximately 7,300 gross wells located primarily in the Wattenberg Field, Appalachian Basin, Northeast Colorado ("NECO") and Piceance Basin. We are engaged in two business segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries, and our proportionate share of PDC Mountaineer, LLC ("PDCM") and our 21 affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated 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.

In our opinion, the accompanying condensed consolidated 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 2012 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 2013 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 mainly attributable to reporting as discontinued operations the results of operations related to the planned sale of our Piceance Basin and NECO oil and gas properties. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned divestiture. We also reclassified prepaid well cost write-offs out of the statement of cash flows line item changes in assets and liabilities and into other. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recently Adopted Accounting Standards.

On January 1, 2013, we adopted changes issued by the Financial Accounting Standards Board regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on an entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Our adoption of these changes had no impact on the condensed consolidated financial statements.

NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant.

Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our natural gas and crude oil collars, natural gas calls and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:

	March 31, 2013												December 31, 2012
	Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
	(in thousands)
Assets:
Commodity-based derivative contracts	$	24,588			$	9,604			$	34,192			$	42,788			$	15,734			$	58,522
Basis protection derivative contracts	828				11				839				387				16				403
Total assets	25,416				9,615				35,031				43,175				15,750				58,925
Liabilities:
Commodity-based derivative contracts	22,531				1,952				24,483				9,839				2,081				11,920
Basis protection derivative contracts	12,127				—				12,127				16,656				—				16,656
Total liabilities	34,658				1,952				36,610				26,495				2,081				28,576
Net asset (liability)	$	(9,242	)		$	7,663			$	(1,579	)		$	16,680			$	13,669			$	30,349

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents a reconciliation of our Level 3 assets measured at fair value:

		Three Months Ended March 31,
		2013				2012
		(in thousands)
Fair value, net asset, beginning of period		$	13,669			$	22,107
Changes in fair value included in statement of operations line item:
Commodity price risk management gain, net		(2,731		)		1,416
Sales from natural gas marketing		(16		)		43
Changes in fair value included in balance sheet line item:
Accounts payable affiliates (1)		—				(52		)
Settlements included in statement of operations line items:
Commodity price risk management loss, net		(3,234		)		(3,797		)
Sales from natural gas marketing		(25		)		(73		)
Fair value, net asset end of period		$	7,663			$	19,644
Changes in unrealized gains (losses) relating to assets (liabilities) still held
as of year-end, included in statement of operations line item:
Commodity price risk management gain, net		$	(2,739	)		$	1,282
Sales from natural gas marketing		(16		)		3
Total		$	(2,755	)		$	1,285

__________

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

The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts.

    

Non-Derivative Financial Assets and Liabilities

The carrying values of the financial instruments included in 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 revolving credit facility, as well as our proportionate share of PDCM's credit facility, approximates fair value due to the variable nature of related interest rates. 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, 2013, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2016 to be $157.3 million, or 136.7% of par value, and the portion related to our 7.75% senior notes due 2022 to be $536.5 million, or 107.3% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs.

NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS

Our results of operations and operating cash flows are affected by changes in market prices for natural gas, NGLs and crude oil. To manage a portion of our exposure to price volatility from producing natural gas and crude oil, we utilize the following economic hedging strategies for each of our business segments.

•	For natural gas and crude oil sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market.

 

•	For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.

We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of March 31, 2013, we had derivative instruments, which were comprised of commodity floors, collars and swaps, basis protection swaps and physical sales and purchases, in place for a portion of our anticipated production through 2016 for a total of 72,674 BBtu of natural gas and 5,568 MBbls of crude oil.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

We have elected not to designate any of our derivative instruments as hedges and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations, with the exception of changes in fair value related to those derivatives we designated to our affiliated partnerships. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the balance sheets in accounts payable affiliates and accounts receivable affiliates. As positions designated to our affiliated partnerships settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk.

All of our derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets. Pursuant to the master netting provisions contained in our derivative agreements, the fair value of our derivatives instruments was a net liability of $1.6 million as of March 31, 2013 and a net asset of $30.3 million as of December 31, 2012.

The following table presents the location and fair value amounts of our derivative instruments on the balance sheets as of March 31, 2013 and December 31, 2012:

					Fair Value
Derivatives instruments:			Balance sheet line item		March 31, 2013				December 31, 2012
					(in thousands)
Derivative assets:	Current
	Commodity contracts
	Related to natural gas and crude oil sales		Fair value of derivatives		$	25,526			$	47,016
	Related to affiliated partnerships (1)		Fair value of derivatives		2,936				4,707
	Related to natural gas marketing		Fair value of derivatives		877				302
	Basis protection contracts
	Related to natural gas and crude oil sales		Fair value of derivatives		493				—
	Related to natural gas marketing		Fair value of derivatives		18				17
					29,850				52,042
	Non Current
	Commodity contracts
	Related to natural gas and crude oil sales		Fair value of derivatives		4,532				6,671
	Related to natural gas marketing		Fair value of derivatives		321				203
	Basis protection contracts
	Related to natural gas and crude oil sales		Fair value of derivatives		325				—
	Related to natural gas marketing		Fair value of derivatives		3				9
					5,181				6,883
Total derivative assets					$	35,031			$	58,925
Derivative liabilities:	Current
	Commodity contracts
	Related to natural gas and crude oil sales		Fair value of derivatives		$	10,707			$	1,744
	Related to natural gas marketing		Fair value of derivatives		730				226
	Basis protection contracts
	Related to natural gas and crude oil sales		Fair value of derivatives		10,552				14,329
	Related to affiliated partnerships (2)		Fair value of derivatives		1,575				2,140
					23,564				18,439
	Non Current
	Commodity contracts
	Related to natural gas and crude oil sales		Fair value of derivatives		12,803				9,969
	Related to natural gas marketing		Fair value of derivatives		243				168
					13,046				10,137
Total derivative liabilities					$	36,610			$	28,576

__________

(1)	Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets.

(2)	Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities.

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PDC ENERGY, INC.

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,
		2013												2012
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		$	9,045			$	(571	)		$	8,474			$	8,628			$	1,299			$	9,927
Unrealized gains (losses)		(9,045		)		(21,784		)		(30,829		)		(8,628		)		10,202				1,574
Total commodity price risk management gain (loss), net		$	—			$	(22,355	)		$	(22,355	)		$	—			$	11,501			$	11,501
Sales from natural gas marketing
Realized gains		$	194			$	7			$	201			$	684			$	109			$	793
Unrealized gains (losses)		(194		)		(774		)		(968		)		(684		)		759				75
Total sales from natural gas marketing		$	—			$	(767	)		$	(767	)		$	—			$	868			$	868
Cost of natural gas marketing
Realized losses		$	(156	)		$	(6	)		$	(162	)		$	(591	)		$	(154	)		$	(745	)
Unrealized gains (losses)		156				920				1,076				591				(707		)		(116		)
Total cost of natural gas marketing		$	—			$	914			$	914			$	—			$	(861	)		$	(861	)

Derivative Counterparties. Our derivative arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility 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, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments was not significant.

The following table presents the counterparties that expose us to credit risk as of March 31, 2013 with regard to our derivative assets:

Counterparty Name		Fair Value of Derivative Assets As of March 31, 2013
		(in thousands)
JPMorgan Chase Bank, N.A. (1)		$	23,774
Bank of Nova Scotia (1)		2,237
Wells Fargo Bank, N.A. (1)		2,249
Other lenders in our revolving credit facility		5,479
Various (2)		1,292
Total		$	35,031

__________

(1)Major lender in our revolving credit facility. See Note 7, Long-Term Debt.

(2)Represents a total of 28 counterparties.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 5 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization:

	March 31, 2013				December 31, 2012
	(in thousands)
Properties and equipment, net:
Natural gas and crude oil properties
Proved	$	1,399,879			$	2,075,924
Unproved	317,672				319,327
Total natural gas and crude oil properties	1,717,551				2,395,251
Pipelines and related facilities	14,995				47,786
Transportation and other equipment	27,518				34,858
Land and buildings	12,832				14,935
Construction in progress	55,325				67,217
Gross properties and equipment	1,828,221				2,560,047
Accumulated depreciation, depletion and amortization	(452,748		)		(943,341		)
Properties and equipment, net	$	1,375,473			$	1,616,706

The following table presents impairment charges recorded for natural gas and crude oil properties:

	Three Months Ended
	2013				2012
	(in thousands)
Continuing operations:
Impairment of proved properties	$	45,000			$	—
Impairment of individually significant unproved properties	154				154
Amortization of individually insignificant unproved properties	1,305				434
Total continuing operations	46,459				588
Discontinued operations:
Amortization of individually insignificant unproved properties	3				65
Total discontinued operations	3				65
Total impairment of natural gas and crude oil properties	$	46,462			$	653

During the three months ended March 31, 2013, we recognized an impairment charge of approximately $45 million related to all of our shallow upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania owned directly by us, as well as through our proportionate share of PDCM and our affiliated partnerships. The assets were determined to be impaired when the assets became held for sale in the first quarter of 2013 as the estimated fair value, less cost to sell, was less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based upon estimated future cash flows from an unrelated third-party bid, a Level 3 input. The impairment charge was included in the statement of operations line item impairment of natural gas and crude oil properties. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties. It is not certain that these properties will be sold.

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 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 expense 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 rates for continuing operations for the three months ended March 31, 2013 was a 35.5% benefit on loss compared to a 37.9% expense on income for the three months ended March 31, 2012. The effective tax rates for the three month periods ended March 31, 2013 and March 31, 2012 approximate the federal statutory rate of 35.0%, plus our effective blended state tax rate of approximately 3.0%. For the three months ended March 31, 2012, our permanent deductions, largely percentage depletion, were offset by nondeductible items, primarily officers' compensation. For the three months ended March 31, 2013, the nondeductible item for officers' compensation exceeded our deduction

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

for percentage depletion, thereby reducing our tax benefit rate. Additionally, state statutory limits on the utilization of our net operating losses resulted in a reduced state tax benefit. There were no significant discrete items recorded during the three months ended March 31, 2013 or 2012.

As of March 31, 2013, we had a gross liability for unrecognized tax benefits of $0.2 million, unchanged from the amount recorded at December 31, 2012. If recognized, this liability would affect our effective tax rate. This liability is reflected in other accrued expenses on our accompanying balance sheets. We expect our remaining liability for uncertain tax positions to decrease in the next twelve months due to the expiration of 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.

NOTE 7 - LONG-TERM DEBT

Long-term debt consists of the following:

	March 31, 2013				December 31, 2012
	(in thousands)
Senior notes:
3.25% Convertible senior notes due 2016:
Principal amount	$	115,000			$	115,000
Unamortized discount	(12,780		)		(13,671		)
3.25% Convertible senior notes due 2016, net of discount	102,220				101,329
7.75% Senior notes due 2022	500,000				500,000
Total senior notes	602,220				601,329
Credit facilities:
Corporate	57,000				49,000
PDCM	28,750				26,250
Total credit facilities	85,750				75,250
Total long-term debt	$	687,970			$	676,579

    

Senior Notes

3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million aggregate principal amount 3.25% convertible senior notes due May 15, 2016 (the "2016 Convertible Senior Notes") in a private placement to qualified institutional investors. Interest on the 2016 Convertible Senior Notes is payable semi-annually in arrears on each May 15 and November 15. We allocated the gross proceeds of the convertible senior notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based upon the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued our convertible senior notes. The original issue discount and capitalized debt issuance costs are being amortized to interest expense over the life of the notes using an effective interest rate of 7.4%.

Upon conversion, the convertible senior notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the 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.

7.75% Senior Notes Due 2022. In October 2012, we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”) in a private placement to qualified institutional investors. Interest on the 2022 Senior Notes is payable semi-annually in arrears on each April 15 and October 15. The indenture governing the notes contains customary restrictive covenants. Capitalized debt issuance costs are being amortized as interest expense over the life of the notes using the effective interest method.

As of March 31, 2013, we were in compliance with all covenants related to the 2016 Convertible Senior Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the next twelve-month period.

    

Credit Facilities

Revolving Credit Facility. In November 2010, we obtained a revolving credit facility pursuant to a Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The maximum facility amount is $600 million. As of March 31, 2013, the borrowing base on the revolving credit facility was $450 million and we had $57 million outstanding at a weighted-average interest rate of 2.72%, compared to $49 million at a weighted-average interest rate of 2.31%

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

as of December 31, 2012. The borrowing base of the revolving credit facility is the loan value assigned to the proved reserves attributable to our and our subsidiaries' natural gas and crude oil interests, excluding proved reserves attributable to PDCM and our 21 affiliated partnerships. Our revolving credit facility borrowing base is subject to a semiannual size redetermination based on quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The borrowing base redetermination based on our December 31, 2012 proved reserves is currently under review. The revolving 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 and such subsidiaries' 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 revolving 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, 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 revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and maintaining certain financial ratios on a quarterly basis. The financial tests and ratios, as defined per the revolving credit facility, include requirements to maintain a minimum current ratio of 1.00 to 1.00 and not exceed a maximum leverage ratio of 4.00 to 1.00.

  

As of March 31, 2013 we had an $18.7 million irrevocable standby letter of credit outstanding in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by us and others for whom we market production in West Virginia. The letter of credit reduces the amount of available funds under our revolving 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, 2013) for the period in which the letter of credit remains outstanding. The letter of credit expires on July 20, 2013. We expect to renew the letter of credit prior to its expiration.

We pay a fee of 0.5% per annum on the unutilized commitment on the available funds under our revolving credit facility. As of March 31, 2013, the available funds under our revolving credit facility, including a reduction for the $18.7 million irrevocable standby letter of credit in effect, was $374.3 million.

PDCM Credit Facility. PDCM has a credit facility dated April 30, 2010, as amended, with an aggregate revolving commitment or borrowing base of $80 million, of which our proportionate share is $40 million. The maximum allowable facility amount is $400 million. At PDCM's discretion, interest accrues at either an alternative base rate ("ABR") or an adjusted LIBOR. The ABR is the greater of Wells Fargo's prime rate, the federal funds effective rate plus 0.5% or the adjusted LIBOR for a three month interest period plus 1%. ABR and adjusted LIBOR borrowings are assessed an additional margin based upon the outstanding balance as a percentage of the available balance. ABR borrowings are assessed an additional margin of 1.25% to 2.0%. Adjusted LIBOR borrowings are assessed an additional margin spread of 2.25% to 3.0%. No principal payments are required until the credit agreement expires on April 30, 2014, or in the event that the borrowing base falls below the outstanding balance. 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 June 30 and December 31. Either PDCM or the lenders may request a redetermination upon the occurrence of certain events. The borrowing base redetermination based on our December 31, 2012 proved reserves is currently under review. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Marcellus assets.

The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and financial ratios that must be met on a quarterly basis. The financial tests and ratios, as defined by the credit facility, include requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 4.5 to 1.0 (declining to 4.0 to 1.0 on September 30, 2013) and to maintain a minimum interest coverage ratio of 2.5 to 1.0. As of March 31, 2013, our proportionate share of PDCM's outstanding credit facility balance was $28.8 million compared to $26.3 million as of December 31, 2012. PDCM is required to pay a commitment fee of 0.5% per annum on the unutilized portion of the activated credit facility. The weighted-average borrowing rate on PDCM's credit facility was 3.6% per annum as of March 31, 2013, compared to 3.5% as of December 31, 2012.

As of March 31, 2013, we were in compliance with all credit facility covenants and expect to remain in compliance throughout the next twelve-month period.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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, 2012	$	62,563
Obligations incurred with development activities	98
Accretion expense	1,245
Obligations discharged with disposal of properties and asset retirements	(264		)
Balance at March 31, 2013	63,642
Liabilities held for sale (1)	(28,346		)
Less current portion	(1,000		)
Long-term portion	$	34,296

______________

(1)	Represents asset retirement obligations related to our assets held for sale. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned sale of these properties.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Firm Transportation Agreements. We enter into contracts that provide firm transportation, sales and processing services on pipeline systems through which we transport or sell natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by PDCM, our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. With the exception of contracts entered into by PDCM, the costs of any volume shortfalls are borne by PDC.

        

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

		For the Twelve Months Ending March 31,
Area		2014				2015				2016				2017				2018 and Through Expiration				Total				Expiration Date
Volume (MMcf)
Piceance Basin		32,114				15,522				10,277				9,319				31,653				98,885				May 31, 2021
Appalachian Basin		20,238				25,028				23,923				24,795				162,165				256,149				September 20, 2025
NECO		2,100				1,825				1,830				1,375				—				7,130				December 31, 2016
Utica Shale		1,541				2,623				2,738				2,738				17,115				26,755				June 30, 2023
Total		55,993				44,998				38,768				38,227				210,933				388,919
Dollar commitment (in thousands)		$	26,998			$	19,529			$	16,612			$	16,026			$	69,428			$	148,593

Effective January 1, 2013, we entered into a new gas gathering and processing agreement with Williams Field Services Company related to our Piceance Basin production. The new agreement included additional terms and conditions which, among other things, reduced our Piceance Basin total committed volumes for gathering over the term of the agreement. In February 2013, we entered into a purchase and sale agreement pursuant to which our Piceance Basin and NECO firm transportation and processing commitments will be assumed by the purchaser of certain of our oil and natural gas properties upon the closing of the transaction. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the planned sale. There can be no assurance that we will be successful in closing such divestiture.

In March 2013, we entered into long-term agreements with a subsidiary of MarkWest Energy Partners, LP to provide midstream services, including gas gathering, processing, fractionation and marketing, to support our Utica Shale operations in Guernsey County in Southeast Ohio. The primary term of the agreements is ten years commencing when our natural gas begins to flow into the gathering system. The gas processing agreement includes minimum volume commitments as shown in the table above, with certain fees assessed for any shortfall.

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 is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.

Alleged Class Action Filed Regarding 2010 and 2011 Partnership Purchases

On December 21, 2011 the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to its partnership repurchases completed by mergers in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and is titled Schulein v. Petroleum Development Corp. The complaint primarily alleges that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. On February 10, 2012, the Company filed a motion to dismiss or in the alternative to stay. On June 15, 2012, the Court denied the motion. The Court has approved a litigation schedule including a jury trial in May 2014. We have not recorded a liability for claims pending because we believe we have good legal defenses to the asserted claims and because the plaintiffs have not specified damages and it is not possible for management to reasonably estimate what, if any, monetary damages could result from this claim.

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 recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of March 31, 2013 and December 31, 2012, we had accrued environmental liabilities in the amount of $6.3 million and $8.4 million, respectively, included in other accrued expenses on the balance sheets. We are not aware of any environmental claims existing as of March 31, 2013 which have not been provided for or would otherwise have a material impact on our 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, 2013, the maximum annual repurchase obligation, based upon the minimum price described above, was approximately $3.9 million. We believe we have adequate liquidity to meet this potential obligation. For the quarter ended March 31, 2013, amounts paid for the repurchase of partnership units pursuant to this provision were immaterial.

    

Employment Agreements with Executive Officers. Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company.

NOTE 10 - COMMON STOCK

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,
		2013				2012 (1)
		(in thousands)
Stock-based compensation expense		$	2,602			$	1,946
Income tax benefit		(994		)		(741		)
Net expense		$	1,608			$	1,205

Stock Appreciation Rights ("SARs")

The SARs vest ratably over a three-year period and may be exercised at any point after vesting through 10 years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

In January 2013, the Compensation Committee awarded 87,078 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 following assumptions:

	Three Months Ended March 31,
	2013				2012
Expected term of award	6 years				6 years
Risk-free interest rate	1.0		%		1.1		%
Expected volatility	65.5		%		64.3		%
Weighted-average grant date fair value per share	$	21.96			$	17.61

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 or declare dividends in the foreseeable future.

    

The following table presents the changes in our SARs:

	Three Months Ended March 31,
	2013														2012
	Number of SARs			Weighted-Average Exercise Price				Average Remaining Contractual Term (in years)			Aggregate Intrinsic Value (in thousands)				Number of SARs			Weighted-Average Exercise Price				Average Remaining Contractual Term (in years)			Aggregate Intrinsic Value (in thousands)
Outstanding beginning of year, January 1,	118,832			$	30.80			8.4			$	486			50,471			$	31.61			8.6			$	341
Awarded	87,078			37.18				—			—				68,361			30.19				—			—
Outstanding at March 31,	205,910			33.50				8.9			3,310				118,832			30.80				9.2			875
Vested and expected to vest at March 31,	194,689			33.38				8.8			3,152				111,137			30.76				9.2			825
Exercisable at March 31,	56,430			31.04				8.0			1,046				16,822			31.61				8.4			135

Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our statement of operations as of March 31, 2013 was $2.5 million. The cost is expected to be recognized over a weighted-average period of 2.4 years.

    

Restricted Stock Awards

Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed.

In January 2013, the Compensation Committee awarded a total of 103,050 time-based restricted shares to our executive officers that vest ratably over three year period ending on January 16, 2016.

The following table presents the changes in non-vested time-based awards for the three months ended March 31, 2013:

	Shares			Weighted-Average Grant-Date Fair Value
Non-vested at December 31, 2012	646,490			$	27.93
Granted	118,518			36.82
Vested	(55,918	)		29.85
Forfeited	(11,648	)		26.48
Non-vested at March 31, 2013	697,442			29.31

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

	As of/Three Months Ended March 31,
	2013				2012
	(in thousands, except per share data)
Total intrinsic value of time-based awards vested	$	2,303			$	1,104
Total intrinsic value of time-based awards non-vested	34,572				21,918
Market price per common share as of March 31,	49.57				37.09
Weighted-average grant date fair value per share	36.82				31.23

Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our statements of operations as of March 31, 2013 was $13.3 million. This cost is expected to be recognized over a weighted-average period of 2.3 years.

Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. 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 between three to 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 January 2013, the Compensation Committee awarded a total of 41,570 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 16 peer companies. The shares are measured over a three-year period ending on December 31, 2015 and can result in a payout between 0% 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 following assumptions:

		Three Months Ended March 31,
		2013				2012
Expected term of award		3 years				3 years
Risk-free interest rate		0.4		%		0.3		%
Expected volatility		56.6		%		65.3		%
Weighted-average grant date fair value per share		$	49.04			$	36.54

The expected term of the awards was 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 and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.

    

The following table presents the change in non-vested market-based awards during three months ended March 31, 2013:

		Shares			Weighted-Average Grant-Date Fair Value per Share
Non-vested at December 31, 2012		40,696			$	39.22
Granted		41,570			49.04
Non-vested at March 31, 2013		82,266			44.18

	As of/Year Ended March 31,
	2013				2012
	(in thousands, except per share data)
Total intrinsic value of market-based awards non-vested	$	4,078			$	2,731
Market price per common share as of March 31,	49.57				37.09
Weighted-average grant date fair value per share	49.04				36.54

Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our statement of operations as of March 31, 2013 was $2.5 million. This cost is expected to be recognized over a weighted-average period of 2.4 years.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 11 - EARNINGS PER SHARE

Basic earnings per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible senior notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

The following table presents a reconciliation of the weighted-average diluted shares outstanding:

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Weighted-average common shares outstanding - basic	30,270			23,609
Dilutive effect of:
Restricted stock	—			212
SARs	—			65
Non-employee director deferred compensation	—			3
Weighted-average common and common share equivalents outstanding - diluted	30,270			23,889

The following table presents 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,
	2013			2012
	(in thousands)
Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	844			27
SARs	45			19
Stock options	3			7
Non-employee director deferred compensation	4			—
Convertible senior notes	48			—
Total anti-dilutive common share equivalents	944			53

We reported a net loss for the three months ended March 31, 2013. As a result, our basic and diluted weighted-average common shares outstanding were the same as the effect of the common share equivalents was anti-dilutive.

In November 2010, we issued 115,000 convertible senior notes, $1,000 principal amount per note, that give the holders the right to convert the aggregate principal amount into 2.7 million common shares at a conversion price of $42.40 per share. These convertible senior notes could be included in the dilutive earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the period presented. Shares issuable under the convertible senior notes were excluded from the diluted earnings per share calculation for the three month ended March 31, 2013 as the effect would be anti-dilutive to our earnings. Shares issuable under the convertible senior notes were excluded from the diluted earnings per share calculation for the three months ended March 31, 2012 as the conversion price was greater than the average market price of our common stock during the period.

NOTE 12 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS

    

Piceance Basin and NECO. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets for aggregate cash consideration of approximately $190 million, subject to post-closing adjustments. These assets have been classified as held for sale in the condensed consolidated balance sheet as of March 31, 2013. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and by certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus. The proceeds from the asset disposal will be used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. There can be no assurance we will be successful in closing such divestiture. Following the planned sale, we will not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

separately reported as discontinued operations in the condensed consolidated statement of operations for all periods presented. The planned sale of our other non-core Colorado oil and gas properties do not meet the requirements to be accounted for as discontinued operations.

Appalachian Basin. During the three months ended March 31, 2013, we developed a plan to market all of our shallow upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties located in West Virginia and Pennsylvania owned directly by us, as well as through our proportionate share of PDCM and our affiliated partnerships. The properties being marketed consist of approximately 3,500 gross shallow producing wells, related facilities and associated shallow leasehold acreage, limited to the upper Devonian and shallower formations. The company is retaining all zones, formations and intervals below the upper Devonian formation including the Marcellus Shale, Utica Shale and Huron Shale. Any proceeds from the sale of these shallow upper Devonian assets will be used to fund a portion of our Marcellus drilling program in the Appalachian Basin. It is not certain that these properties will be sold. We have classified the related assets owned directly by us, as well as through our proportionate share of PDCM and our affiliated partnerships, as held for sale in the condensed consolidated balance sheet as of March 31, 2013. The planned divestiture of these assets does not meet the requirements to be accounted for as discontinued operations.

Permian Basin. In December 2011, we executed a purchase and sale agreement with COG Operating LLC (“COG”), a wholly owned subsidiary of Concho Resources Inc., an unrelated third-party, for the sale of our core Permian Basin assets for a sale price of $173.9 million, subject to customary terms and adjustments, including adjustments based on title and environmental due diligence to be conducted by COG. The effective date of the transaction was November 1, 2011. Following the sale to COG, we do not have significant continuing involvement in the operations of, or cash flows from, these assets. Accordingly, the results of operations related to the Permian assets have been separately reported as discontinued operations in the condensed consolidated statement of operations for the three months ended March 31, 2012. In February 2012, the divestiture closed. Upon final settlement, total proceeds received were $189.2 million after closing adjustments.

Selected financial information related to divested and discontinued operations. The tables below set forth selected financial information related to net assets held for sale and operating results related to discontinued operations. Net assets held for sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchaser. While the reclassification of revenues and expenses related to discontinued operations for the prior period had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.

The following table presents balance sheet data related to assets held for sale as of March 31, 2013:

Balance Sheet		Net Assets Held for Sale
		(in thousands)
Assets
Properties and equipment		$	782,556
Accumulated depreciation, depletion and amortization		(565,754		)
Total Assets		$	216,802
Liabilities
Asset retirement obligation		$	28,346
Net Assets		$	188,456

    

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents statement of operations data related to our discontinued operations:

		Three Months Ended
Statements of Operations - Discontinued Operations		2013				2012
		(in thousands)
Revenues
Natural gas, NGLs and crude oil sales		$	10,274			$	12,811
Sales from natural gas marketing		450				453
Well operations, pipeline income and other		450				566
Total revenues		11,174				13,830
Costs, expenses and other
Production costs		5,393				7,102
Cost of natural gas marketing		454				401
Depreciation, depletion and amortization		2,258				11,902
Other		495				348
Gain on sale of properties and equipment		—				(20,335		)
Total costs, expenses and other		8,600				(582		)
Income from discontinued operations		2,574				14,412
Provision for income taxes		(1,037		)		(5,341		)
Income from discontinued operations, net of tax		$	1,537			$	9,071

NOTE 13 - TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES

PDCM and Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by PDCM and our affiliated partnerships in the eastern operating region.

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 have entered into derivative instruments on behalf of our affiliated partnerships for their estimated production.

The following table presents amounts included in our condensed consolidated statements of operations related to the marketing of natural gas on behalf of PDCM and our affiliated partnerships and amounts included in our condensed consolidated balance sheets related to the derivative instruments we entered into on behalf of our affiliated partnerships:

		Three Months Ended March 31,
Statement of Operations		2013				2012
		(in thousands)
PDCM:
Sales from natural gas marketing		$	3,725			$	2,442
Cost of natural gas marketing		3,652				2,394
Affiliated Partnerships:
Sales from natural gas marketing		268				119
Cost of natural gas marketing		274				116

		As of
Balance Sheet		March 31, 2013				December 31, 2012
		(in thousands)
Affiliated Partnerships:
Receivable from affiliated partnerships		$	1,575			$	2,140
Payable to affiliated partnerships		2,936				4,707

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $3.4 million and $3.2 million for the quarters ended March 31, 2013 and 2012, respectively. Our statements of operations include only our proportionate share of these billings. The following table presents the statement of operations line item in which our proportionate share is recorded and the amount for each of the periods presented.

		Three Months Ended March 31,
Statement of Operations Line Item		2013				2012
		(in thousands)
Production costs		$	1,066			$	1,056
Exploration expense		105				132
General and administrative expense		515				414

 

NOTE 14 - BUSINESS SEGMENTS

We separate our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated.

Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our natural gas and crude oil properties. The segment represents revenues and expenses from the production and sale of natural gas, NGLs and crude oil. Segment revenue includes natural gas, NGLs and crude oil sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of natural gas and crude oil properties, direct general and administrative expense and depreciation, depletion and amortization expense.

Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income, less costs of natural gas marketing and direct general and administrative expense.

Unallocated amounts. Unallocated income includes corporate general administrative expense, corporate depreciation, depletion and amortization expense, interest income and interest expense.

    

The following tables present our segment information:

	Three Months Ended March 31,
	2013				2012
	(in thousands)
Revenues:
Oil and gas exploration and production	$	58,156			$	79,625
Gas marketing	13,670				11,381
Total revenues	$	71,826			$	91,006
Segment income (loss) before income taxes:
Oil and gas exploration and production	$	(33,702	)		$	37,424
Gas marketing	(66		)		290
Unallocated	(29,679		)		(26,830		)
Total	$	(63,447	)		$	10,884

	March 31, 2013				December 31, 2012
	(in thousands)
Segment assets:
Oil and gas exploration and production	$	1,460,815			$	1,723,011
Gas marketing	10,204				11,090
Unallocated	93,992				92,747
Assets held for sale	216,802				—
Total Assets	$	1,781,813			$	1,826,848

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PDC ENERGY, INC.

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

The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements.

EXECUTIVE SUMMARY

Financial Overview

We recorded strong increases in natural gas, NGLs and crude oil sales from continuing operations during the three months ended March 31, 2013 as a direct result of our significant increase in production. Total natural gas, NGLs and crude oil sales increased $12.4 million, or 18.6%, to $79.4 million during the three months ended March 31, 2013 compared to $67 million during the three months ended March 31, 2012. Our natural gas, NGLs and crude oil production from continuing operations during the three months ended March 31, 2013 averaged 18.5 Mboe per day, an increase of approximately 18.6% compared to the three months ended March 31, 2012. The increase in production is primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field and to a lesser extent certain Wattenberg assets acquired in June 2012. Crude oil production from continuing operations increased 22.8% during the three months ended March 31, 2013, while NGL production from continuing operations increased 4.9%. Our liquids percentage of total production from continuing operations was 54.4% during the three months ended March 31, 2013. Natural gas production increased 17.1% during the three months ended March 31, 2013 compared to the same period in 2012.

Available liquidity as of March 31, 2013 was $388.1 million, including $12.4 million through our joint venture PDCM, compared to $398.6 million, including $14.1 million related to PDCM, as of December 31, 2012. Available liquidity is comprised of cash, cash equivalents and funds available under revolving credit facilities. We believe we have sufficient liquidity to allow us to execute our drilling program in the Wattenberg Field and the Utica Shale.

 

Operational Overview

Drilling Activities. During the three months ended March 31, 2013, we continued to focus our operations primarily in the oil- and liquid-rich Wattenberg Field in Colorado and the emerging Utica Shale play in Ohio. In our western operating region, we currently have two drilling rigs operating in the Wattenberg Field. We spud 11 horizontal wells in the Wattenberg Field, four of which were completed, during the three months ended March 31, 2013 and participated in ten gross, two net, horizontal non-operated drilling projects. We also executed six refracture and/or recompletion projects on three wells in the Wattenberg Field.

In our eastern operating region, we spud two horizontal Utica wells during the quarter on our first three-well pad, all of which were in-process as of March 31, 2013. These wells are expected to be turned-in-line during the third quarter of 2013. Of the wells drilled in 2012, one well remains shut-in awaiting pipeline connections, while production volumes from the second well are being sold through a temporary arrangement pending connection to permanent facilities. In addition, PDCM spud four horizontal Marcellus wells during the three months ended March 31, 2013, all of which were in-process as of March 31, 2013.

Planned Natural Gas and Crude Oil Properties Divestitures. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets for aggregate cash consideration of approximately $190 million. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and adjustments relating to certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus. We intend to use the proceeds from the sale to repay amounts outstanding under our revolving credit facility and partially fund our 2013 capital program. As of December 31, 2012, total estimated proved reserves related to these assets were 83,656 MMcf of natural gas and 148 MBbls of crude oil, for an aggregate of 14,091 MBbls of crude oil equivalent. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, to our condensed consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets. There can be no assurance that this transaction will close as planned. In addition, purchase price adjustments may reduce our proceeds from the transaction.

Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDA," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes 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 (loss) or cash flows from operations, investing or financing activities, and should not be viewed as a liquidity measure or indicator of 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 for a detailed description of these measures, as well as a reconciliation of each to the most comparable U.S. GAAP measure.

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PDC ENERGY, INC.

Results of Operations

Summary Operating Results

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

	Three Months Ended March 31,
	2013				2012				Percentage Change
	(dollars in millions, except per unit data)
Production (1)
Natural gas (MMcf)	4,549.8				3,884.5				17.1	%
Crude oil (MBbls)	668.3				544.4				22.8	%
NGLs (MBbls)	238.3				227.2				4.9	%
Crude oil equivalent (MBoe) (2)	1,665.0				1,419.0				17.3	%
Average MBoe per day	18.5				15.6				18.6	%
Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	14.0			$	10.0			40.1	%
Crude oil	58.1				50.6				15.0	%
NGLs	7.3				6.4				14.1	%
Total natural gas, NGLs and crude oil sales	$	79.4			$	67.0			18.6	%
Realized Gain (Losses) on Derivatives, net (3)
Natural gas	$	8.0			$	12.5			(36.1	)%
Crude oil	0.5				(2.6		)		*
Total realized gain on derivatives, net	$	8.5			$	9.9			(14.6	)%
Average Sales Price (excluding gain (loss) on derivatives)
Natural gas (per Mcf)	$	3.09			$	2.58			19.8	%
Crude oil (per Bbl)	86.96				92.86				(6.4	)%
NGLs (per Bbl)	30.48				28.01				8.8	%
Crude oil equivalent (per Boe)	47.71				47.18				1.1	%
Average Sales Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	4.85			$	5.81			(16.5	)%
Crude oil (per Bbl)	87.67				88.11				(0.5	)%
NGLs (per Bbl)	30.48				28.01				8.8	%
Crude oil equivalent (per Boe)	52.80				54.18				(2.5	)%
Average Lifting Cost (per Boe) (4)
Western operating region	$	3.96			$	4.08			(2.9	)%
Eastern operating region	7.08				8.47				(16.4	)%
Weighted-average	4.48				4.85				(7.6	)%
Natural Gas Marketing Contribution Margin (5)	$	—			$	0.3			*
Other Costs and Expenses
Exploration expense	$	1.7			$	1.9			(9.8	)%
Impairment of natural gas and crude oil properties	46.5				0.6				*
General and administrative expense	15.1				14.7				2.8	%
Depreciation, depletion and amortization	27.9				27.9				0.1	%
Interest Expense	$	13.4			$	10.4			27.9	%

*	Percentage change is not meaningful or equal to or greater than 300%.

Amounts may not recalculate due to rounding.

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PDC ENERGY, INC.

______________

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

(2)	One Bbl of crude oil or NGL equals six Mcf of natural gas.

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

(4)	Represents lease operating expenses, exclusive of production taxes, 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.

Natural Gas, NGLs and Crude Oil Sales

The following tables present natural gas, NGLs and crude oil production and weighted-average sales price from continuing operations:

		Three Months Ended March 31,
Production by Operating Region		2013			2012			Percentage Change
Natural gas (MMcf)
Western - Wattenberg Field		2,975.5			2,398.4			24.1	%
Eastern - Appalachian Basin		1,574.3			1,486.1			5.9	%
Total		4,549.8			3,884.5			17.1	%
Crude oil (MBbls)
Western - Wattenberg Field		650.7			541.3			20.2	%
Eastern - Appalachian Basin		17.6			3.1			*
Total		668.3			544.4			22.8	%
NGLs (MBbls)
Western - Wattenberg Field		238.3			227.2			4.9	%
Crude oil equivalent (MBoe)
Western - Wattenberg Field		1,385.0			1,168.2			18.6	%
Eastern - Appalachian Basin		280.0			250.8			11.6	%
Total		1,665.0			1,419.0			17.3	%

*	Percentage change is not meaningful or equal to or greater than 300%.

Amounts may not recalculate due to rounding.

		Three Months Ended March 31,
Average Sales Price by Operating Region										Percentage Change
(excluding gain (loss) on derivatives)		2013				2012
Natural gas (per Mcf)
Western - Wattenberg Field		$	3.02			$	2.67			13.1%
Eastern - Appalachian Basin		3.23				2.44				32%
Weighted-average price		3.09				2.58				19.8%
Crude oil (per Bbl)
Western - Wattenberg Field		86.89				92.83				(6.4)%
Eastern - Appalachian Basin		89.79				98.52				(9)%
Weighted-average price		86.96				92.86				(6.4)%
NGLs (per Bbl)
Western - Wattenberg Field		30.48				28.01				8.8%
Crude oil equivalent (per Boe)
Western - Wattenberg Field		52.55				53.94				(2.6)%
Eastern - Appalachian Basin		23.79				15.69				52%
Weighted-average price		47.71				47.18				1.1%

Amounts may not recalculate due to rounding.

 

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PDC ENERGY, INC.

For the three months ended March 31, 2013, natural gas, NGLs and crude oil sales revenue increased compared to the three months ended March 31, 2012 due to the following (in millions):

Increase in production	$	13.5
Increase in average natural gas price	2.3
Increase in average NGL price	0.5
Decrease in average crude oil price	(3.9		)
Total increase in natural gas, NGLs and crude oil sales revenue	$	12.4

Natural Gas, NGLs and Crude Oil Pricing. Our results of operations depend upon many factors, particularly the price of natural gas, NGLs and crude oil and our ability to market our production effectively. Natural gas, NGLs and crude oil prices are among the most volatile of all commodity prices. These price variations can have a material impact on our financial results and capital expenditures.

Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price we receive for our natural gas produced in our western operating region is based on CIG prices, while natural gas produced in our eastern operating region is based on NYMEX pricing. Our NGL price is mainly based on prices from the Conway hub in Kansas where our Wattenberg production is marketed. Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. The majority of our crude oil is sold on a calendar-year basis at a fixed differential to NYMEX pricing.

We currently use the "net-back" method of accounting for these arrangements related to our natural gas sales. We sell natural gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

Recently, a combination of increased drilling activity, curtailments due to limited capacity on local gathering and processing infrastructure and, in some periods, high temperatures, has resulted in capacity constraints, primarily in our Wattenberg Field. We anticipate that we will again experience high line pressures in 2013, particularly in the summer months, as field-wide production volumes from the ongoing development of the successful horizontal Wattenberg play outpace current midstream capacity. We have factored production curtailments into our estimated 2013 volumes to account for anticipated high line pressures, although the effect of the curtailments could exceed our estimates. We are working closely with our primary midstream provider in the Wattenberg Field who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity. We expect reduced line pressures to substantially benefit us in late 2013, concurrent with the startup of the LaSalle gas plant and associated field compressor stations. Like most producers, we rely on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our production growth. As a result, the timing and availability of these facilities is beyond our control.

Production Costs

Production costs include lease operating expenses, production taxes and certain production and engineering staff-related overhead costs, as well as other costs to operate wells and pipelines as follows:

	Three Months Ended March 31,
	2013				2012
	(in millions)
Lease operating expenses	$	7.5			$	6.9
Production taxes	5.4				4.5
Cost of well operations, overhead and other production expenses	3.0				1.5
Total production costs	$	15.9			$	12.9
Total production costs per Boe	$	9.52			$	9.12

Lease operating expenses. The increase in lease operating expenses in 2013 as compared to 2012 was primarily due to an increase of $0.3 million for the rental of additional compressors used to accommodate increased drilling activity in the Wattenberg Field and an increase of $0.4 million in additional wages and employee benefits. These increases were partially offset by a $0.3 million decrease in expense due to a reduction in the amount of workover projects performed during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012. Lifting costs per Boe were $4.48 and $4.85 for the three month periods ended March 31, 2013 and 2012, respectively. The 7.6% decrease in lifting costs per Boe in 2013 from 2012 was primarily due to an increase in production.

Production taxes. Production taxes fluctuate with natural gas, NGL and crude oil sales. The $0.9 million, or 18.3%, increase in production taxes for 2013 compared to 2012 is primarily related to a 18.6% increase in natural gas and crude oil sales.

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Overhead and other production expenses. Overhead and other production expenses increased $1.5 million for the three months ended March 31, 2013 as compared to the three months ended March 31, 2012. The increase consisted of a $0.5 million increase in transportation expense due to unutilized firm transportation, a $0.3 million increase in wages and employee benefits and a $0.7 million increase in various other operating costs.

Commodity Price Risk Management, Net

Commodity price risk management, net, includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to our natural gas and crude oil production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for additional details of our derivative financial instruments.

The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net:

 

	Three Months Ended March 31,
	2013				2012
	(in millions)
Commodity price risk management gain (loss), net:
Realized gains (losses):
Natural gas	$	8.0			$	12.5
Crude oil	0.5				(2.6		)
Total realized gains, net	8.5				9.9
Unrealized gains (losses):
Reclassification of realized gains included in prior periods unrealized	(9.1		)		(8.6		)
Unrealized gains (losses) for the period	(21.8		)		10.2
Total unrealized gains (losses), net	(30.9		)		1.6
Total commodity price risk management gain (loss), net	$	(22.4	)		$	11.5

Realized gains recognized in the three months ended March 31, 2013 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of our natural gas derivative positions. For the three months ended March 31, 2013, realized gains on natural gas, exclusive of basis swaps, were $12.2 million, reflective of a weighted-average strike price of $5.09 compared to a weighted-average settlement price of $3.34. These gains were offset in part by realized losses of $4.2 million on our basis swap positions as the negative basis differential between NYMEX and CIG was a weighted-average of $0.13 compared to a weighted-average strike price of $0.90. Realized gains for the three months ended March 31, 2013 on our crude oil positions are reflective of a weighted-average strike price of $96.22 compared to a weighted-average settlement price of $94.39.

During the three months ended March 31, 2013, we recorded unrealized losses on our natural gas positions of $16.7 million and unrealized losses on our crude oil positions of $5.6 million resulting from the upward shift in the natural gas and crude oil forward curves during the quarter. These losses were offset slightly by unrealized gains on our CIG basis swaps of $0.5 million due to the widening of the CIG basis forward curve.

    

Realized gains recognized in the three months ended March 31, 2012 were primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of our natural gas derivative positions. For the three months ended March 31, 2012, realized gains on natural gas, exclusive of basis swaps, were $17.1 million. These gains were offset in part by realized losses of $4.6 million on our basis swap positions. The realized gains on natural gas derivative positions for the three months ended March 31, 2012 were offset in part by realized losses on our crude oil positions as a result of higher spot prices at settlement compared to the respective strike price on our derivative positions.

Unrealized gains for the three months ended March 31, 2012 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of our open positions, offset in part by the upward shift in the crude oil forward curve and the narrowing of the CIG basis forward curve. For the three months ended March 31, 2012, unrealized gains on our natural gas positions were $22.4 million, partially offset by unrealized losses on our crude oil positions and CIG basis swaps of $12.1 million and $0.1 million, respectively.

We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our physical natural gas and crude oil at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps.

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Natural Gas Marketing

 

Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices and realized and unrealized, mark-to-market adjustments, gains and losses on open derivative positions, and, to a lesser extent, volumes sold and purchased.

    

The following table presents the components of sales from and costs of natural gas marketing:

	Three Months Ended March 31,
	2013				2012
	(in millions)
Natural gas sales revenue	$	14.4			$	10.5
Realized derivative gains, net	0.2				0.8
Unrealized derivative gains (losses), net	(1.0		)		0.1
Other	0.1				—
Total sales from natural gas marketing	13.7				11.4
Costs of natural gas purchases	14.2				9.9
Realized derivative losses, net	0.2				0.8
Unrealized derivative (gains) losses, net	(1.1		)		0.1
Other	0.4				0.3
Total costs of natural gas marketing	13.7				11.1
Natural gas marketing contribution margin	$	—			$	0.3

Natural gas sales revenue and cost of natural gas purchases increased in the three months ended March 31, 2013 compared to the three months ended March 31, 2012 primarily due to natural gas prices increasing by approximately 30%. The effect of the higher natural gas prices were offset in part by a 0.6% decrease in volumes.

Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price

derivative contracts for the purchase or sale of physical natural gas and enter into cash-settled derivative positions with counterparties in order

to offset those same physical positions.

Exploration Expense

The following table presents the major components of exploration expense:

	Three Months Ended March 31,
	2013				2012
	(in millions)
Geological and geophysical costs	$	0.5			$	0.9
Operating, personnel and other	1.2				1.0
Total exploration expense	$	1.7			$	1.9

Geological and geophysical costs. The $0.4 million decrease during the three months ended March 31, 2013 compared to the three months ended March 31, 2012 is primarily related to costs associated with a decrease in PDCM's geological and seismic testing of the Marcellus Shale in the Appalachian Basin and PDC's reservoir studies in the Utica Shale.

Operating, personnel and other. The $0.2 million increase during the three months ended March 31, 2013 compared to the three months ended March 31, 2012 is mainly attributable to a $0.3 million increase in exploration general and administrative expense, primarily payroll and employee benefits in the exploration division as a result of increased employee headcount in the Utica Shale, offset in part by a $0.1 million decrease in PDCM's lease prospecting costs.

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Impairment of Natural Gas and Crude Oil Properties

    

The following table sets forth the major components of our impairments of natural gas and crude oil properties expense:

		Three Months Ended March 31,
		2013				2012
		(in millions)
Impairment of proved properties		$	45.0			$	—
Impairment of individually significant unproved properties		0.2				0.2
Amortization of individually insignificant unproved properties		1.3				0.4
Total impairment of natural gas and crude oil properties		$	46.5			$	0.6

Impairment of proved properties. During the three months ended March 31, 2013, we recognized an impairment charge of approximately $45 million related to all of our shallow upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania owned directly by us, as well as through our proportionate share of PDCM and our affiliated partnerships. The assets were determined to be impaired when the assets became held for sale in the first quarter of 2013 as the estimated fair value, less cost to sell, was less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based upon estimated future cash flows from an unrelated third-party bid, a Level 3 input. The impairment charge was included in the statement of operations line item impairment of natural gas and crude oil properties. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, to our condensed consolidated financial statements included elsewhere in this report for additional information regarding these properties. It is not certain that these properties will be sold.

Amortization of individually insignificant unproved properties. The $0.9 million increase during the three months ended March 31, 2013 compared to the three months ended March 31, 2012 is primarily related to an increase in leases not held by production, primarily in the Utica Shale.

General and Administrative Expense

General and administrative expense increased $0.4 million to $15.1 million for the three months ended March 31, 2013 compared to $14.7 million for the three months ended March 31, 2012. The increase was primarily due to increased payroll and employee benefits of $1.2 million, partially offset by a decrease in professional, consulting and legal costs of $0.6 million.

    

Depreciation, Depletion and Amortization

Natural gas and crude oil properties. Depreciation, depletion and amortization ("DD&A") expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A expense related to natural gas and crude oil properties was $26.7 million for the three months ended March 31, 2013 compared to $26.8 million for the three months ended March 31, 2012. The quarter-over-quarter decrease was comprised of a decrease of $4.7 million due to a lower weighted-average depreciation, depletion and amortization rate, offset in part by an increase of $4.6 million due to higher production during the three months ended March 31, 2013.

The following table presents our DD&A expense rates for natural gas and crude oil properties:

	Three Months Ended March 31,
Operating Region/Area	2013				2012
	(per Boe)
Western
Wattenberg Field	$	17.00			$	20.66
Eastern
Marcellus Shale and other	11.44				10.62
Total weighted-average	$	16.06			$	18.89

Non-natural gas and crude oil properties. Depreciation expense for non-natural gas and crude oil properties was $1.2 million for the three months ended March 31, 2013 compared to $1.1 million for the three months ended March 31, 2012.

Interest Expense

Interest expense increased $3 million to $13.4 million for the three months ended March 31, 2013 compared to $10.4 million for the three months ended March 31, 2012. The increase is primarily related to $10 million of interest expense resulting from the issuance in October 2012 of $500 million 7.75% Senior Notes due 2022. Partially offsetting this increase were decreases of $6.3 million related to the redemption,

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in November 2012, of previously-outstanding 12% senior notes due 2018 and $0.7 million as a result of lower average borrowings on our revolving credit facility during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012.

Provision for Income Taxes

See Note 6, Income Taxes, to the accompanying condensed consolidated financial statements for a discussion of the changes in our effective tax rate for the three months ended March 31, 2013 compared to the three months ended March 31, 2012. Due to tax interim period benefit limitations, comparisons of interim loss periods with interim income periods and the different effects of permanent tax adjustments, primarily percentage depletion and nondeductible officers' compensation, the effective tax rate comparison for the three-month periods is less meaningful.

Discontinued Operations

On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets for aggregate cash consideration of approximately $190 million, subject to post-closing adjustments. Following the planned sale, we will not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the condensed consolidated statement of operations for all periods presented. The planned sale of our other non-core Colorado oil and gas properties will not meet the requirements to be accounted for as discontinued operations. There can be no assurance we will be successful in closing such divestiture.

In December 2011, we executed a purchase and sale agreement with COG, a wholly owned subsidiary of Concho Resources Inc., an unrelated third-party, for the sale of our then remaining Permian Basin assets and closed the transaction in February 2012. Upon final settlement on June 29, 2012, total proceeds received were $189.2 million after final closing adjustments.

See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, to the accompanying condensed consolidated financial statements included elsewhere in this report for additional information regarding the planned sale of our Piceance Basin, NECO and other non-core Colorado oil and gas properties and the divestiture of our Permian assets.

The table below presents production data related to the assets that have been or are planned to be divested and that are classified as discontinued operations:

	Three Months Ended March 31,
Discontinued Operations	2013			2012
Production
Natural gas (MMcf)	3,584.1			4,529.8
Crude oil (MBbls)	6.9			49.9
NGLs (MBbl)	—			14.6
Crude oil equivalent (MBoe)	604.2			819.5

Net Income (Loss)/Adjusted Net Income (Loss)

  

Net loss for the three months ended March 31, 2013 was $39.4 million compared to net income of $15.8 million for the three months ended March 31, 2012. Adjusted net loss, a non-U.S. GAAP financial measure, for the three months ended March 31, 2013 was $20.4 million compared to an adjusted net income of $14.9 million for the three months ended March 31, 2012. The quarter-over-quarter changes in net income (loss) are discussed above, with the most significant changes being related to the increase in commodity price risk management losses, net and the increase in impairment of natural gas and crude oil properties, offset in part by the increase in natural gas, NGL and crude oil sales. Additionally, during the three months ended March 31, 2012 we recorded a pretax gain of $19.9 million related to the divestiture of our Permian Basin assets. These same reasons for change similarly impacted adjusted net income (loss), with the exception of the unrealized derivative gains and losses on derivatives, adjusted for taxes, as these amounts are not included in the total. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of this non-U.S. GAAP financial measure.

Financial Condition, Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in the debt and equity markets and asset monetization transactions. For the three months ended March 31, 2013, our primary source of liquidity was net cash flows from operating activities of $44.3 million.

Our primary source of cash flows from operating activities is the sale of natural gas, NGLs and crude oil and to a lesser extent realized commodity price risk management gains. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our use of derivatives, which

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has also historically been a source of cash. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in two years or less, our debt covenants limit us from entering into hedges that would exceed 80% of our expected future production on total proved reserves (proved developed producing, proved developed not producing and proved undeveloped). For instruments that mature later than two years, but no more than our designated maximum maturity, our debt covenants limit our holdings to 80% of our expected future production from proved developed producing properties. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production.

Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At March 31, 2013, we had a working capital deficit of $42.1 million compared to a deficit of $31.4 million at December 31, 2012.

We ended March 2013 with cash and cash equivalents of $2.5 million and availability under our revolving credit facility and our proportionate share of PDCM's credit facility of $385.6 million, for a total liquidity position of $388.1 million, compared to $398.6 million at December 31, 2012. The decrease in liquidity of $10.5 million, or 2.6%, was primarily attributable to capital expenditures of $61.9 million during the three months ended March 2013, offset in part by cash flows provided by operating activities of $44.3 million and proceeds from acquisition adjustments of $7.6 million. With our current liquidity position, planned asset sales and expected cash flows from operations, we believe that we have sufficient capital to fund operations.

Capital Expenditures

We establish a capital budget annually based upon our development and exploration opportunities, liquidity position and expected cash flows from operating activities. We may revise our capital budget during the year as a result of, among other things, acquisitions or dispositions of assets, drilling results, commodity prices, changes in our borrowing capacity and/or significant changes in cash flows. In March 2013, our Board of Directors approved our current 2013 capital budget of $387 million, excluding our share of PDCM's capital budget. Based on our budget, we expect to allocate $280 million to be invested in the Wattenberg Field, where we expect to add a third rig in the second quarter and to drill a total of 69 horizontal wells in the liquid-rich Niobrara and Codell formations during 2013. We expect to allocate approximately $96 million to drilling, leasing and completion activity in the Utica Shale, where we expect to maintain a one-rig drilling program throughout 2013 and expect to drill a total of 11 horizontal wells. PDCM's 2013 capital budget is $114 million, of which $57 million represents our share, and is expected to be funded by PDCM's operating activities, proceeds from divestitures and additional borrowings. PDCM's capital budget for 2013 includes funding for the drilling of 15 gross horizontal wells.

Because natural gas and crude oil production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of natural gas, NGLs and crude oil production and cash flows from operating activities if capital markets were unavailable, commodity prices were to become depressed and/or the borrowing base under our revolving credit facility was significantly reduced. The occurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures and could have a material negative impact on our operations in the future.

Financing Activities

In recent periods, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of debt and equity securities. We cannot, however, assure this will continue to be the case in the future. We continue to monitor market conditions and circumstances and their potential impact on each of our revolving credit facility lenders. Our $450 million revolving credit facility borrowing base is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. Our next scheduled redetermination is in May 2013. While we expect to continue to add producing reserves through our drilling operations, these reserve additions will be offset by the planned sale of our Piceance and NECO assets if that transaction is completed and could be offset by other factors including, among other things, a significant decrease in commodity prices. However, we do not expect a change in the borrowing base upon the completion of our May 2013 redetermination.

In January 2012, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants and purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable.

Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.0 times earnings before interest, taxes, depreciation, depletion and amortization, unrealized derivative gains (losses), exploration expense, gains (losses) on sales of assets and other non-cash, extraordinary or non-recurring gains (losses) ("EBITDAX") and (ii) an adjusted current ratio of at least 1.0 to 1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of natural gas and crude oil derivative instruments. Additionally, available borrowings under our revolving credit facility are added back to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At March 31, 2013, we were in compliance with all debt covenants with a 3.3 times debt to EBITDAX ratio and a 3.0 to 1.0 current ratio. We expect to remain in compliance throughout the next year.

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The indenture governing our senior notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. At March 31, 2013, we were in compliance with all covenants and expect to remain in compliance throughout the next year.

See Part I, Item 3, Quantitative and Qualitative Disclosures about Market Risk, for our discussion of credit risk.

Cash Flows

Operating Activities. Our net cash flows from operating activities is primarily impacted by commodity prices, production volumes, realized gains and losses from our derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities were unchanged at $44.3 million for each of the three month periods ended March 31, 2013 and 2012 as increases in natural gas, NGLs and crude oil sales were offset by increases in production costs, other expenses and the difference in the timing of cash payments and receipts of our assets and liabilities. The key components for the changes in our cash flows provided by operating activities are described in more detail in Results of Operations above.

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased $2.7 million during the three months ended March 31, 2013 compared to the three months ended March 31, 2012. The increase was primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of our assets and liabilities. Adjusted EBITDA, a non-U.S. GAAP financial measure, decreased by $14.4 million during the three months ended March 31, 2013 compared to the three months ended March 31, 2012, primarily related to the $20.3 million pretax gain on sale of properties and equipment recognized in 2012 related to the sale of our Permian Basin assets and an increase in production cost of approximately $2.9 million in the quarter ended 2013. The decreases were offset in part by a $12.5 million increase in natural gas, NGLs and crude oil sales during the three months ended March 31, 2013. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of non-U.S. GAAP financial measures.

 

Investing Activities. Cash flows from investing activities primarily consist of the acquisition, exploration and development of natural gas and crude oil properties, net of dispositions of natural gas and crude oil properties. During the three months ended March 31, 2013, our drilling program consisted of two rigs operating in the oil- and liquid-rich horizontal Niobrara and Codell plays in our Wattenberg Field, one rig in the emerging Utica shale play and one rig in the Marcellus Shale. Net cash used in investing activities of $54.3 million during the three months ended March 31, 2013 was primarily related to drilling activity of $61.9 million, offset in part by cash receipts of approximately $7.6 million related to post-closing adjustments of previous acquisitions.

 

Financing Activities. Net cash from financing activities for the three months ended March 31, 2013 decreased significantly compared to the three months ended March 31, 2012. Net cash from financing activities for the three months ended March 31, 2012 was primarily related to our utilization of proceeds provided from the divestiture of our Permian assets in February 2012 to pay down our corporate credit facility and partially fund our capital expenditures. It was therefore not necessary to draw on our corporate bank credit facility.

Drilling Activity

 

The following table presents our net developmental and exploratory drilling activity. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells spudded, turned-in-line and producing during the period. In-process wells represent wells that have been spudded, drilled and are waiting to be completed and/or for gas pipeline connection during the period.

 

		Net Drilling Activity
		Three Months Ended March 31,
		2013						2012
Operating Region/Area		Productive			In-Process (1)			Productive			In-Process
Development Wells
Western		4.0			7.2			2.3			3.7
Eastern		—			2.0			—			1.5
Total development wells		4.0			9.2			2.3			5.2
Exploratory Wells
Western		—			—			—			—
Eastern		—			1.5			—			—
Total exploratory wells		—			1.5			—			—
Total drilling activity		4.0			10.7			2.3			5.2

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__________

(1)	A total of 13.7 net wells, including the 10.7 net wells drilled during the three months ended March 31, 2013 and still in-process as of March 31, 2013, were waiting to be completed and/or for pipeline connection. All in-process wells as of March 31, 2013 are horizontal wells.

Off-Balance Sheet Arrangements

From time to time, we enter into arrangements and transactions that can give rise to off-balance sheet obligations. These arrangements are identified under the caption Contractual Obligations and Contingent Commitments in our 2012 Form 10-K.

In March 2013, we entered into long-term agreements for midstream services, including gas gathering, processing, fractionation and marketing to support our Utica Shale operations in Guernsey County in Southeast Ohio. The primary term of the agreements is ten years commencing when our natural gas begins to flow into the gathering system. The gas processing agreement includes minimum volume commitments with certain fees assessed for any shortfall. See Note 9, Commitments and Contingencies, to the accompanying condensed consolidated financial statements included elsewhere in this report for a discussion of our firm transportation agreements.

Commitments and Contingencies

See Note 9, Commitments and Contingencies, to the accompanying condensed consolidated financial statements included elsewhere in this report.

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to the accompanying condensed consolidated financial statements included elsewhere in this report.

Critical Accounting Policies and Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with U.S. GAAP requires management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.

There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the consolidated financial statements and accompanying notes contained in our 2012 Form 10-K.

Reconciliation of Non-U.S. GAAP Financial Measures

Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the Condensed Consolidated Statements of Cash Flows in this report.

Adjusted net income (loss). We define adjusted net income (loss) as net income (loss) plus unrealized derivative losses, less unrealized derivative gains, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe it often provides more transparency into our operating trends, such as production, prices, operating costs, realized gains and losses from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from unrealized gains and losses from derivatives. Additionally, other items which are not indicative of future results may be excluded to clearly identify operational trends.

Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus unrealized derivative loss, interest expense, net of interest income, income taxes, impairment of natural gas and crude oil properties, depreciation, depletion and amortization, and accretion of asset retirement obligations, less unrealized derivative gain. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), nor as an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by the Company and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as:

•	our operating performance and return on capital as compared to our peers;

•	the financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis;

•	our ability to generate sufficient cash to service our debt obligations; and

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•	the viability of acquisition opportunities and capital expenditure projects, including the related rate of return.

The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure:

	Three Months Ended March 31,
	2013				2012
	(in millions)
Adjusted cash flows from operations:
Adjusted cash flows from operations	$	52.4			$	49.7
Changes in assets and liabilities	(8.1		)		(5.4		)
Net cash from operating activities	$	44.3			$	44.3
Adjusted net income (loss):
Adjusted net income (loss)	$	(20.4	)		$	14.9
Unrealized gain (loss) on derivatives, net	(30.7		)		1.5
Tax effect of above adjustments	11.7				(0.6		)
Net income (loss)	$	(39.4	)		$	15.8
Adjusted EBITDA to net income (loss):
Adjusted EBITDA	$	61.1			$	75.5
Unrealized gain (loss) on derivatives, net	(30.7		)		1.5
Interest expense, net	(13.4		)		(10.4		)
Income tax provision	21.5				(9.5		)
Impairment of natural gas and crude oil properties	(46.5		)		(0.7		)
Depreciation, depletion and amortization	(30.2		)		(39.8		)
Accretion of asset retirement obligations	(1.2		)		(0.8		)
Net income (loss)	$	(39.4	)		$	15.8
Adjusted EBITDA to net cash from operating activities:
Adjusted EBITDA	$	61.1			$	75.5
Interest expense, net	(13.4		)		(10.4		)
Exploratory dry hole costs	0.1				—
Stock-based compensation	2.6				1.9
Amortization of debt discount and issuance costs	1.8				1.6
Gain on sale of properties and equipment	—				(20.5		)
Other	0.2				1.6
Changes in assets and liabilities	(8.1		)		(5.4		)
Net cash from operating activities	$	44.3			$	44.3

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Market-Sensitive Instruments and Risk Management

We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.

Interest Rate Risk

Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our senior notes and convertible senior notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.

As of March 31, 2013, our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of March 31, 2013 was $5.9 million with an average interest rate of 0.1%. The $5.9 million represents our aggregate bank balances, which includes checks issued and outstanding. Based on a sensitivity analysis of our interest bearing deposits as of March 31, 2013, it was estimated that if market interest rates would have increased or decreased by 1%, the impact on interest income for the three months ended March 31, 2013 would have been immaterial.

As of March 31, 2013, excluding the $18.7 million irrevocable standby letters of credit, we had outstanding borrowings on our corporate bank credit facility of $57 million and, representing our proportionate share, $28.8 million on PDCM's bank credit facility. We estimate that if market interest rates would have increased or decreased by 1%, interest expense for the three months ended March 31, 2013 would have changed by approximately $0.2 million.

    

Commodity Price Risk

We are exposed to the potential risk of loss from adverse changes in the market price of natural gas, NGLs and crude oil. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments allow us to predict with greater certainty the effective natural gas and crude oil prices to be received for our hedged production as it is produced. We believe that our established derivative policies and procedures are effective in achieving our risk management objectives.

 

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The following table presents our derivative positions (excluding the derivative positions designated to our affiliated partnerships) related to natural gas and crude oil sales in effect as of March 31, 2013:

		Floors							Collars											Fixed-Price Swaps							CIG Basis Protection Swaps
Commodity/ Index/ Maturity Period		Quantity (BBtu) (1)			Weighted- Average Contract Price				Quantity (Gas - BBtu (1)  Oil - MBbls)			Weighted-Average Contract Price								Quantity (Gas - BBtu (1)  Oil - MBbls)			Weighted- Average Contract Price				Quantity (BBtu) (1)			Weighted- Average Contract Price				Fair Value March 31, 2013 (2) (in thousands)
												Floors				Ceilings
Natural Gas
NYMEX
2013		3,480.0			$	6.16			—			$	—			$	—			17,618.6			$	4.59			17,488.2			$	(0.83	)		$	5,431.9
2014		—			—				—			—				—				19,937.5			4.07				8,830.0			(0.22		)		(2,878.1		)
2015		720.0			4.00				—			—				—				12,435.0			4.00				—			—				(4,108.5		)
2016		—			—				—			—				—				7,920.0			3.89				—			—				(3,659.1		)
CIG
2013		—			—				170.0			4.00				5.45				—			—				—			—				50.5
2014		—			—				1,115.0			4.50				5.67				4,828.0			4.00				—			—				982.0
2015		—			—				1,040.0			4.50				5.67				2,730.0			4.01				—			—				490.6
PEPL
2013		—			—				—			—				—				680.4			6.18				—			—				1,540.2
Total Natural Gas (3)		4,200.0							2,325.0											66,149.5							26,318.2							(2,150.5		)
Crude Oil
NYMEX
2013		—			—				847.0			80.48				103.46				963.0			97.66				—			—				36.9
2014		—			—				1,032.0			82.83				102.55				2,150.0			91.63				—			—				(1,647.6		)
2015		—			—				36.0			90.00				106.15				540.0			90.09				—			—				576.0
Total Crude Oil		—							1,915.0											3,653.0							—							(1,034.7		)
Total Natural Gas and Crude Oil																																		$	(3,185.2	)

_____________

(1)	A standard unit of measurement for natural gas (one BBtu equals one MMcf).

(2)	Approximately 31.1% of the fair value of our derivative assets and 5.7% of our derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the condensed consolidated financial statements included elsewhere in this report.

(3)

Pursuant to a purchase and sale agreement entered into on February 4, 2013, approximately 20,563 BBtu of natural gas hedging positions as of March 31, 2013 will be assumed by certain affiliates of Caerus upon the closing of the planned sale. There can be no assurance we will be successful in closing such divestiture. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, to our condensed consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture of certain of our natural gas properties.

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The following table presents monthly average NYMEX and CIG closing prices for natural gas and crude oil for the periods identified, as well as average sales prices we realized for the respective commodities:

	Three Months Ended				Year Ended
	March 31, 2013				December 31, 2012
Average Index Closing Price:
Natural gas (per MMBtu)
CIG	$	3.21			$	2.58
NYMEX	3.34				2.79
Crude oil (per Bbl)
NYMEX	$	93.41			$	94.92
Average Sales Price Realized:
Excluding realized derivative gains (losses)
Natural gas (per Mcf)	$	3.09			$	2.63
Crude oil (per Bbl)	86.96				87.27
Including realized derivative gains (losses)
Natural gas (per Mcf)	$	4.85			$	5.75
Crude oil (per Bbl)	87.67				87.02

Based on a sensitivity analysis as of March 31, 2013, it was estimated that a 10% increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have derivatives in place, including those designated to our affiliated partnerships, would have resulted in a decrease in fair value of $72.9 million; whereas a 10% decrease in prices would have resulted in an increase in fair value of $71.1 million. Excluding the derivatives designated to our affiliated partnerships, the same 10% increase or decrease in natural gas and crude oil prices would have resulted in a decrease in fair value of $72.5 million and an increase in fair value of $70.7 million, respectively.

See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis.

Our Oil and Gas Exploration and Production segment's natural gas, NGLs and crude oil sales are concentrated with a few predominately large customers. This concentrates the significance of our credit risk exposure to a small number of large customers. Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions and end-users in various industries. We monitor their creditworthiness through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. To date, we have had no material counterparty default losses in either of our Oil and Gas Exploration and Production or Gas Marketing segments.

Our derivative financial instruments may expose us to the credit risk of nonperformance by the instrument's contract counterparty. We use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. We monitor their creditworthiness through our credit committee which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. To date, we have had no material counterparty default losses from our derivative financial instruments. See Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included in this report for more detail on our derivative financial instruments.

Disruption in the credit market may have a significant adverse impact on a number of financial institutions. We monitor the creditworthiness of the financial institutions with which we transact, giving consideration to the reports of credit agencies and their related ratings. While we believe that our monitoring procedures are sufficient and customary, no amount of analysis can assure performance by a financial institution.

Disclosure of Limitations

Because the information above included only those exposures that existed at March 31, 2013, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time, and interest rates and commodity prices at the time.

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PDC ENERGY, INC.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of March 31, 2013, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e).

Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2013.

Changes in Internal Control over Financial Reporting

During the three months ended March 31, 2013, we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

Information regarding our legal proceedings can be found in Note 9, Commitments and Contingencies – Litigation, to our condensed consolidated financial statements included elsewhere in this report.

ITEM 1A. RISK FACTORS

We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under Item 1A, Risk Factors, of our 2012 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC. There have been no material changes from the risk factors previously disclosed in our 2012 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

    

    

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Period		Total Number of Shares Purchased (1)			Average Price Paid per Share				Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs			Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 - 31, 2013		8,403			$	36.56			—			—
February 1 - 28, 2013		664			46.64				—			—
March 1 - 31, 2013		7,280			49.87				—			—
Total first quarter purchases		16,347			42.90

__________

(1)	Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES - None.

ITEM 4. MINE SAFETY DISCLOSURES - Not applicable.

ITEM 5. OTHER INFORMATION - None.

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Exhibits Index

Incorporated by Reference

Exhibit

SEC File

Filed

Number

Exhibit Description

Form

Number

Exhibit

Filing Date

Herewith

10.1

Purchase and Sale Agreement by and among the Company, affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated February 4, 2013.

X

31.1

Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

31.2

Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

32.1*

Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

* Furnished herewith.

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PDC ENERGY, INC.

SIGNATURES

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

	PDC Energy, Inc.
	(Registrant)
Date: May 1, 2013	/s/ James M. Trimble
	James M. Trimble
	Chief Executive Officer and President
	(principal executive officer)
	/s/ Gysle R. Shellum
	Gysle R. Shellum
	Chief Financial Officer
	(principal financial officer)
	/s/ R. Scott Meyers
	R. Scott Meyers
	Chief Accounting Officer
	(principal accounting officer)

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