Edgar Filing: PDC ENERGY, INC.

PDCE 2014 3.31 10Q

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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, 2014

£ 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: 35,793,603 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 18, 2014.

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PDC ENERGY, INC.

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	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	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	34

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
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 crude oil, natural gas and natural gas liquids (“NGLs”) reserves; future production (including the components of such production), sales, expenses, cash flows and liquidity; our evaluation method of our customers' and derivative counterparties' credit risk is appropriate; expected 2014 production; anticipated capital projects, expenditures and opportunities; future exploration, drilling and development activities; our drilling programs and number of locations; expected timing of additional drilling rigs in the Wattenberg Field and Utica Shale; the effect of additional midstream facilities and services; availability of sufficient funding for our 2014 capital program and sources of that funding; expected 2014 capital budget allocations; acquisitions of additional acreage and other future transactions; the impact of high line pressures; compliance with debt covenants; expected funding sources for conversion of our 3.25% convertible senior notes due 2016; impact of litigation on our results of operations and financial position; effectiveness of our derivative program in providing a degree of price stability; that we do not expect to pay dividends in the foreseeable future; our expected tax liability for uncertain positions to decrease to zero in the next 12 months; the outcome of the May 2014 borrowing base redetermination; 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 crude oil, natural gas and NGLs, 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 worldwide production volumes and demand, including economic conditions that might impact demand;


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


•	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 value of our crude oil, natural gas and NGLs 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 being greater than expected;


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


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


•	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 Utica Shale, and the impact of these facilities and regional capacity on the prices we receive for our production;


•	timing and receipt of necessary regulatory permits;


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


•	our future cash flows, liquidity and financial condition;


•	competition within the oil and gas industry;


•	availability and cost of capital;


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


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


•	effect of crude oil and natural gas 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;


•	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, 2013 ("2013 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 20, 2014, 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 the 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

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any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

REFERENCES

Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" 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 PDC Mountaineer, LLC ("PDCM"), a joint venture currently owned 50% each by PDC and Lime Rock Partners, LP. Unless the context otherwise requires, references in this report to "Appalachian Basin" refer to our operations in the Utica Shale in Ohio and the Marcellus Shale in West Virginia and Pennsylvania, including 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, 2014			December 31, 2013
Assets
Current assets:
Cash and cash equivalents	$	147,194		$	193,243
Restricted cash	2,215			2,214
Accounts receivable, net	104,256			94,085
Accounts receivable affiliates	8,252			6,614
Fair value of derivatives	827			2,572
Deferred income taxes	25,795			22,374
Prepaid expenses and other current assets	5,063			4,711
Total current assets	293,602			325,813
Properties and equipment, net	1,725,792			1,656,230
Fair value of derivatives	2,566			5,601
Other assets	43,208			37,559
Total Assets	$	2,065,168		$	2,025,203

Liabilities and Shareholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	106,501		$	109,555
Accounts payable affiliates	—			41
Production tax liability	22,094			23,421
Fair value of derivatives	29,214			15,515
Funds held for distribution	39,927			32,578
Current portion of long-term debt	105,947			—
Accrued interest payable	19,846			9,251
Other accrued expenses	16,306			23,059
Total current liabilities	339,835			213,420
Long-term debt	561,250			656,990
Deferred income taxes	120,552			118,767
Asset retirement obligation	39,297			39,872
Fair value of derivatives	3,467			3,015
Other liabilities	32,631			25,545
Total liabilities	1,097,032			1,057,609

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, 35,778,057 and 35,675,656 issued as of March 31, 2014 and December 31, 2013, respectively	358			357
Additional paid-in capital	677,366			674,211
Retained earnings	291,140			293,267
Treasury shares - at cost, 14,897 and 5,508 as of March 31, 2014 and December 31, 2013, respectively	(728		)	(241		)
Total shareholders' equity	968,136			967,594
Total Liabilities and Shareholders' Equity	$	2,065,168		$	2,025,203

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,
	2014			2013
Revenues
Crude oil, natural gas and NGLs sales	$	129,844		$	79,439
Sales from natural gas marketing	26,937			13,670
Commodity price risk management loss, net	(27,155		)	(22,355		)
Well operations, pipeline income and other	636			1,072
Total revenues	130,262			71,826
Costs, expenses and other
Production costs	21,204			15,858
Cost of natural gas marketing	26,870			13,736
Exploration expense	307			1,689
Impairment of crude oil and natural gas properties	979			46,459
General and administrative expense	23,612			15,115
Depreciation, depletion, and amortization	46,639			27,949
Accretion of asset retirement obligations	861			1,148
(Gain) loss on sale of properties and equipment	725			(38		)
Total cost, expenses and other	121,197			121,916
Income (loss) from operations	9,065			(50,090		)
Interest expense	(12,830		)	(13,357		)
Interest income	251			—
Loss from continuing operations before income taxes	(3,514		)	(63,447		)
Provision for income taxes	1,387			22,492
Loss from continuing operations	(2,127		)	(40,955		)
Income from discontinued operations, net of tax	—			1,537
Net loss	$	(2,127	)	$	(39,418	)

Earnings per share:
Basic
Loss from continuing operations	$	(0.06	)	$	(1.35	)
Income from discontinued operations, net of tax	—			0.05
Net loss	$	(0.06	)	$	(1.30	)

Diluted
Loss from continuing operations	$	(0.06	)	$	(1.35	)
Income from discontinued operations, net of tax	—			0.05
Net loss	$	(0.06	)	$	(1.30	)

Weighted-average common shares outstanding:
Basic	35,690			30,270
Diluted	35,690			30,270

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,
	2014			2013
Cash flows from operating activities:
Net loss	$	(2,127	)	$	(39,418	)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled derivatives	18,931			30,721
Depreciation, depletion and amortization	46,639			30,207
Impairment of crude oil and natural gas properties	979			46,462
Accretion of asset retirement obligation	861			1,245
Stock-based compensation	3,847			2,602
(Gain) loss on sale of properties and equipment	725			(38		)
Amortization of debt discount and issuance costs	1,709			1,752
Deferred income taxes	(1,636		)	(21,150		)
Other	(272		)	(36		)
Changes in assets and liabilities	10,835			(8,085		)
Net cash from operating activities	80,491			44,262
Cash flows from investing activities:
Capital expenditures	(135,758		)	(61,873		)
Proceeds from acquisition adjustments	—			7,579
Proceeds from sale of properties and equipment	769			38
Net cash from investing activities	(134,989		)	(54,256		)
Cash flows from financing activities:
Proceeds from revolving credit facility	9,250			95,500
Repayment of revolving credit facility	—			(85,000		)
Other	(801		)	(469		)
Net cash from financing activities	8,449			10,031
Net change in cash and cash equivalents	(46,049		)	37
Cash and cash equivalents, beginning of period	193,243			2,457
Cash and cash equivalents, end of period	$	147,194		$	2,494

Supplemental cash flow information:
Cash payments for:
Interest, net of capitalized interest	$	1,159		$	1,196
Income taxes	1,800			2
Non-cash investing activities:
Change in accounts payable related to purchases of properties and equipment	$	(10,978	)	$	8,413
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals	137			98

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2014

(Unaudited)

NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy, Inc. is a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and the Marcellus Shale in northern West Virginia. Our operations in the Wattenberg Field are focused on the liquid-rich horizontal Niobrara and Codell plays. We are currently focusing our Ohio development in the liquid-rich portion of the Utica Shale play. As of March 31, 2014, we owned an interest in approximately 2,900 gross wells. 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 PDCM and our 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 presentation 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 2013 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 2014 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. 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 Standard

On January 1, 2014, we adopted changes issued by the Financial Accounting Standards Board ("FASB") regarding the accounting for income taxes. The change provides clarification on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. Adoption of these changes had no impact on the condensed consolidated financial statements.

Recently Issued Accounting Standard

In April 2014, the FASB issued changes related to the criteria for determining which disposals can be presented as discontinued operations and modified related disclosure requirements. Under the new pronouncement, a discontinued operation is defined as a disposal of a component of an organization that represents a strategic shift and that has a major effect on the organization's operations and financial results. These changes are to be applied prospectively for new disposals or components of our business classified as held for sale during interim and annual periods beginning after December 15, 2014, with early adoption permitted. We are currently evaluating the impact these changes will have on our 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. 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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

Derivative Financial Instruments. 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, crude oil and natural gas 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 and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our crude oil and natural gas 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, 2014								December 31, 2013
	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	$	1,810		$	1,498	$	3,308		$	5,325		$	2,385	$	7,710
Basis protection derivative contracts	85			—		85			463			—		463
Total assets	1,895			1,498		3,393			5,788			2,385		8,173
Liabilities:
Commodity-based derivative contracts	31,166			1,393		32,559			17,537			988		18,525
Basis protection derivative contracts	122			—		122			5			—		5
Total liabilities	31,288			1,393		32,681			17,542			988		18,530
Net asset (liability)	$	(29,393	)	$	105	$	(29,288	)	$	(11,754	)	$	1,397	$	(10,357	)

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



		Three Months Ended March 31,
		2014			2013
	(in thousands)
Fair value, net asset, beginning of period		$	1,397		$	13,669
Changes in fair value included in statement of operations line item:
Commodity price risk management loss, net		(1,395		)	(2,731		)
Sales from natural gas marketing		(22		)	(16		)
Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net		119			(3,234		)
Sales from natural gas marketing		6			(25		)
Fair value, net asset end of period		$	105		$	7,663

Net change in fair value of unsettled derivatives included in statement of operations line item:
Commodity price risk management loss, net		$	(1,531	)	$	(2,739	)
Sales from natural gas marketing		(5		)	(16		)
Total		$	(1,536	)	$	(2,755	)

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input.

The portion of our long-term debt related to our revolving credit facility, as well as our proportionate share of PDCM's credit facility and second lien term loan, approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, as of March 31, 2014, we estimate the fair value of the portion of our long-term debt related to our 3.25% convertible senior notes due 2016 to be $184.1 million, or 160.0% of par value, and the portion related to our 7.75% senior notes due 2022 to be $551.3 million, or 110.3% 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.

Concentration of Risk

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 relating to our derivative arrangements. 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 at March 31, 2014, taking into account the estimated likelihood of nonperformance.

The following table presents the counterparties that expose us to credit risk as of March 31, 2014 with regard to our derivative assets:



Counterparty Name	Fair Value of Derivative Assets
	(in thousands)
Wells Fargo Bank, N.A. (1)	$	904
Bank of Montreal (1)	716
Bank of Nova Scotia (1)	425
JP Morgan Chase Bank, N.A (1)	380
Other lenders in our revolving credit facility	756
Various (2)	212
Total	$	3,393

__________

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

(2)Represents a total of 30 counterparties.

NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS

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


•	For crude oil and natural gas 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; and


•	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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of March 31, 2014, we had derivative instruments, which were comprised of collars, fixed-price swaps, basis protection swaps and physical sales and purchases, in place for a portion of our anticipated production through 2017 for a total of 58,541 BBtu of natural gas and 7,687 MBbls of crude oil. The majority of our derivative contracts are entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices.

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. 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.

The following table presents the location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets as of March 31, 2014 and December 31, 2013:



			Fair Value
Derivatives instruments:		Balance sheet line item	March 31, 2014		December 31, 2013
			(in thousands)
Derivative assets:	Current
	Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	$	552	$	2,016
	Related to natural gas marketing	Fair value of derivatives	275		361
	Basis protection contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	—		195
			827		2,572
	Non-current
	Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	2,214		5,055
	Related to natural gas marketing	Fair value of derivatives	202		278
	Basis protection contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	150		268
			2,566		5,601
Total derivative assets			$	3,393	$	8,173

Derivative liabilities:	Current
	Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	$	28,921	$	15,263
	Related to natural gas marketing	Fair value of derivatives	171		247
	Basis protection contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	120		—
	Related to natural gas marketing	Fair value of derivatives	2		5
			29,214		15,515
	Non-current
	Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	3,302		2,782
	Related to natural gas marketing	Fair value of derivatives	165		233
			3,467		3,015
Total derivative liabilities			$	32,681	$	18,530

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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,
Condensed consolidated statement of operations line item	2014			2013
	(in thousands)
Commodity price risk management loss, net
Net settlements	$	(8,240	)	$	8,474
Net change in fair value of unsettled derivatives	(18,915		)	(30,829		)
Total commodity price risk management loss, net	$	(27,155	)	$	(22,355	)
Sales from natural gas marketing
Net settlements	$	(476	)	$	201
Net change in fair value of unsettled derivatives	(312		)	(968		)
Total sales from natural gas marketing	$	(788	)	$	(767	)
Cost of natural gas marketing
Net settlements	$	535		$	(162	)
Net change in fair value of unsettled derivatives	296			1,076
Total cost of natural gas marketing	$	831		$	914

All of our financial 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. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets.

The following table reflects the impact of netting agreements on gross derivative assets and liabilities as of March 31, 2014 and December 31, 2013:



As of March 31, 2014	Derivatives instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	3,393	$	(2,164	)	$	1,229

Liability derivatives:
Derivative instruments, at fair value	$	32,681	$	(2,164	)	$	30,517



As of December 31, 2013	Derivatives instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	8,173	$	(5,623	)	$	2,550

Liability derivatives:
Derivative instruments, at fair value	$	18,530	$	(5,623	)	$	12,907

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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 (DD&A):



	March 31, 2014			December 31, 2013
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	1,876,762		$	1,784,466
Unproved	308,865			307,203
Total crude oil and natural gas properties	2,185,627			2,091,669
Pipelines and related facilities	21,597			21,781
Equipment and other	29,439			29,246
Land and buildings	13,617			13,617
Construction in progress	75,447			53,810
Properties and equipment, at cost	2,325,727			2,210,123
Accumulated DD&A	(599,935		)	(553,893		)
Properties and equipment, net	$	1,725,792		$	1,656,230

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



	Three Months Ended March 31,
	2014		2013
	(in thousands)
Continuing operations:
Impairment of proved properties	$	—	$	45,000
Impairment of individually significant unproved properties	—		154
Amortization of individually insignificant unproved properties	979		1,305
Total continuing operations	979		46,459
Discontinued operations:
Amortization of individually insignificant unproved properties	—		3
Total discontinued operations	—		3
Total impairment of crude oil and natural gas properties	$	979	$	46,462

During the three months ended March 31, 2013, we recognized an impairment charge of approximately $45.0 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania previously owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. The impairment charge was included in the statement of operations line item impairment of crude oil and natural gas properties. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties.

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 rate for continuing operations for the three months ended March 31, 2014 was a 39.5% benefit on loss compared to a 35.5% benefit on loss for the three months ended March 31, 2013. The effective tax rate for the three months ended March 31, 2014 is based upon a full year forecasted tax provision on income and is greater than the statutory rate primarily due to nondeductible officers' compensation, partially offset by percentage depletion deductions. For the three months ended March 31, 2013, the nondeductible item for officers' compensation exceeded our deduction for percentage depletion, thereby reducing our tax benefit rate. Additionally, state statutory limits on the utilization of

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

our net operating losses resulted in a reduced state tax benefit for the three months ended March 31, 2013. There were no significant discrete items recorded during the three months ended March 31, 2014 or 2013.

As of March 31, 2014, our gross liability for unrecognized tax benefits continues to be immaterial and was unchanged from the amount recorded at December 31, 2013. We expect our remaining liability for uncertain tax positions to decrease to zero in the next 12 months due to the expiration of the statute of limitations.

As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under examination. We continue voluntary participation in the Internal Revenue Service’s Compliance Assurance Program for the 2013 and 2014 tax years. We received a full acceptance “no change” notice from the IRS for our filed 2012 federal tax return.

NOTE 7 - LONG-TERM DEBT

Long-term debt consists of the following:



	March 31, 2014			December 31, 2013
	(in thousands)
Senior notes:
3.25% Convertible senior notes due 2016:
Principal amount	$	115,000		$	115,000
Unamortized discount	(9,053		)	(10,010		)
3.25% Convertible senior notes due 2016, net of discount	105,947			104,990
7.75% Senior notes due 2022	500,000			500,000
Total senior notes	605,947			604,990
Credit facilities:
Corporate	—			—
PDCM	46,250			37,000
Total credit facilities	46,250			37,000
PDCM second lien term loan	15,000			15,000
Total debt	667,197			656,990
Less: Current portion of long-term debt	105,947			—
Long-term debt	$	561,250		$	656,990

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 "Convertible Notes") in a private placement to qualified institutional buyers. Interest is payable semi-annually in arrears on each May 15 and November 15. We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based upon the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued the Convertible 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 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.

The Convertible Notes became convertible at the option of holders beginning April 1, 2014. The conversion right was triggered on March 20, 2014, when the closing sale price of our common stock on the NASDAQ Global Select Market exceeded $55.12 (130% of the applicable conversion price) for the 20th trading day in the 30 consecutive trading days ending on March 31, 2014. In the event a holder elects to convert its note, we expect to fund any cash settlement of any such conversion from working capital and/or borrowings under our revolving credit facility. Through May 6, 2014, no holders of the Convertible Notes have elected to convert their notes. As a result of the Convertible Notes becoming convertible, we have included the carrying value of the Convertible Notes, net of discount, in the current portion of long-term debt on our condensed consolidated balance sheet as of March 31, 2014. We will reassess the convertibility of the Convertible Notes, and the related balance sheet classification, on a quarterly basis. In the event that a holder exercises the right to convert its note, we will write-off a ratable portion of the remaining debt issuance costs and unamortized discount to interest expense. Based on a March 31, 2014 stock price of $62.26, the “if-converted” value of the Convertible Notes exceeded the principal amount by approximately $53.9 million.

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 buyers. Interest on the 2022 Senior Notes is payable semi-

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

annually in arrears on each April 15 and October 15. The indenture governing the notes contains customary restrictive incurrence 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, 2014, we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the next 12-month period.

Credit Facilities

Revolving Credit Facility. In May 2013, we entered into a Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. This agreement amends and restates the credit agreement dated November 2010 and expires in May 2018. The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. As of March 31, 2014, the borrowing base was $450 million. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our and our subsidiaries' crude oil and natural gas interests, excluding proved reserves attributable to PDCM and our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Neither PDCM nor our affiliated partnerships are guarantors of our obligations under the revolving credit facility. We had no outstanding draws on our revolving credit facility as of March 31, 2014 or December 31, 2013.

As of March 31, 2014, Riley Natural Gas, a wholly owned subsidiary of PDC, had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit reduces the amount of available funds under our revolving credit facility by an equal amount. The letter of credit expires in September 2014. As of March 31, 2014, the available funds under our revolving credit facility, including a reduction for the $11.7 million irrevocable standby letter of credit in effect, was $438.3 million.

The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00.

As of March 31, 2014, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period.

PDCM Credit Facility. PDCM has a credit facility dated April 2010, as amended in February 2014, with a borrowing base of $105 million, of which our proportionate share is approximately $53 million. The maximum allowable facility amount is $400 million. No principal payments are required until the credit agreement expires in April 2017, 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 borrowing base is subject to size redetermination semi-annually 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 credit facility is utilized by PDCM for the exploration and development of its Marcellus Shale assets. In February 2014, PDCM entered into a Sixth Amendment to Credit Agreement. The amendment increased the amount of future production from proved, developed and producing properties that is permitted to be hedged.

The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests that must be met on a quarterly basis. The financial tests, 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 4.25 to 1.0 (declining to 4.0 to 1.0 on July 1, 2014) and to maintain a minimum interest coverage ratio of 2.5 to 1.0. As of March 31, 2014, our proportionate share of PDCM's outstanding credit facility balance was $46.3 million compared to $37.0 million as of December 31, 2013. The weighted-average borrowing rate on PDCM's credit facility was 3.4% per annum as of March 31, 2014, compared to 3.7% as of December 31, 2013.

As of March 31, 2014, PDCM was in compliance with all credit facility covenants and expects to remain in compliance throughout the next 12-month period.

PDCM Second Lien Term Loan

In July 2013, PDCM entered into a Second Lien Credit Agreement ("Term Loan Agreement") with Wells Fargo Energy Capital as administrative agent and a syndicate of other lenders party thereto. The aggregate commitment under the Term Loan Agreement is $30 million, of which our proportionate share is $15 million. The aggregate commitment may increase periodically up to a maximum of $75 million, as PDCM's reserve value increases and the covenants under the Term Loan Agreement allow. The Term Loan Agreement matures in October 2017. Amounts borrowed accrue interest, at PDCM's discretion, at either an alternative base rate plus a margin of 6% per annum or an adjusted LIBOR for the interest period in effect plus a margin of 7% per annum. As of March 31, 2014, amounts borrowed and outstanding on the Term Loan Agreement were $30.0 million, of which our proportionate share is $15.0 million. The weighted-average interest rate on the term loan was 8.5% per annum as of both March 31, 2014 and December 31, 2013.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The Term Loan Agreement contains financial covenants, as defined in the agreement, that must be met on a quarterly basis, including 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, to maintain a minimum interest coverage ratio of 2.25 to 1.0 and a present value of future net revenues to total debt ratio of 1.50 to 1.00.

As of March 31, 2014, PDCM was in compliance with all Term Loan Agreement covenants and expects to remain in compliance throughout the next 12-month period.

NOTE 8 - ASSET RETIREMENT OBLIGATIONS

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



	Amount
	(in thousands)

Balance at beginning of period, January 1	$	41,030
Obligations incurred with development activities	137
Accretion expense	861
Revisions in estimated cash flows	(12		)
Obligations discharged with divestitures of properties and asset retirements	(1,561		)
Balance end of period, March 31	40,455
Less: Current portion	(1,158		)
Long-term portion	$	39,297

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Firm Transportation, Processing and Sales 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 or not the required volumes are delivered. 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 as of March 31, 2014:



	For the Twelve Months Ending March 31,
Area	2015		2016		2017		2018		2019 and Through Expiration		Total		Expiration Date

Volume (MMcf)
Marcellus Shale	19,072		19,361		20,987		20,987		120,161		200,568		January 31, 2026
Utica Shale	2,623		2,745		2,737		2,737		14,611		25,453		July 22, 2023
Total	21,695		22,106		23,724		23,724		134,772		226,021

Dollar commitment (in thousands)	$	7,323	$	7,429	$	7,745	$	7,287	$	36,807	$	66,591

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 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

Alleged Class Action Regarding 2010 and 2011 Partnership Purchases

In December 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. In June 2012, the court denied the Company's motion to dismiss. In January 2014, the plaintiffs were certified as a class by the court, subject to reconsideration in pre-trial motions which we have requested. A jury trial initially scheduled for May 20, 2014 has been rescheduled to begin July 1, 2014. We have held three mediation meetings with plaintiffs in the last few months; there can be no assurance, however, that these discussions will continue. We recorded an estimated liability of $3.3 million during the quarter ended March 31, 2014 for this litigation. We continue to believe we have good defenses to the asserted claims; however, it is reasonably possible that actual losses could be in excess of the amount accrued.

Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures designed to mitigate the risks of environmental contamination and related liabilities. 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, 2014 and December 31, 2013, we had accrued environmental liabilities in the amount of $3.2 million and $5.4 million, respectively, included in other accrued expenses on the condensed consolidated balance sheets. We are not aware of any environmental claims existing as of March 31, 2014 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.

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,
	2014			2013
	(in thousands)

Stock-based compensation expense	$	3,847		$	2,602
Income tax benefit	(1,462		)	(994		)
Net stock-based compensation expense	$	2,385		$	1,608

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.

In January 2014, the Compensation Committee awarded 88,248 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,
	2014			2013

Expected term of award	6 years			6 years
Risk-free interest rate	2.1		%	1.0		%
Expected volatility	65.6		%	65.5		%
Weighted-average grant date fair value per share	$	29.96		$	21.96

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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,
	2014					2013
	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,	190,763	$	33.77			118,832	$	30.80
Awarded	88,248	49.57				87,078	37.18
Outstanding at March 31,	279,011	38.76		8.6	6,555	205,910	33.50		8.9	3,310
Vested and expected to vest at March 31,	266,369	38.50		8.5	6,329	194,689	33.38		8.8	3,152
Exercisable at March 31,	109,920	32.71		7.6	3,248	56,430	31.04		8.0	1,046

Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our condensed consolidated statement of operations as of March 31, 2014 was $3.6 million. The cost is expected to be recognized over a weighted-average period of 2.3 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 years. The time-based shares vest ratably on each annual anniversary following the grant date if the participant is continuously employed.

In January 2014, the Compensation Committee awarded a total of 120,428 time-based restricted shares to our executive officers that vest ratably over a three-year period ending on January 16, 2017.

The following table presents the changes in non-vested time-based awards for the three months ended March 31, 2014:



	Shares		Weighted-Average Grant-Date Fair Value

Non-vested at December 31, 2013	651,781		$	36.36
Granted	126,102		49.62
Vested	(84,235	)	35.09
Forfeited	(15,466	)	36.59
Non-vested at March 31, 2014	678,182		38.98



	As of/Three Months Ended March 31,
	2014		2013
	(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	4,317	$	2,303
Total intrinsic value of time-based awards non-vested	42,224		34,572
Market price per common share as of March 31,	62.26		49.57
Weighted-average grant date fair value per share	49.62		36.82

Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our condensed consolidated statements of operations as of March 31, 2014 was $18.5 million. This cost is expected to be recognized over a weighted-average period of 2.1 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 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

In January 2014, the Compensation Committee awarded a total of 42,151 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 15 peer companies. The shares are measured over a three-year period ending on December 31, 2016 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,
	2014			2013

Expected term of award	3 years			3 years
Risk-free interest rate	0.8		%	0.4		%
Expected volatility	55.2		%	56.6		%
Weighted-average grant date fair value per share	$	56.87		$	49.04

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.

The following table presents the change in non-vested market-based awards during three months ended March 31, 2014:



	Shares	Weighted-Average Grant-Date Fair Value per Share

Non-vested at December 31, 2013	72,111	$	43.75
Granted	42,151	56.87
Non-vested at March 31, 2014	114,262	48.59



	As of/Three Months Ended March 31,
	2014		2013
	(in thousands, except per share data)

Total intrinsic value of market-based awards vested	$	—	$	—
Total intrinsic value of market-based awards non-vested	7,114		4,078
Market price per common share as of March 31,	62.26		49.57
Weighted-average grant date fair value per share	56.87		49.04

Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our condensed consolidated statement of operations as of March 31, 2014 was $3.5 million. This cost is expected to be recognized over a weighted-average period of 2.2 years.

NOTE 11 - EARNINGS PER SHARE

Basic earnings per share is computed by dividing net earnings 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 Notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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



	Three Months Ended March 31,
	2014	2013
	(in thousands)

Weighted-average common shares outstanding - basic	35,690	30,270
Weighted-average common shares and equivalents outstanding - diluted	35,690	30,270

We reported a net loss for the three months ended March 31, 2014 and 2013, respectively. 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.

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,
	2014	2013
	(in thousands)

Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	832	844
SARs	97	45
Stock options	3	3
Non-employee director deferred compensation	5	4
Convertible notes	614	48
Total anti-dilutive common share equivalents	1,551	944

In November 2010, we issued our Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible 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 upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the three months ended March 31, 2014 and 2013 as the effect would be anti-dilutive to our earnings per share.

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

Appalachian Basin. In October 2013, we executed a purchase and sale agreement for the sale of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties previously owned directly by us, as well as through our proportionate share of PDCM. The properties consisted of approximately 3,500 gross shallow producing wells, related facilities and associated leasehold acreage, limited to the Upper Devonian and shallower formations. Substantially all of the divestiture closed in December 2013 for aggregate consideration of approximately $20.6 million, of which our share of the proceeds was approximately $5.1 million, subject to certain post-closing adjustments. We received our proportionate share of cash proceeds of $0.9 million and recorded our proportionate share of a note receivable and account receivable from the buyer of $3.3 million and $0.8 million, respectively. Concurrent with the closing of the transaction, our $6.7 million irrevocable standby letter of credit and an agreement for firm transportation services was released and novated to the buyer. We retained all zones, formations and intervals below the Upper Devonian formation including the Marcellus Shale, Utica Shale and Huron Shale. The divestiture of these assets did not meet the requirements to be accounted for as discontinued operations.

Piceance Basin and NECO. In February 2013, we entered into a purchase and sale agreement pursuant to which we agreed to sell to certain affiliates of Caerus Oil and Gas LLC (“Caerus”) our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Additionally, certain firm transportation obligations and natural gas hedging positions were assumed by the buyer. In June 2013, this divestiture was completed with total consideration of approximately $177.6 million, with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million. Following the sale to Caerus, we do 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 the three months ended March 31, 2013. The sale of our other non-core Colorado oil and gas properties did not meet the requirements to be accounted for as discontinued operations.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents statement of operations data related to our discontinued operations for the Piceance Basin and NECO divestitures:



Condensed consolidated statements of operations - discontinued operations	Three Months Ended March 31, 2013

Revenues
Crude oil, natural gas and NGLs sales	$	10,274
Sales from natural gas marketing	450
Well operations, pipeline income and other	450
Total revenues	11,174

Costs, expenses and other
Production costs	5,393
Cost of natural gas marketing	454
Depreciation, depletion and amortization	2,258
Other	495
Total costs, expenses and other	8,600

Income from discontinued operations	2,574
Provision for income taxes	(1,037		)
Income from discontinued operations, net of tax	$	1,537

NOTE 13 - TRANSACTIONS WITH AFFILIATES

PDCM and Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by PDCM and our affiliated partnerships in the Appalachian Basin. Our cost of natural gas marketing includes $9.4 million and $3.7 million for the three months ended March 31, 2014 and 2013, respectively, related to the marketing of natural gas on behalf of PDCM and $0.3 million for the three months ended March 31, 2013 related to the marketing of natural gas on behalf of our affiliated partnerships.

Amounts due from/to the affiliated partnerships have historically been primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. Previously, we have entered into derivative instruments on behalf of our affiliated partnerships for their estimated production. In June 2013, all remaining derivative positions designated to our affiliated partnerships were liquidated prior to settlement. As a result, there were no amounts due from/to our affiliated partnerships related to derivative positions as of March 31, 2014.

We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $2.3 million and $3.4 million for the three months ended March 31, 2014 and March 31, 2013, 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,
Condensed consolidated statement of operations line item		2014		2013
	(in thousands)

Production costs		$	605	$	1,066
Exploration expense		—		105
General and administrative expense		556		515

NOTE 14 - BUSINESS SEGMENTS

We separate our operating activities into two segments: Oil and Gas Exploration and Production and 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 crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs 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 crude oil and natural gas properties, direct general and administrative expense and depreciation, depletion and amortization expense.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate, general and administrative purposes, as well as assets not specifically included in our two business segments.

The following tables present our segment information:



	Three Months Ended March 31,
	2014			2013
	(in thousands)
Segment revenues:
Oil and gas exploration and production	$	103,325		$	58,156
Gas marketing	26,937			13,670
Total revenues	$	130,262		$	71,826

Segment income (loss) before income taxes:
Oil and gas exploration and production	$	34,006		$	(33,702	)
Gas marketing	67			(66		)
Unallocated	(37,587		)	(29,679		)
Loss before income taxes	$	(3,514	)	$	(63,447	)



	March 31, 2014		December 31, 2013
	(in thousands)
Segment assets:
Oil and gas exploration and production	$	1,965,354	$	1,937,251
Gas marketing	28,366		20,342
Unallocated	71,448		67,610
Total assets	$	2,065,168	$	2,025,203

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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

Crude oil, natural gas and NGLs sales from continuing operations increased during the three months ended March 31, 2014 by $50.4 million, or 63%, compared to the three months ended March 31, 2013. The growth in crude oil, natural gas and NGLs sales was the result of increased production and higher commodity prices. Production of 2.4 MMboe from continuing operations for the three months ended March 31, 2014 represents an increase of 44% as compared to the three months ended March 31, 2013, primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. This translates to 26.7 Mboe per day during the three months ended March 31, 2014, compared to 18.5 Mboe per day during the three months ended March 31, 2013. Crude oil production from continuing operations increased 56% during the three months ended March 31, 2014, while NGLs production from continuing operations increased 59%. Our liquids percentage of total production from continuing operations was 59% during the three months ended March 31, 2014 compared to 54% during the three months ended March 31, 2013. Natural gas production from continuing operations increased 29% during the three months ended March 31, 2014 compared to the same prior year period.

Growth in financial metrics for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was as follows:


•	Adjusted net income of $9.6 million compared to an adjusted net loss of $20.4 million;


•	Adjusted cash flows from operations of $69.7 million compared to $52.4 million; and


•	Adjusted EBITDA of $76.5 million compared to $61.1 million.

Adjusted net income/loss, Adjusted cash flows from operations and Adjusted EBITDA are non-U.S. GAAP financial measures. See Non-U.S. GAAP Financial Measures and Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures.

Available liquidity as of March 31, 2014 was $591.7 million, including $7.0 million related to PDCM, compared to $647.0 million, including $16.1 million related to PDCM, as of December 31, 2013. Available liquidity is comprised of $147.2 million of cash and cash equivalents and $444.5 million available for borrowing under our revolving credit facilities. We believe we have sufficient liquidity to allow us to execute our expanded drilling program through 2014.

Operational Overview

Drilling Activities. During the three months ended March 31, 2014, we continued to execute our strategic plan of increasing our overall production and liquids mix by focusing our drilling operations primarily in the liquid-rich Wattenberg Field in Colorado and the emerging Utica Shale play in southeastern Ohio.

In the Wattenberg Field, we are currently running four drilling rigs and plan to bring on a fifth rig in the second quarter of 2014. During the three months ended March 31, 2014, we spudded 24 horizontal wells in the Wattenberg Field and turned in line 13 horizontal wells. We also participated in 13 gross, 2.5 net, horizontal non-operated drilling projects and turned in line 11 gross, 1.9 net, horizontal non-operated wells. In the Utica Shale, we are currently running one drilling rig and plan to bring on a second rig in the second half of 2014. We spudded three horizontal wells during the three months ended March 31, 2014 and turned in line two horizontal wells. In the Marcellus Shale, PDCM finalized drilling and completion operations on four horizontal wells that were in-process at December 31, 2013. Three of these wells were turned in line as of March 31, 2014 and the fourth was turned in line in April 2014.

2014 Operational Outlook

We expect our production for 2014 to range between 9.5 MMBoe to 10 MMBoe. Our 2014 capital budget of $647 million, which includes our $16 million share of PDCM's capital budget, is expected to be used primarily for development drilling and selective acquisitions of additional acreage. This budget includes $576 million of development capital and $71 million for leasehold acquisitions, exploration and other expenditures. 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.

Wattenberg Field. We expect to invest approximately $467 million in the Wattenberg Field in 2014, continuing with a four-rig drilling program with plans to add a fifth rig in the second quarter of 2014. We plan to spud 115 gross operated horizontal wells in the field, comprised of 59 horizontal Codell wells and 56 horizontal Niobrara wells, of which 92 are expected to be turned in line during 2014. Approximately $100 million of the total Wattenberg Field capital budget is expected to be allocated to non-operated projects. During the three months ended March 31, 2014, we invested approximately $87 million, or 19%, of our 2014 capital budget for the Wattenberg Field.

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Utica Shale. We expect to invest approximately $162 million in the Utica Shale in 2014 to spud 18 horizontal wells, comprised of eight wells in our northern acreage and 10 wells in our southern acreage, of which 12 are expected to be turned in line during 2014. A second drilling rig is expected to be deployed in the second half of 2014. The Utica capital budget includes approximately $30 million to acquire additional contiguous acreage. During the three months ended March 31, 2014, we invested approximately $28 million, or 17%, of our 2014 capital budget for the Utica Shale.

Marcellus Shale. PDCM's 2014 capital budget is $32 million, of which $16 million represents our share, and is expected to be utilized to finalize drilling and completion operations on horizontal wells that were in-process at December 31, 2013 and for midstream infrastructure. During the three months ended March 31, 2014, PDCM invested approximately $20 million, or 63%, of its 2014 capital budget for the Marcellus Shale, of which $10 million represents our share. PDCM's capital budget is expected to be funded by PDCM's operating activities and borrowing under its credit facility or other financing transactions. PDCM has elected to temporarily suspend its drilling activities in the Marcellus Shale.

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, in some cases, 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 liquidity measures or indicators 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 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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Results of Operations

Summary Operating Results

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



	Three Months Ended March 31,
	2014			2013		Percentage Change
	(dollars in millions, except per unit data)
Production (1)
Crude oil (MBbls)	1,042.9			668.3		56.1	%
Natural gas (MMcf)	5,878.3			4,549.8		29.2	%
NGLs (MBbls)	379.5			238.3		59.3	%
Crude oil equivalent (MBoe) (2)	2,402.1			1,665.0		44.3	%
Average MBoe per day	26.7			18.5		44.3	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	89.7		$	58.1	54.4	%
Natural gas	26.8			14.0		91.4	%
NGLs	13.3			7.3		82.2	%
Total crude oil, natural gas and NGLs sales	$	129.8		$	79.4	63.5	%

Net Settlements on Derivatives (3)
Natural gas	$	(3.9	)	$	8.0	*
Crude oil	(4.3		)	0.5		*
Total net settlements on derivatives	$	(8.2	)	$	8.5	(196.5	)%

Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	86.02		$	86.96	(1.1	)%
Natural gas (per Mcf)	4.56			3.09		47.6	%
NGLs (per Bbl)	35.18			30.48		15.4	%
Crude oil equivalent (per Boe)	54.05			47.71		13.3	%

Average Lifting Cost (per Boe) (4)
Wattenberg Field	$	4.10		$	3.79	8.2	%
Utica Shale	0.77			2.76		(72.1	)%
Marcellus Shale	1.34			5.07		(73.6	)%
Weighted-average	3.41			3.98		(14.3	)%

Natural Gas Marketing Contribution Margin (5)	$	—		$	—	*

Other Costs and Expenses
Exploration expense	$	0.3		$	1.7	(81.8	)%
Impairment of crude oil and natural gas properties	1.0			46.5		*
General and administrative expense	23.6			15.1		56.2	%
Depreciation, depletion and amortization	46.6			27.9		66.9	%

Interest Expense	$	12.8		$	13.4	(3.9	)%


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

Amounts may not recalculate due to rounding.

______________


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


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


(3)	Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives 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 net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities.

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Crude Oil, Natural Gas and NGLs Sales

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



	Three Months Ended March 31,
Production by Operating Region	2014	2013	Percentage Change
Crude oil (MBbls)
Wattenberg Field	952.6	650.7	46.4	%
Utica Shale	90.3	16.7	*
Appalachia-Marcellus Shale	—	0.9	(100.0	)%
Total	1,042.9	668.3	56.1	%
Natural gas (MMcf)
Wattenberg Field	3,315.0	2,975.5	11.4	%
Utica Shale	429.3	0.3	*
Appalachia-Marcellus Shale	2,134.0	1,574.0	35.6	%
Total	5,878.3	4,549.8	29.2	%
NGLs (MBbls)
Wattenberg Field	343.9	238.3	44.3	%
Utica Shale	35.6	—	*
Total	379.5	238.3	59.3	%
Crude oil equivalent (MBoe)
Wattenberg Field	1,848.9	1,385.0	33.5	%
Utica Shale	197.5	16.8	*
Appalachia-Marcellus Shale	355.7	263.2	35.1	%
Total	2,402.1	1,665.0	44.3	%


*	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 net settlements on derivatives)	2014		2013		Percentage Change
Crude oil (per Bbl)
Wattenberg Field	$	86.03	$	86.89	(1.0)%
Utica Shale	85.92		89.89		(4.4)%
Appalachia-Marcellus Shale	—		87.79		(100.0)%
Weighted-average price	86.02		86.96		(1.1)%
Natural gas (per Mcf)
Wattenberg Field	$	4.47	$	3.02	48.0%
Utica Shale	4.63		2.39		93.7%
Appalachia-Marcellus Shale	4.67		3.23		44.6%
Weighted-average price	4.56		3.09		47.6%
NGLs (per Bbl)
Wattenberg Field	$	32.63	$	30.48	7.1%
Utica Shale	59.83		—		*
Weighted-average price	35.18		30.48		15.4%
Crude oil equivalent (per Boe)
Wattenberg Field	$	58.41	$	52.55	11.2%
Utica Shale	60.15		89.62		(32.9)%
Appalachia-Marcellus Shale	28.04		19.59		43.1%
Weighted-average price	54.05		47.71		13.3%


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

Amounts may not recalculate due to rounding.

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For the three months ended March 31, 2014, crude oil, natural gas and NGLs sales revenue increased compared to the three months ended March 31, 2013 due to the following (in millions):



Increase in production	$	41.0
Increase in average natural gas price	8.6
Increase in average NGLs price	1.8
Decrease in average crude oil price	(1.0		)
Total increase in crude oil, natural gas and NGLs sales revenue	$	50.4

In recent years, our Wattenberg Field production has been adversely impacted by high line pressures on the gathering system operated by our primary third-party midstream service provider. Ongoing industry drilling activity in the area has resulted in an increase in volumes on the gathering system with an associated increase in system pressures. In addition, higher temperatures resulted in reduced system compressor efficiencies and further increased line pressures in the summer months. We, and other operators in the field, are working with the midstream service provider, who is implementing a multi-year facility expansion program. This expansion will significantly increase the long-term gathering and processing capacity of the system. Initial system improvements have already been implemented. In particular, the O’Connor (formerly known as LaSalle) gas plant commenced operations in October 2013 and was further expanded in early 2014 to accommodate additional system volumes. We have already experienced reductions in line pressure and an increase in system capacity throughput since the startup of the O’Connor gas plant. We will likely see increases in gathering line pressures as temperatures increase in the summer months, but we expect the system pressures to be at a lower level than was experienced in 2013 as a result of the recent midstream facility expansions. 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 additional facilities going forward is beyond our control.

Crude Oil, Natural Gas and NGLs Pricing. Our results of operations depend upon many factors, particularly the price of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs 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.

Crude oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials. We are currently pursuing various alternatives with respect to oil transportation, particularly in the Wattenberg Field, with a view toward improving pricing and takeaway capacity. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials. 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 the Wattenberg Field is based on CIG prices, adjusted for differentials, while natural gas produced in the Utica Shale and Appalachia-Marcellus Shale is based on NYMEX pricing, adjusted for differentials. Our price for NGLs produced in the Wattenberg Field is mainly based on prices from the Conway hub in Kansas where this production is marketed. The NGLs produced in the Utica Shale are sold based on month-to-month pricing in various markets.

We currently use the "net-back" method of accounting for crude oil, natural gas and NGLs production from the Wattenberg Field and crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation and gathering services. We sell our commodities 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. Natural gas and NGLs sales related to production from the Utica Shale and Marcellus Shale are recognized based on gross prices as the purchasers do not provide transportation, gathering and processing services and we recognize expenses relating to those services as production costs.

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Production Costs

Production costs include lease operating expenses, production taxes, transportation, gathering and processing costs 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,
	2014		2013
	(in millions)

Lease operating expenses	$	8.2	$	6.6
Production taxes	7.6		5.4
Transportation, gathering and processing expenses	2.2		1.6
Overhead and other production expenses	3.2		2.3
Total production costs	$	21.2	$	15.9
Total production costs per Boe	$	8.83	$	9.52

Lease operating expenses. The $1.6 million increase in lease operating expenses during the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was primarily due to an increase of $0.7 million for workover, compliance and maintenance related projects, an increase of $0.5 million for the rental of additional compressors used to accommodate high line pressures in the Wattenberg Field and an increase of $0.3 million in additional wages and employee benefits.

Production taxes. Production taxes are directly related to crude oil, natural gas and NGLs sales. The $2.2 million, or 41%, increase in production taxes for the three months ended March 31, 2014 compared to the three months ended March 31, 2013, was primarily related to the 63% increase in crude oil, natural gas and NGLs sales.

Transportation, gathering and processing expenses. The $0.6 million, or 37.5%, increase in transportation, gathering and processing expenses for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was primarily attributed to a $1.2 million increase in Utica gas transportation expenses offset by decreases of $0.3 million for compression expense resulting from the divestiture of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties and $0.2 million for Marcellus Shale firm transportation cost, net of a $0.4 million decrease in unutilized firm transportation expense.

Overhead and other production expenses. Overhead and other production expenses increased $0.9 million during the three months ended March 31, 2014 as compared to the three months ended March 31, 2013. The increase consisted of a $1.4 million increase in wages and employee benefits, mostly attributable to Utica Shale development. This increase was offset by a $0.4 million decrease in various other operating costs.

Commodity Price Risk Management, Net

Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled derivatives related to our crude oil and natural gas 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 net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net:



	Three Months Ended March 31,
	2014			2013
	(in millions)
Commodity price risk management loss, net:
Net settlements	$	(8.2	)	$	8.5
Net change in fair value of unsettled derivatives	(19.0		)	(30.9		)
Total commodity price risk management loss, net	$	(27.2	)	$	(22.4	)

Net settlements for the three months ended March 31, 2014 were primarily the result of higher crude oil and natural gas index prices at maturity of our derivative instruments compared to the respective strike prices. Negative settlements on our crude oil positions were $4.3 million, reflective of a weighted-average strike price of $91.84 compared to a weighted-average settlement price of $98.94. Negative settlements

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on natural gas, exclusive of basis swaps, were $3.7 million. This reflects a weighted-average strike price of $4.10 compared to a weighted-average settlement price of $4.95. Negative settlements on our basis swap positions were $0.2 million, as the negative basis differential between NYMEX and Columbia Gas Transmission basis was a weighted-average of $0.02 compared to a weighted-average strike price of $0.18 and the negative basis differential between NYMEX and CIG was a weighted-average of $0.14 compared to a weighted-average strike price of $0.22. The net change in fair value of unsettled derivatives for the three months ended March 31, 2014 includes a $4.8 million net asset increase in the beginning-of-period fair value of derivative instruments that settled during the period. The corresponding impact of settlement of these instruments is included in net settlements for the period as discussed above. The net change in fair value of unsettled derivatives for the three months ended March 31, 2014 also includes a $23.8 million decrease in the fair value of unsettled derivatives during the period, primarily related to the upward shift in the crude oil and natural gas forward curves.

Net settlements for the three months ended March 31, 2013 were mainly the result of lower natural gas and crude oil index prices at maturity of our derivative instruments compared to the respective strike prices, resulting in $12.2 million of positive settlements on our natural gas derivatives and $0.5 million of positive settlements on our crude oil derivatives. The positive settlements were offset in part by negative settlements of $4.2 million on our basis swap positions. The net change in fair value of unsettled derivatives for the three months ended March 31, 2013 includes a $9.1 million net asset reduction in the beginning-of-period fair value of derivative instruments that settled during the period and a $21.8 million decrease in the fair value of unsettled derivatives during the period, primarily related to the upward shift in the crude oil and natural gas forward curves.

We use various derivative instruments to manage fluctuations in crude oil and natural gas prices. We have in place a variety of collars, fixed-price swaps and basis swaps on a portion of our estimated crude oil and natural gas production. Because we sell all of our physical crude oil and natural gas 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 strike price, adjusted for differentials.

Natural Gas Marketing

Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices, cash settlements upon maturity of derivative instruments and the change in fair value of unsettled derivatives, 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,
	2014			2013
	(in millions)
Natural gas sales revenue	$	27.6		$	14.4
Net settlements from derivatives	(0.5		)	0.2
Net change in fair value of unsettled derivatives	(0.3		)	(1.0		)
Other	0.1			0.1
Total sales from natural gas marketing	26.9			13.7

Costs of natural gas purchases	27.3			14.2
Net settlements from derivatives	(0.5		)	0.2
Net change in fair value of unsettled derivatives	(0.3		)	(1.1		)
Other	0.4			0.4
Total costs of natural gas marketing	26.9			13.7

Natural gas marketing contribution margin	$	—		$	—

Natural gas sales revenue and cost of natural gas purchases increased in the three months ended March 31, 2014 compared to the three months ended March 31, 2013, mainly attributable to higher natural gas prices and production 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.

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Exploration Expense

The following table presents the major components of exploration expense:



	Three Months Ended March 31,
	2014		2013
	(in millions)

Geological and geophysical costs	$	—	$	0.5
Operating, personnel and other	0.3		1.2
Total exploration expense	$	0.3	$	1.7

Geological and geophysical costs. Geological and geophysical costs during the three months ended March 31, 2013 were primarily related to costs associated with 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 $0.9 million decrease during the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was primarily related to a reduction in Utica Shale personnel costs resulting from the reassignment of former exploration department personnel to other departments.

Impairment of Crude oil and Natural Gas Properties

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



	Three Months Ended March 31,
	2014		2013
	(in millions)

Impairment of proved properties	$	—	$	45.0
Impairment of individually significant unproved properties	—		0.2
Amortization of individually insignificant unproved properties	1.0		1.3
Total impairment of crude oil and natural gas properties	$	1.0	$	46.5

Impairment of proved properties. During the three months ended March 31, 2013, we recognized an impairment charge of approximately $45.0 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania previously owned directly by us, as well as through our proportionate share of PDCM and our affiliated partnerships. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. See Note 12, Assets Held for Sale, Divestitures and Discontinued Operations, included elsewhere in this report for additional information regarding these properties, including the closing of the sale of these properties.

General and Administrative Expense

General and administrative expense increased $8.5 million to $23.6 million for the three months ended March 31, 2014 compared to $15.1 million for the three months ended March 31, 2013. The increase was attributable to a $3.3 million charge recorded in 2014 representing our estimate of potential legal settlement charges related to class action litigation, a $2.8 million increase in payroll and employee benefits, of which $1.0 million was stock-based compensation, and a $1.5 million increase in professional and consulting costs.

Depreciation, Depletion and Amortization Expense

Crude oil and natural gas properties. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $45.2 million for the three months ended March 31, 2014 compared to $26.7 million for the three months ended March 31, 2013. The quarter-over-quarter increase was comprised of an increase of $6.7 million due to a higher weighted-average depreciation, depletion and amortization rate and an increase of $11.8 million due to higher production during the three months ended March 31, 2014.

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



	Three Months Ended March 31,
Operating Region/Area	2014		2013
	(per Boe)
Wattenberg Field	$	19.16	$	17.00
Utica Shale	32.56		—
Appalachia-Marcellus Shale	9.51		12.17
Total weighted-average	18.83		16.06

Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $1.4 million for the three months ended March 31, 2014 compared to $1.2 million for the three months ended March 31, 2013.

Gain (Loss) on Sale of Properties and Equipment

The loss on sale of properties and equipment of $0.7 million during the three months ended March 31, 2014 primarily relates to the sale of certain pipeline equipment and the divestiture of the partnerships' remaining assets and related liabilities relating to our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties.

Interest Expense

Interest expense decreased $0.6 million to $12.8 million for the three months ended March 31, 2014 compared to $13.4 million for the three months ended March 31, 2013. The quarter-over-quarter decrease was comprised of a $0.4 million decrease attributable to an increase in the interest expense capitalized during the three months ended March 31, 2014 and a $0.2 million decrease due to having no outstanding balance on our revolving credit facility during the three months ended March 31, 2014 compared to an average outstanding balance of $62.9 million during the three months ended March 31, 2013.

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, 2014 compared to the three months ended March 31, 2013. The effective tax rate of 39.5% for the three months ended March 31, 2014 is based on forecasted pre-tax income for the year adjusted for permanent differences. The forecasted effective tax rate has been applied to the quarter-to-date pre-tax loss resulting in a tax benefit for the period. Because the estimate of full-year income may change from quarter to quarter, the estimated annual effective tax rate for any particular quarter may not have a meaningful relationship to pre-tax income or loss for the quarter.

Discontinued Operations

In February 2013, we entered into a purchase and sale agreement pursuant to which we agreed to sell to certain affiliates of Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Additionally, certain firm transportation obligations and natural gas hedging positions were assumed by Caerus. In June 2013, this divestiture was completed for total consideration of approximately $177.6 million, with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million. Following the sale to Caerus, we do 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 the three months ended March 31, 2013. The sale of our other non-core Colorado oil and gas properties did not meet the requirements to be accounted for as discontinued operations.

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 sale of our Piceance Basin, NECO and other non-core Colorado oil and gas properties.

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



Discontinued Operations		Three Months Ended March 31, 2013
Production
Crude oil (MBbls)		6.9
Natural gas (MMcf)		3,584.1
Crude oil equivalent (MBoe)		604.2

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Net Loss/Adjusted Net Income (Loss)

Net loss for the three months ended March 31, 2014 was $2.1 million compared to a net loss of $39.4 million for the three months ended March 31, 2013. Adjusted net income, a non-U.S. GAAP financial measure, for the three months ended March 31, 2014 was $9.6 million compared to an adjusted net loss of $20.4 million for the three months ended March 31, 2013. The quarter-over-quarter changes in net loss are discussed above, with the most significant changes related to the increase in crude oil, natural gas and NGLs sales and DD&A expense, and the decrease in impairment of crude oil and natural gas properties and loss from commodity price risk management activities in the current quarter. These same reasons for change similarly impacted adjusted net income (loss), with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes, as this amount is 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 debt and equity market transactions, asset sales and entrance into joint ventures, such as PDCM. In light of our current focus on the Wattenberg Field and the Utica Shale, we are considering various strategic alternatives for PDCM going forward. For the three months ended March 31, 2014, our primary sources of liquidity were net cash flows from operating activities of $80.5 million and the remaining cash from the August 2013 equity transaction noted below.

Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. 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. 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 three years or less, our debt covenants restrict us from entering into hedges that would exceed 85% of our expected future production from total proved reserves (proved developed producing, proved developed non-producing and proved undeveloped). For instruments that mature later than three years, but no more than our designated maximum maturity, our debt covenants limit our holdings to 85% 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, 2014, we had a working capital deficit of $46.2 million compared to a surplus of $112.4 million at December 31, 2013. The working capital deficit as of March 31, 2014 is a direct result of the reclassification of our 3.25% convertible senior notes due 2016 (the "Convertible Notes") to current liabilities and a decrease in cash and cash equivalents.

We ended March 2014 with cash and cash equivalents of $147.2 million and availability under our revolving credit facility and our proportionate share of PDCM's credit facility of $444.5 million, for a total liquidity position of $591.7 million, compared to $647.0 million at December 31, 2013. The decrease in liquidity of $55.3 million, or 8.5%, was primarily attributable to capital expenditures of $135.8 million during the three months ended March 31, 2014, offset in part by cash flows provided by operating activities of $80.5 million. With our current liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund our planned operations in 2014.

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 2014. While we expect to continue to add producing reserves through our drilling operations, these reserve additions could be offset by other factors including, among other things, a significant decrease in commodity prices. We do not plan to request an increase, nor do we expect a reduction, in the borrowing base upon the completion of our May 2014 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 or 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. Pursuant to this shelf registration, we sold 5.2 million shares of our common stock in August 2013 in an underwritten public offering at a price to us of $53.37 per share.

Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.25 times earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled derivatives, 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 crude oil and natural gas derivative instruments. Additionally, available borrowings under our revolving credit facility are added 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, 2014, we were in compliance with all debt covenants with a 2.2 times debt to EBITDAX ratio and a 2.4 to 1.0 current ratio. We expect to remain in compliance throughout the next year.

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The indenture governing our 7.75% senior notes due 2022 contains customary 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, 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, 2014, we were in compliance with all covenants and expect to remain in compliance throughout the next year.

The conversion right on our Convertible Notes was triggered on March 20, 2014, when the closing sale price of our common stock exceeded $55.12 (130% of the applicable conversion price) for the 20th trading day in the 30 consecutive trading days ending on March 31, 2014. Through May 6, 2014, no holders of the Convertible Notes have elected to convert their notes. As a result, the carrying value of the Convertible Notes, net of discount, was classified as a current liability as of March 31, 2014 in our condensed consolidated balance sheet. 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. In the event that a holder elects to convert its note, we expect to fund the cash settlement of any such conversion from working capital and/or borrowings under our revolving credit facility. The conversion right is not expected to have a material impact on our financial position.

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 are primarily impacted by commodity prices, production volumes, net settlements from our derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities increased by $36.2 million for the three months ended March 31, 2014 compared to the three months ended March 31, 2013. The increase in cash provided by operating activities was primarily due to the increase in crude oil, natural gas and NGLs sales of $50.4 million and changes in assets and liabilities of $18.9 million related to the timing of cash payments and receipts. The increase was offset in part by the decrease in realized derivative gains of $16.7 million and increases in general and administrative expense of $8.5 million and production costs of $5.3 million. 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 $17.3 million during the three months ended March 31, 2014 compared to the three months ended March 31, 2013. 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 assets and liabilities. Adjusted EBITDA, a non-U.S. GAAP financial measure, increased by $15.4 million during the three months ended March 31, 2014 compared to the three months ended March 31, 2013. The increase was primarily the result of the increase in crude oil, natural gas and NGLs sales of $50.4 million, offset in part by the decrease in net settlements on derivatives of $16.7 million and an increase in general and administrative expense of $8.5 million and production costs of $5.3 million. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of non-U.S. GAAP financial measures.

Investing Activities. Because crude oil and natural gas 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 crude oil, natural gas and NGLs 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.

Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. During the three months ended March 31, 2014, our drilling program consisted of four drilling rigs operating in the liquid-rich horizontal Niobrara and Codell plays in our Wattenberg Field and one rig in the Utica Shale play. Net cash from investing activities of $135.0 million during the three months ended March 31, 2014 was primarily related to cash utilized for our drilling operations of $135.8 million, offset in part by $0.8 million received from the sale of properties and equipment.

Financing Activities. Net cash from financing activities for the three months ended March 31, 2014 decreased by approximately $1.6 million compared to the three months ended March 31, 2013. Net cash from financing activities of $8.4 million for the three months ended March 31, 2014 primarily represents our proportionate share of PDCM's draw on its credit facility.

Drilling Activity

The following table presents our net developmental and exploratory drilling activity for the periods shown. 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 or are waiting to be completed and/or for gas pipeline connection during the period. The 0.7 well dry hole shown for the three months ended March 31, 2014 relates to the mechanical failure of a horizontal Codell well in the Wattenberg Field.

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	Net Drilling Activity
		Three Months Ended March 31,
		2014			2013
Operating Region/Area		Productive	In-Process	Dry	Productive	In-Process	Dry
Development Wells
Wattenberg Field		11.7	24.5	0.7	7.8	12.2	—
Utica Shale		2.0	3.0	—	—	—	—
Appalachia-Marcellus Shale		1.5	0.5	—	—	—	—
Total net development wells		15.2	28.0	0.7	7.8	12.2	—
Exploratory Wells
Utica Shale		—	—	—	1.5	1.5	—
Total net exploratory wells		—	—	—	1.5	1.5	—
Total drilling activity		15.2	28.0	0.7	9.3	13.7	—

Off-Balance Sheet Arrangements

At March 31, 2014, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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 2013 Form 10-K filed with the SEC on February 20, 2014.

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 significant accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the condensed consolidated statements of cash flows in the accompanying condensed consolidated financial statements included elsewhere in this report.

Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled 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 loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of crude oil and natural gas properties, depreciation, depletion and amortization and accretion of asset retirement obligations, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDA is not a measure

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of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), and should not be considered 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:


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


•	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


•	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,
	2014			2013
	(in millions)
Adjusted cash flows from operations:
Adjusted cash flows from operations	$	69.7		$	52.4
Changes in assets and liabilities	10.8			(8.1		)
Net cash from operating activities	80.5			$	44.3

Adjusted net income (loss):
Adjusted net income (loss)	$	9.6		$	(20.4	)
Loss on commodity derivative instruments	(27.1		)	(22.2		)
Net settlements on commodity derivative instruments	8.2			(8.5		)
Tax effect of above adjustments	7.2			11.7
Net loss	$	(2.1	)	$	(39.4	)

Adjusted EBITDA to net income (loss):
Adjusted EBITDA	$	76.5		$	61.1
Loss on commodity derivative instruments	(27.1		)	(22.2		)
Net settlements on commodity derivative instruments	8.2			(8.5		)
Interest expense, net	(12.6		)	(13.4		)
Income tax provision	1.4			21.5
Impairment of crude oil and natural gas properties	(1.0		)	(46.5		)
Depreciation, depletion and amortization	(46.6		)	(30.2		)
Accretion of asset retirement obligations	(0.9		)	(1.2		)
Net loss	$	(2.1	)	$	(39.4	)

Adjusted EBITDA to net cash from operating activities:
Adjusted EBITDA	$	76.5		$	61.1
Interest expense, net	(12.6		)	(13.4		)
Stock-based compensation	3.8			2.6
Amortization of debt discount and issuance costs	1.7			1.8
Loss on sale of properties and equipment	0.7			—
Other	(0.4		)	0.3
Changes in assets and liabilities	10.8			(8.1		)
Net cash from operating activities	$	80.5		$	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 7.75% senior notes due 2022 and 3.25% convertible senior notes due 2016 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, 2014, 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, 2014 was $147.8 million with an average interest rate of 0.1%. Based on a sensitivity analysis of our interest bearing deposits as of March 31, 2014, it was estimated that if market interest rates would have increased by 1%, the impact on interest income for the three months ended March 31, 2014 would result in a change of $1.5 million.

As of March 31, 2014, excluding the $11.7 million irrevocable standby letter of credit, we had no outstanding draws on our revolving credit facility and, representing our proportionate share, $46.3 million on PDCM's revolving credit facility. We estimate that if market interest rates would have increased or decreased by 1%, the impact on interest expense for the three months ended March 31, 2014 would have been immaterial.

Commodity Price Risk

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

The following table presents our derivative positions related to crude oil and natural gas sales in effect as of March 31, 2014:



	Collars					Fixed-Price Swaps			Basis Protection Swaps
Commodity/ Index/ Maturity Period	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, 2014 (2) (in millions)
Commodity/ Index/ Maturity Period	Quantity (Gas - BBtu (1) Oil - MBbls)	Floors		Ceilings		Quantity (Gas - BBtu (1) Oil - MBbls)	Weighted- Average Contract Price		Quantity (BBtu) (1)	Weighted- Average Contract Price			Fair Value March 31, 2014 (2) (in millions)
Natural Gas
NYMEX
2014	—	$	—	$	—	13,200.0	$	4.17	4,422.0	$	(0.22	)	$	(4.0	)
2015	5,860.0	4.00		4.48		12,950.0	4.10		1,620.0	(0.27		)	(1.5		)
2016	4,820.0	4.03		4.48		13,000.0	4.00		—	—			(1.7		)
2017	1,630.0	4.25		5.00		625.0	4.22		—	—			0.4

CIG
2014	—	—		—		3,726.0	3.99		—	—			(1.1		)
2015	—	—		—		2,730.0	4.01		—	—			0.1

Total Natural Gas	12,310.0					46,231.0			6,042.0				(7.8		)

Crude Oil
NYMEX
2014	702.5	82.43		102.16		2,484.0	90.98		—	—			(16.6		)
2015	336.0	81.07		97.76		4,165.0	88.67		—	—			(5.0		)

Total Crude Oil	1,038.5					6,649.0			—				(21.6		)
Total Natural Gas and Crude Oil													$	(29.4	)

_____________


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

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PDC ENERGY, INC.


(2)	Approximately 51.0% of the fair value of our derivative assets and 4.3% 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.

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



	Three Months Ended		Year Ended
	March 31, 2014		December 31, 2013
Average Index Closing Price:
Crude oil (per Bbl)
NYMEX	$	98.89	$	96.76
Natural gas (per MMBtu)
CIG	$	4.79	$	3.45
NYMEX	4.94		3.65

Average Sales Price Realized:
Excluding net settlements on derivatives
Crude oil (per Bbl)	$	86.02	$	89.92
Natural gas (per Mcf)	4.56		3.29
NGLs (per Bbl)	35.18		27.97

Based on a sensitivity analysis as of March 31, 2014, 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, would have resulted in a decrease in the fair value of our derivative positions of $90.1 million; whereas a 10% decrease in prices would have resulted in an increase in fair value of $88.3 million.

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 significant 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. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties.

Our Oil and Gas Exploration and Production segment's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with 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 segment.

Our derivative financial instruments may expose us to the risk of nonperformance by the instrument's contract counterparty. We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets may have a significant adverse impact on a number of financial institutions. We monitor the creditworthiness of our counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our monitoring procedures are reasonable, no amount of analysis can assure performance by a financial institution. To date, we have had no material counterparty default losses from our derivative financial instruments. See Note 4, Derivative Financial Instruments, to our consolidated financial statements included elsewhere in this report for more detail on our derivative financial instruments.

Disclosure of Limitations

Because the information above included only those exposures that existed at March 31, 2014, 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, 2014, 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, 2014.

Changes in Internal Control over Financial Reporting

During the three months ended March 31, 2014, 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 2013 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.

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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

January 1 - 31, 2014	17,434	$	49.67
February 1 - 28, 2014	1,637	59.88
March 1 - 31, 2014	2,726	59.44
Total first quarter purchases	21,797	51.66

__________


(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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PDC ENERGY, INC.

ITEM 6. EXHIBITS

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

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.

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.

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 6, 2014	/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)