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 June 30, ~~2014~~2015

£ 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~~Delaware	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: ~~35,870,665~~40,099,702 shares of the Company's Common Stock ($0.01 par value) were outstanding as of July ~~18, 2014~~.17, 2015.

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PDC ENERGY, INC.

TABLE OF CONTENTS



	PART I – FINANCIAL INFORMATION	Page

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets (unaudited)	1
	Condensed Consolidated Statements of Operations (unaudited)	2
	Condensed Consolidated Statements of Cash Flows (unaudited)	3
	Notes to Condensed Consolidated Financial Statements	43
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2120
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3634
Item 4.	Controls and Procedures	3835

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	3835
Item 1A.	Risk Factors	3835
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3935
Item 3.	Defaults Upon Senior Securities	3935
Item 4.	Mine Safety Disclosures	3935
Item 5.	Other Information	3935
Item 6.	Exhibits	4036

	SIGNATURES	4137

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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: ~~closing of the proposed PDC Mountaineer, LLC ("PDCM") divestiture; use of expected proceeds from such divestiture;~~ 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; estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves; expected 2015 capital forecast allocations, including revised capital and production forecasts; anticipated increased 2015 capital projects, expenditures and opportunities; expected year-end exit rates; the impact of prolonged depressed commodity prices; potential future impairments; availability of sufficient funding for our 2015 capital program and sources of that funding; future exploration, drilling and development activities, including our expected rig count; expectation of cash flow neutrality in 2016; potential additional revisions to our 2015 capital and production forecast; anticipated reductions in our 2015 cost structure; the expiration of certain significant and insignificant leases in the Utica Shale; our evaluation method of our customers' and derivative counterparties' credit risk, ~~is appropriate; anticipated capital projects, expenditures and opportunities; future exploration, drilling and development activities; our drilling programs and number~~in light of locations; the effect of additional midstream facilities and services; availability of sufficient funding for our 2014 capital program and sources of that funding, including PDCM; expected 2014 capital budget allocations; acquisitions of additional acreage and other future transactions; the impact of high line pressures and our inability to control the timing and availability of additional facilities going forward; widening of the NYMEX differential through 2014 at our two primary sales hubs primarily due to current oversupply in the Appalachian region; compliance with debt covenants; expected funding sources for conversionlow commodity prices on certain of our ~~3.25% convertible senior notes due 2016; impact of litigation~~Gas Marketing customers; our expected positive net settlements on our ~~results of operations and financial position; our ability to recoup costs incurred to remediate environmental issues that occurred as a result of a mechanical failure on a Utica Shale horizontal well;~~derivative positions in 2015; effectiveness of our derivative program in providing a degree of price stability; the impact of high line pressures and the timing, availability, cost and effect of additional midstream facilities and services going forward; expected differentials; compliance with debt covenants; expected funding sources upon conversion of our 3.25% convertible senior notes due 2016; the impact of litigation on our results of operations and financial position; 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;~~ 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:

~~potential impediments to completing the proposed PDCM divestiture on the expected timeframe or at all, or greater than expected purchase price adjustments;~~

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;~~NGLs and the risk of an extended period of depressed prices;

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~~

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2014 (the "2014 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February ~~20, 2014,~~19, 2015, 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,

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which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

REFERENCES

Unless the context otherwise requires, references 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 ~~PDCM,~~PDC Mountaineer, LLC ("PDCM"), a joint venture ~~currently~~ owned, until October 14, 2014, 50% each by PDC and Lime Rock Partners, LP. 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)


	June 30, 2014			December 31, 2013			June 30, 2015			December 31, 2014
Assets
Current assets:
Cash and cash equivalents	$	40,357		$	193,243		$	1,376		$	16,066
Restricted cash	49			2,214
Accounts receivable, net	116,928			94,085			90,005			131,204
Accounts receivable affiliates	6,424			6,614
Fair value of derivatives	785			2,572			155,891			187,495
Deferred income taxes	44,118			22,374
Prepaid expenses and other current assets	4,907			4,711			3,678			5,954
Total current assets	213,568			325,813			250,950			340,719
Properties and equipment, net	1,828,721			1,656,230			1,985,431			1,800,186
Assets held for sale							2,874			2,874
Fair value of derivatives	1,158			5,601			69,888			112,819
Other assets	42,978			37,559			82,474			83,990
Total Assets	$	2,086,425		$	2,025,203		$	2,391,617		$	2,340,588

Liabilities and Shareholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	107,897		$	109,555		$	79,709		$	130,321
Accounts payable affiliates	—			41
Production tax liability	25,259			23,421			25,952			21,314
Fair value of derivatives	50,838			15,515			1,812			570
Funds held for distribution	40,411			32,578			28,821			27,186
Current portion of long-term debt	106,921			—			110,998			—
Accrued interest payable	9,182			9,251			9,170			9,109
Deferred income taxes							32,914			59,174
Other accrued expenses	40,827			23,059			17,940			62,717
Total current liabilities	381,335			213,420			307,316			310,391
Long-term debt	562,000			656,990			553,000			664,923
Deferred income taxes	116,948			118,767			129,323			125,693
Asset retirement obligation	38,911			39,872			71,070			71,992
Fair value of derivatives	23,415			3,015			1,289			197
Other liabilities	20,545			25,545			13,032			30,033
Total liabilities	1,143,154			1,057,609			1,075,030			1,203,229

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, 150,000,000 authorized, 35,857,560 and 35,675,656 issued as of June 30, 2014 and December 31, 2013, respectively	359			357
Common shares - par value $0.01 per share, 150,000,000 authorized, 40,092,754 and 35,927,985 issued as of June 30, 2015 and December 31, 2014, respectively							401			359
Additional paid-in capital	681,019			674,211			898,430			689,209
Retained earnings	262,953			293,267			418,894			448,702
Treasury shares - at cost, 18,580 and 5,508 as of June 30, 2014 and December 31, 2013, respectively	(1,060		)	(241		)
Treasury shares - at cost, 21,734 and 21,643 as of June 30, 2015 and December 31, 2014, respectively							(1,138		)	(911		)
Total shareholders' equity	943,271			967,594			1,316,587			1,137,359
Total Liabilities and Shareholders' Equity	$	2,086,425		$	2,025,203		$	2,391,617		$	2,340,588

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 June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
Revenues
Crude oil, natural gas and NGLs sales	$	139,924		$	77,537		$	269,768		$	156,976		$	96,928		$	131,017		$	171,037		$	251,030
Sales from natural gas marketing	22,415			18,079			49,352			31,749			2,523			22,415			5,756			49,352
Commodity price risk management gain (loss), net	(53,411		)	24,724			(80,566		)	2,369			(49,041		)	(52,643		)	17,621			(77,552		)
Well operations, pipeline income and other	544			965			1,180			2,037			550			514			1,178			1,130
Total revenues	109,472			121,305			239,734			193,131			50,960			101,303			195,592			223,960
Costs, expenses and other
Production costs	26,754			16,176			47,958			32,034			21,476			23,774			45,645			41,857
Cost of natural gas marketing	22,428			18,065			49,298			31,801			2,836			22,428			6,094			49,298
Exploration expense	277			1,437			584			3,126			275			276			560			583
Impairment of crude oil and natural gas properties	938			1,502			1,917			47,961			2,773			848			5,257			1,758
General and administrative expense	40,665			15,783			64,277			30,898			18,667			39,440			37,347			61,924
Depreciation, depletion, and amortization	53,743			27,800			100,382			55,749
Depreciation, depletion and amortization													70,106			49,636			125,926			92,525
Accretion of asset retirement obligations	855			1,172			1,716			2,320			1,588			840			3,148			1,681
(Gain) loss on sale of properties and equipment	(363		)	(9		)	362			(47		)	(207		)	(23		)	(228		)	556
Total cost, expenses and other	145,297			81,926			266,494			203,842			117,514			137,219			223,749			250,182
Income (loss) from operations	(35,825		)	39,379			(26,760		)	(10,711		)
Loss from operations													(66,554		)	(35,916		)	(28,157		)	(26,222		)
Interest expense	(13,060		)	(13,089		)	(25,890		)	(26,446		)	(11,567		)	(12,195		)	(23,292		)	(24,378		)
Interest income	152			3			403			3			1,135			83			2,248			270
Income (loss) from continuing operations before income taxes	(48,733		)	26,293			(52,247		)	(37,154		)
Loss from continuing operations before income taxes													(76,986		)	(48,028		)	(49,201		)	(50,330		)
Provision for income taxes	20,546			(9,791		)	21,933			12,701			30,116			18,650			19,393			19,544
Income (loss) from continuing operations	(28,187		)	16,502			(30,314		)	(24,453		)
Loss from continuing operations													(46,870		)	(29,378		)	(29,808		)	(30,786		)
Income from discontinued operations, net of tax	—			3,416			—			4,953			—			1,191			—			472
Net income (loss)	$	(28,187	)	$	19,918		$	(30,314	)	$	(19,500	)
Net loss													$	(46,870	)	$	(28,187	)	$	(29,808	)	$	(30,314	)

Earnings per share:
Basic
Income (loss) from continuing operations	$	(0.79	)	$	0.55		$	(0.85	)	$	(0.80	)
Loss from continuing operations													$	(1.17	)	$	(0.82	)	$	(0.78	)	$	(0.86	)
Income from discontinued operations, net of tax	—			0.11			—			0.16			—			0.03			—			0.01
Net income (loss)	$	(0.79	)	$	0.66		$	(0.85	)	$	(0.64	)
Net loss													$	(1.17	)	$	(0.79	)	$	(0.78	)	$	(0.85	)

Diluted
Income (loss) from continuing operations	$	(0.79	)	$	0.53		$	(0.85	)	$	(0.80	)
Loss from continuing operations													$	(1.17	)	$	(0.82	)	$	(0.78	)	$	(0.86	)
Income from discontinued operations, net of tax	—			0.11			—			0.16			—			0.03			—			0.01
Net income (loss)	$	(0.79	)	$	0.64		$	(0.85	)	$	(0.64	)
Net loss													$	(1.17	)	$	(0.79	)	$	(0.78	)	$	(0.85	)

Weighted-average common shares outstanding:
Basic	35,762			30,332			35,726			30,301			40,035			35,762			38,202			35,726
Diluted	35,762			31,014			35,726			30,301			40,035			35,762			38,202			35,726

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(unaudited; in thousands)


	Six Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2015			2014
Cash flows from operating activities:
Net loss	$	(30,314	)	$	(19,500	)	$	(29,808	)	$	(30,314	)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled derivatives	61,953			9,913			76,869			61,953
Depreciation, depletion and amortization	100,382			58,007			125,926			100,382
Impairment of crude oil and natural gas properties	1,917			47,964			5,257			1,917
Accretion of asset retirement obligation	1,716			2,481			3,148			1,716
Stock-based compensation	8,879			6,951			9,465			8,879
Loss on sale of properties and equipment	362			1,029
(Gain) loss on sale of properties and equipment							(228		)	362
Amortization of debt discount and issuance costs	3,443			3,419			3,521			3,443
Deferred income taxes	(23,563		)	(11,075		)	(22,630		)	(23,563		)
Non-cash interest income							(2,247		)	—
Other	(90		)	(476		)	1,517			(90		)
Changes in assets and liabilities	6,905			(56,687		)	(24,333		)	6,905
Net cash from operating activities	131,590			42,026			146,457			131,590
Cash flows from investing activities:
Capital expenditures	(293,648		)	(139,462		)	(358,135		)	(293,648		)
Proceeds from acquisition adjustments	—			7,579
Proceeds from sale of properties and equipment	1,449			173,297			243			1,449
Net cash from investing activities	(292,199		)	41,414			(357,892		)	(292,199		)
Cash flows from financing activities:
Proceeds from sale of common stock, net of issuance costs							202,851			—
Proceeds from revolving credit facility	17,000			227,750			272,000			17,000
Repayment of revolving credit facility	(7,000		)	(267,000		)	(275,000		)	(7,000		)
Other	(2,277		)	(3,435		)	(3,106		)	(2,277		)
Net cash from financing activities	7,723			(42,685		)	196,745			7,723
Net change in cash and cash equivalents	(152,886		)	40,755			(14,690		)	(152,886		)
Cash and cash equivalents, beginning of period	193,243			2,457			16,066			193,243
Cash and cash equivalents, end of period	$	40,357		$	43,212		$	1,376		$	40,357

Supplemental cash flow information:
Cash payments for (receipts from):
Cash payments for:
Interest, net of capitalized interest	$	23,724		$	25,787		$	22,828		$	23,724
Income taxes	1,800			(57		)	9,936			1,800
Non-cash investing activities:
Non-cash investing and financing activities:
Change in accounts payable related to purchases of properties and equipment	$	(6,962	)	$	(8,695	)	$	(41,490	)	$	(6,962	)
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals	341			211			1,395			341
Change in accounts payable related to disposition of properties and equipment	—			(4,680		)
Change in accounts receivable affiliates related to disposition of properties and equipment	—			9,201
Purchase of properties and equipment under capital leases							950			—

~~See accompanying Notes to Condensed Consolidated Financial Statements~~

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~JUNE 30, 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 and the Utica Shale in southeastern ~~Ohio and the Marcellus Shale in northern West Virginia.~~Ohio. Our operations in the Wattenberg Field are focused onin the ~~liquid-rich~~ horizontal Niobrara and Codell plays and our Ohio operations are focused ~~on the liquid-rich portion of~~in the Utica Shale play. As of June 30, ~~2014~~2015, we owned an interest in approximately 2,900 gross wells. We are engaged in two business segments: Oil and Gas Exploration and Production and Gas Marketing. In October 2014, we sold our entire 50% ownership interest in our joint venture, PDCM, to an unrelated third-party.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our ~~wholly owned subsidiaries, and~~wholly-owned subsidiary Riley Natural Gas ("RNG"), our proportionate share of ~~PDCM~~our four affiliated partnerships and, for the three and six months ended June 30, 2014, our ~~affiliated partnerships.~~proportionate share of PDCM. 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~~2014 Form 10-K. Our results of operations and cash flows for the three and six months ended June 30, ~~2014~~2015 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are mainly attributable to reporting the results of operations related to PDCM's Marcellus Shale assets as discontinued operations. 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~~Standards

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 Standards~~

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 component of an entity that either has been disposed of or is classified as held for sale and represents a strategic shift that has a major effect on the entity's operations and financial results. These changes ~~are~~were required to be applied prospectively for new disposals or components of an entity classified as held for sale during interim and annual periods beginning after December 15, 2014, with early adoption permitted. ~~We are currently evaluating~~On July 1, 2014, we elected to early adopt the ~~impact these changes will have on our condensed consolidated financial statements.~~new pronouncement.

Recently Issued Accounting Standards

In May 2014, the FASB and the International Accounting Standards Board ("IASB") issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (a) identify the contract with the customer, (b) identify the separate performance obligations in the contract, (c) determine the transaction price, (d) allocate the transaction price to separate performance obligations and (e) recognize revenue when (or as) each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, ~~2016,~~2017, including interim periods within that reporting period, and can be adopted under the full retrospective method or simplified transition method. ~~Early adoption is not permitted. We plan~~Entities are permitted to adopt the revenue standard early, beginning ~~January 1, 2017 and~~with annual reporting periods after December 15, 2016. We are currently evaluating the impact these changes will have on our condensed consolidated financial statements.

In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.

In November 2014, the FASB issued an update to accounting for derivatives and hedging instruments. The update clarifies how current

See accompanying Notes to Condensed Consolidated Financial Statements

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

accounting guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the accounting update clarifies that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the update clarifies that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The assessment of the substance of the relevant terms and features should incorporate a consideration of the characteristics of the terms and features themselves, the circumstances under which the hybrid financial instrument was issued or acquired, and the potential outcomes of the hybrid financial instrument, as well as the likelihood of those potential outcomes. The accounting update is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the impact these changes will have on our condensed consolidated financial statements.

In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements.

In February 2015, the FASB issued an accounting update modifying existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2015, and require either a retrospective or a modified retrospective approach to adoption. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements or disclosures.

In April 2015, the FASB issued an accounting update simplifying the presentation of debt issuance costs and requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The update did not affect the recognition and measurement guidance for debt issuance costs. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Adoption of this guidance is not expected to have a significant impact on our condensed consolidated financial statements or disclosures.

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

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~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

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

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

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

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our collars ~~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:


	June 30, 2014									December 31, 2013								June 30, 2015						December 31, 2014
	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			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)																	(in thousands)
Assets:
Commodity-based derivative contracts	$	1,226		$	611		$	1,837		$	5,325		$	2,385	$	7,710		$	167,362	$	58,417	$	225,779	$	237,939	$	62,356	$	300,295
Basis protection derivative contracts	104			2			106			463			—		463			—		—		—		19		—		19
Total assets	1,330			613			1,943			5,788			2,385		8,173			167,362		58,417		225,779		237,958		62,356		300,314
Liabilities:
Commodity-based derivative contracts	66,652			7,393			74,045			17,537			988		18,525			1,016		162		1,178		742		—		742
Basis protection derivative contracts	208			—			208			5			—		5			1,923		—		1,923		25		—		25
Total liabilities	66,860			7,393			74,253			17,542			988		18,530			2,939		162		3,101		767		—		767
Net asset (liability)	$	(65,530	)	$	(6,780	)	$	(72,310	)	$	(11,754	)	$	1,397	$	(10,357	)
Net asset																		$	164,423	$	58,255	$	222,678	$	237,191	$	62,356	$	299,547

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~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in thousands)												(in thousands)
Fair value, net asset, beginning of period	$	105		$	7,663		$	1,397		$	13,669		$	74,817		$	(129	)	$	62,356		$	1,111
Changes in fair value included in statement of operations line item:
Commodity price risk management gain (loss), net	(7,501		)	2,834			(8,896		)	103			(10,749		)	(7,454		)	4,440			(8,797		)
Sales from natural gas marketing	(4		)	22			(26		)	6			(1		)	(4		)	—			(26		)
Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net	621			(2,246		)	740			(5,479		)	(5,809		)	621			(8,534		)	740
Sales from natural gas marketing	(1		)	(3		)	5			(29		)	(3		)	(1		)	(7		)	5
Income (loss) from discontinued operations, net of tax	—			(4,366		)	—			(4,366		)
Fair value, net asset end of period	$	(6,780	)	$	3,904		$	(6,780	)	$	3,904
Fair value, net asset (liability) end of period													$	58,255		$	(6,967	)	$	58,255		$	(6,967	)

Net change in fair value of unsettled derivatives included in statement of operations line item:
Commodity price risk management loss, net	$	(3,041	)	$	(1,717	)	$	(4,327	)	$	(3,652	)
Commodity price risk management gain (loss), net													$	(10,056	)	$	(2,993	)	$	3,629		$	(4,227	)
Sales from natural gas marketing	(2		)	22			(4		)	10			—			(2		)	—			(4		)
Total	$	(3,043	)	$	(1,695	)	$	(4,331	)	$	(3,642	)	$	(10,056	)	$	(2,995	)	$	3,629		$	(4,231	)

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. There has been no change in the methodology we apply to measure the fair value 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, excluding the current portion of long-term debt, 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 liability related to this plan, which was included in other liabilities on the condensed consolidated balance sheets, was immaterial as of June 30, 2015 and December 31, 2014.

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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 June 30, ~~2014~~2015, 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 ~~$183.2~~$155.9 million,, or ~~159.3%~~135.6% of par value, and the portion related to our 7.75% senior notes due 2022 to be ~~$557.5~~$527.2 million,, or ~~111.5%~~105.4% 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.

The carrying value of our capital lease obligations approximates fair value as it represents the present value of future lease payments.

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 June 30, ~~2014~~,2015, taking into account the estimated likelihood of nonperformance.

The following table presents the counterparties that expose us to credit risk as of June 30, 2015 with regard to our derivative assets:



Counterparty Name	Fair Value of Derivative Assets
	(in thousands)
JP Morgan Chase Bank, N.A (1)	$	63,200
Canadian Imperial Bank of Commerce (1)	53,050
Wells Fargo Bank, N.A. (1)	34,072
NATIXIS (1)	28,169
Bank of Nova Scotia (1)	26,938
Key Bank N.A. (1)	14,962
Other lenders in our revolving credit facility	5,388
Total	$	225,779

__________

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

Note Receivable. The following table presents information regarding our note receivable outstanding as of June 30, 2015:



	Amount
	(in thousands)
Note Receivable:
Principal outstanding, December 31, 2014	$	39,707
Paid-In-Kind interest	1,604
Principal outstanding, June 30, 2015	$	41,311

In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the sale. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million, bearing interest at varying rates beginning at 8%, and increasing annually. Pursuant to the Note agreement, interest shall be paid quarterly, in arrears, commencing in December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of June 30, 2015, the issuer of the Note had elected the PIK Interest option. The principal and any unpaid interest shall be due and payable in full in September 2020 and can be prepaid in whole or in part at any time, and in certain circumstances must be repaid prior to maturity. Any such prepayment will be made without premium or penalty. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets.

Under the effective interest method, we recognized $1.1 million and $2.2 million of interest income for the three and six months ended June 30, 2015, respectively, of which $0.8 million and $1.6 million, respectively, was PIK Interest. As of June 30, 2015, the $41.3 million outstanding balance on the Note was included in the condensed consolidated balance sheet line item other assets.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

~~The following table presents the counterparties that expose us to credit risk as of~~ ~~June 30, 2014~~ ~~with regard to our derivative assets:~~

Counterparty Name Fair Value of
Derivative Assets
(in thousands)
Wells Fargo Bank, N.A. (1) $ 518
Bank of Montreal (1) 432
JP Morgan Chase Bank, N.A (1) 412
Bank of Nova Scotia (1) 298
Other lenders in our revolving credit facility 239
Various (2) 44
Total $ 1,943

~~__________~~

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

~~(2)Represents a total of~~ 31 ~~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.

We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of June 30, ~~2014~~2015, 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 ~~53,234~~76,328 BBtu of natural gas and ~~10,238~~8,127 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance ~~sheets as of~~ ~~June 30, 2014~~ ~~and~~ ~~December 31, 2013~~:sheets:


			Fair Value						Fair Value
Derivatives instruments:		Balance sheet line item	June 30, 2014		December 31, 2013
Derivative instruments:							Derivative instruments:	Balance sheet line item	June 30, 2015		December 31, 2014
			(in thousands)						(in thousands)
Derivative assets:	Current						Current
	Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	$	519	$	2,016
	Related to natural gas marketing	Fair value of derivatives	264		361
	Basis protection contracts						Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	—		195		Related to crude oil and natural gas sales	Fair value of derivatives	$	155,516	$	186,886
	Related to natural gas marketing	Fair value of derivatives	2		—		Related to natural gas marketing	Fair value of derivatives	375		590
			785		2,572		Basis protection contracts
	Non-current						Related to crude oil and natural gas sales	Fair value of derivatives	—		19
	Commodity contracts								155,891		187,495
	Related to crude oil and natural gas sales	Fair value of derivatives	721		5,055		Non-current
	Related to natural gas marketing	Fair value of derivatives	190		278		Commodity contracts
	Basis protection contracts						Related to crude oil and natural gas sales	Fair value of derivatives	69,746		112,599
	Related to crude oil and natural gas sales	Fair value of derivatives	247		268		Related to natural gas marketing	Fair value of derivatives	142		220
			1,158		5,601				69,888		112,819
Total derivative assets			$	1,943	$	8,173			$	225,779	$	300,314

Derivative liabilities:	Current						Current
	Commodity contracts						Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	$	50,434	$	15,263	Related to natural gas marketing	Fair value of derivatives	$	348	$	545
	Related to natural gas marketing	Fair value of derivatives	196		247		Basis protection contracts
	Basis protection contracts						Related to crude oil and natural gas sales	Fair value of derivatives	1,464		25
	Related to crude oil and natural gas sales	Fair value of derivatives	207		—				1,812		570
	Related to natural gas marketing	Fair value of derivatives	1		5		Non-current
			50,838		15,515		Commodity contracts
	Non-current						Related to crude oil and natural gas sales	Fair value of derivatives	700		—
	Commodity contracts						Related to natural gas marketing	Fair value of derivatives	130		197
	Related to crude oil and natural gas sales	Fair value of derivatives	23,255		2,782		Basis protection contracts
	Related to natural gas marketing	Fair value of derivatives	160		233		Related to crude oil and natural gas sales	Fair value of derivatives	459		—
			23,415		3,015				1,289		197
Total derivative liabilities			$	74,253	$	18,530			$	3,101	$	767

The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
Condensed consolidated statement of operations line item	2014			2013			2014			2013			2015			2014			2015			2014
	(in thousands)												(in thousands)
Commodity price risk management income (loss), net
Commodity price risk management gain (loss), net
Net settlements	$	(10,429	)	$	3,903		$	(18,668	)	$	12,374		$	44,049		$	(9,813	)	$	94,461		$	(17,051	)
Net change in fair value of unsettled derivatives	(42,982		)	20,821			(61,898		)	(10,005		)	(93,090		)	(42,830		)	(76,840		)	(60,501		)
Total commodity price risk management income (loss), net	$	(53,411	)	$	24,724		$	(80,566	)	$	2,369
Total commodity price risk management gain (loss), net													$	(49,041	)	$	(52,643	)	$	17,621		$	(77,552	)
Sales from natural gas marketing
Net settlements	$	(110	)	$	(173	)	$	(586	)	$	28		$	165		$	(110	)	$	396		$	(586	)
Net change in fair value of unsettled derivatives	265			1,621			(47		)	651			(124		)	265			(293		)	(47		)
Total sales from natural gas marketing	$	155		$	1,448		$	(633	)	$	679		$	41		$	155		$	103		$	(633	)
Cost of natural gas marketing
Net settlements	$	149		$	225		$	684		$	63		$	(157	)	$	149		$	(375	)	$	684
Net change in fair value of unsettled derivatives	(304		)	(1,636		)	(8		)	(559		)	115			(304		)	264			(8		)
Total cost of natural gas marketing	$	(155	)	$	(1,411	)	$	676		$	(496	)	$	(42	)	$	(155	)	$	(111	)	$	676

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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~~ ~~June 30, 2014~~ ~~and~~ ~~December 31, 2013~~:liabilities:


As of June 30, 2014	Derivatives instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
As of June 30, 2015								Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)							(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	1,943	$	(1,165	)	$	778	$	225,779	$	(2,409	)	$	223,370

Liability derivatives:
Derivative instruments, at fair value	$	74,253	$	(1,165	)	$	73,088	$	3,101	$	(2,409	)	$	692


As of December 31, 2013	Derivatives instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
As of December 31, 2014								Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)							(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	8,173	$	(5,623	)	$	2,550	$	300,314	$	(29	)	$	300,285

Liability derivatives:
Derivative instruments, at fair value	$	18,530	$	(5,623	)	$	12,907	$	767	$	(29	)	$	738

NOTE 5 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization ("DD&A"):


	June 30, 2014			December 31, 2013			June 30, 2015			December 31, 2014
	(in thousands)						(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	2,000,264		$	1,784,466		$	2,595,158		$	2,267,165
Unproved	332,548			307,203			186,760			188,206
Total crude oil and natural gas properties	2,332,812			2,091,669			2,781,918			2,455,371
Pipelines and related facilities	21,765			21,781
Equipment and other	30,272			29,246			31,642			29,562
Land and buildings	13,620			13,617			9,028			9,015
Construction in progress	83,422			53,810			119,239			137,937
Properties and equipment, at cost	2,481,891			2,210,123			2,941,827			2,631,885
Accumulated DD&A	(653,170		)	(553,893		)	(956,396		)	(831,699		)
Properties and equipment, net	$	1,828,721		$	1,656,230		$	1,985,431		$	1,800,186

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)
Continuing operations:
Amortization of individually insignificant unproved properties	$	2,773	$	848	$	5,257	$	1,758
Discontinued operations:
Amortization of individually insignificant unproved properties	—		90		—		159
Total impairment of crude oil and natural gas properties	$	2,773	$	938	$	5,257	$	1,917

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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

Three Months Ended June 30, Six Months Ended June 30,
2014 2013 2014 2013
(in thousands)
Continuing operations:
Impairment of proved properties $ —
$ —
$ —
$ 45,000
Impairment of individually significant unproved properties —
671
—
825
Amortization of individually insignificant unproved properties 938
831
1,917
2,136
Total continuing operations 938
1,502
1,917
47,961
Discontinued operations:
Amortization of individually insignificant unproved properties —
—
—
3
Total discontinued operations —
—
—
3
Total impairment of crude oil and natural gas properties $ 938
$ 1,502
$ 1,917
$ 47,964

~~During the first quarter of 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 and update 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 and six months ended June 30, ~~2014~~2015 was a ~~42.2%~~39.1% and ~~42.0%~~39.4% benefit on loss, respectively, compared to a ~~37.2%~~ ~~expense on income and~~ ~~34.2%~~38.8% benefit on loss for the three and six months ended June 30, ~~2013, respectively.~~2014. The effective tax rates for the three and six months ended June 30, ~~2014~~2015 are based upon a full year forecasted tax provision on income and are greater than the statutory rate, primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion ~~deductions.~~and domestic production deduction. The effective tax ~~rates~~rate for the three and six months ended June 30, ~~2013~~2014 differ from the statutory rate primarily due to ~~net permanent additions, largely nondeductible officers' compensation,~~percentage depletion and domestic production deduction partially offset by ~~percentage depletion deductions. For the~~ ~~six~~ ~~months ended June 30, 2013, the~~state taxes and 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 our net operating losses resulted in a reduced state tax benefit.compensation. There were no significant discrete items recorded during the three and six months ended June 30, ~~2014~~2015 or ~~2013~~.2014.

As of June 30, ~~2014, our gross~~2015, we had no 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 current year due to the expiration of the statute of limitations.~~

benefits. 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.~~any state income tax examinations. We continue voluntary participation in the Internal Revenue Service’s ("IRS") Compliance Assurance Program for the ~~2013~~2014 and ~~2014~~2015 tax years. ~~We received a~~The IRS has notified us of full acceptance ~~“no change” notice from the IRS for~~of our ~~filed 2012 federal tax return.~~2013 return with no changes.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

NOTE 7 - LONG-TERM DEBT

Long-term debt consists of the following:


	June 30, 2014			December 31, 2013			June 30, 2015			December 31, 2014
	(in thousands)						(in thousands)
Senior notes:
3.25% Convertible senior notes due 2016:
Principal amount	$	115,000		$	115,000		$	115,000		$	115,000
Unamortized discount	(8,079		)	(10,010		)	(4,002		)	(6,077		)
3.25% Convertible senior notes due 2016, net of discount	106,921			104,990			110,998			108,923
7.75% Senior notes due 2022	500,000			500,000			500,000			500,000
Total senior notes	606,921			604,990			610,998			608,923
Credit facilities:
Corporate	—			—
PDCM	47,000			37,000
Total credit facilities	47,000			37,000
PDCM second lien term loan	15,000			15,000

Revolving credit facility							53,000			56,000
Total debt	668,921			656,990			663,998			664,923
Less: Current portion of long-term debt	106,921			—
Less current portion of long-term debt							110,998			—
Long-term debt	$	562,000		$	656,990		$	553,000		$	664,923

Senior Notes

3.25% Convertible Senior Notes Due ~~2016.~~ 2016. In November 2010,, we issued ~~$115~~$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 15.15. The indenture governing the ~~notes~~Convertible Notes contains certain non-financial covenants. We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial ~~$94.3~~$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~~Convertible Notes using an effective interest rate of 7.4%. As the stated maturity for payment of principal is May 2016, 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 June 30, 2015.

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 were convertible at the option of holders as of June 30, ~~2014~~.2015. The conversion right was triggered on June ~~20, 2014,~~16, 2015, when the closing sale price of our common stock on the NASDAQ Global Select Market exceeded ~~$55.12~~ (~~130%~~$55.12 (130% of the applicable conversion price) for the 20th trading day in the 30 consecutive trading days ending on June 30, ~~2014~~.2015. In the event a holder elects to convert its

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

note, we expect to fund any cash settlement of any such conversion from working capital and/or borrowings under our revolving credit facility. 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 ~~June 30, 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 June 30, ~~2014~~2015 stock price of ~~$63.15~~,$53.64, the “if-converted” value of the Convertible Notes exceeded the aggregate principal amount by approximately ~~$56.3 million. Through August 8, 2014,~~$30.5 million. As of the date of this filing, no holders of the Convertible Notes have elected to convert their notes.

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-annually in arrears on each April 15 and October 15. The indenture governing the ~~notes~~2022 Senior Notes contains customary restrictive incurrence covenants. Capitalized debt issuance costs are being amortized as interest expense over the life of the ~~notes~~2022 Senior Notes using the effective interest method.

As of June 30, ~~2014~~2015, 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.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

Credit ~~Facilities~~Facility

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~~.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$1 billion in allowable borrowing capacity, subject to the borrowing base. As of June 30, ~~2014~~,2015, the borrowing base was ~~$450 million~~.$700 million; however, we have elected to maintain the aggregate commitment at $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 May 2015 semi-annual redetermination resulted in the reaffirmation of our borrowing base at $700 million and our commitment level at $450 million. 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~~Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility.

We had noa $53.0 million outstanding ~~draws~~balance on our revolving credit facility as of June 30, ~~2014~~ or 2015, compared to a $56.0 million outstanding balance as of December 31, ~~2013~~2014. The weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 3.0%. and 3.8% per annum as of June 30, 2015 and December 31, 2014, respectively.

As of June 30, ~~2014~~2015, ~~Riley Natural Gas, a wholly-owned subsidiary of PDC,~~RNG 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 expires in September ~~2014.~~2015. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal ~~amount.~~to the letter of credit. As of June 30, ~~2014~~,2015, the available funds under our revolving credit facility, including athe reduction for the ~~$11.7~~$11.7 million ~~irrevocable standby~~ letter of credit, ~~in effect,~~ was ~~$438.3 million~~.$385.3 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 June 30, ~~2014~~,2015, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period.

NOTE 8 - CAPITAL LEASES

~~PDCM Credit Facility.~~ ~~PDCM~~Beginning in the first quarter of 2015, we entered into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. Each lease agreement has a ~~credit facility dated~~ ~~April 2010~~,term of three years and is being accounted for 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~~capital lease, as 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 its credit agreement. The amendment increased the amount of future production from proved developed and producing properties that is permitted to be hedged. As of ~~June 30, 2014, our proportionate share of PDCM's outstanding credit facility balance was~~ ~~$47.0 million~~ ~~compared to~~ ~~$37.0 million~~ ~~as of~~ ~~December 31, 2013. The weighted-average borrowing rate on PDCM's credit facility was~~ ~~3.8%~~ ~~per annum as of~~ ~~June 30, 2014, compared to~~ ~~3.7%~~ ~~as of~~ ~~December 31, 2013~~.

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~~ ~~June 30, 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~~ ~~June 30, 2014, amounts borrowed and outstanding on the Term Loan Agreement were~~ ~~$30.0 million, of which our proportionate share is~~ ~~$15 million. The weighted-average interest rate on the term loan was~~ ~~8.5%~~ ~~per annum as of both~~ ~~June 30, 2014~~ ~~and December 31, 2013.~~

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, a minimum interest coverage ratio of 2.25 to 1.0 and a present value of ~~future net revenues to total debt ratio~~minimum monthly lease payments, including the residual value guarantee, exceeds 90% of ~~1.50 to 1.00.~~the fair value of the leased vehicles at inception of the lease.

The following table presents leased vehicles under capital leases as of June 30, 2015:



	Amount
	(in thousands)
Vehicles	$	950
Accumulated depreciation	(50		)
	$	900

1211

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

AsFuture minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of ~~June 30, 2014, PDCM was~~one year or more, consist of the following:



For the Twelve Months Ending June 30,	Amount
	(in thousands)
2016	$	219
2017	290
2018	512
	1,021
Less executory cost	(47		)
Less amount representing interest	(147		)
Present value of minimum lease payments	$	827

Short-term capital lease obligations	$	(132	)
Long-term capital lease obligations	(695		)
	$	(827	)

Short-term capital lease obligations are included in ~~compliance with all Term Loan Agreement covenants and expects to remain~~other accrued expenses on the condensed consolidated balance sheets. Long-term capital lease obligations are included in ~~compliance throughout~~other liabilities on the ~~next 12-month period.~~condensed consolidated balance sheets.

NOTE 89 - ASSET RETIREMENT OBLIGATIONS

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

Amount
(in thousands)

Balance at beginning of period, January 1 $ 41,030
Obligations incurred with development activities 341
Accretion expense 1,716
Revisions in estimated cash flows (134 )
Obligations discharged with divestitures of properties and asset retirements (2,884 )
Balance end of period, June 30 40,069
Less: Current portion (1,158 )
Long-term portion $ 38,911



	Amount
	(in thousands)

Balance at beginning of period, January 1, 2015	$	73,855
Obligations incurred with development activities	1,395
Accretion expense	3,148
Obligations discharged with asset retirements	(1,868		)
Balance end of period, June 30, 2015	76,530
Less current portion	(5,460		)
Long-term portion	$	71,070

Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 910 - COMMITMENTS AND CONTINGENCIES

Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing ~~services~~agreements on pipeline systems through which we transport or sell crude oil and 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~~ ~~June 30, 2014~~:capacity:

For the Twelve Months Ending June 30,
Area 2015 2016 2017 2018 2019 and
Through
Expiration Total Expiration
Date

Natural gas (MMcf)
Appalachian Basin 19,033
19,862
20,987
20,987
114,928
195,797
January 31, 2026
Utica Shale 2,737
2,745
2,737
2,737
13,929
24,885
July 22, 2023
Total 21,770
22,607
23,724
23,724
128,857
220,682

Dollar commitment (in thousands) $ 7,356
$ 7,530
$ 7,746
$ 7,092
$ 35,075
$ 64,799

On ~~July 29, 2014, we signed a definitive agreement pursuant to which we agreed to sell our entire 50% ownership interest in PDCM to an unrelated third-party. Pursuant to the definitive agreement, approximately~~ ~~137,865~~ MMcf and $31.1 million of our Appalachian Basin firm transportation obligation will be assumed by the buyer upon the closing of the transaction. There can be no assurance that we will be successful in closing the transaction. In addition, we may have greater than expected purchase price reductions. See Note 15, ~~Subsequent Events, for additional information.~~



	For the Twelve Months Ending June 30,
Area	2016		2017		2018		2019		2020 and Through Expiration		Total		Expiration Date

Natural gas (MMcf)
Appalachian Basin	7,136		7,117		7,117		7,117		22,274		50,761		August 31, 2022
Utica Shale	2,745		2,737		2,737		2,737		11,190		22,146		July 22, 2023
Total	9,881		9,854		9,854		9,854		33,464		72,907

Crude oil (MBbls)
Wattenberg Field	2,420		2,413		2,413		2,413		2,421		12,080		June 30, 2020
											��
Dollar commitment (in thousands)	$	17,625	$	17,577	$	16,540	$	16,328	$	25,429	$	93,499

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~~

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~~unit holders of 12 former ~~partnership unit holders,~~limited partnerships, related to its ~~partnership repurchases~~repurchase of the 12 partnerships, which were formed beginning in late 2002 through 2005. The mergers were completed ~~by mergers~~ in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and iswas titled Schulein v. Petroleum Development Corp. The complaint primarily ~~alleges~~alleged that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court. ~~A jury trial originally scheduled for May~~

In October 2014, ~~has been rescheduled to begin in September 2014. We have held mediation meetings with plaintiffs~~the Company and ~~have proposed~~plaintiffs’ counsel reached a settlement ~~to resolve~~agreement. That settlement agreement was signed in December 2014 and was given final court approval in March 2015. Under this settlement agreement, the ~~alleged~~plaintiffs received a cash payment of $37.5 million in January 2015, of which the Company paid $31.5 million and insurers paid $6 million. In March 2015, the class ~~action. Our proposed settlement includes~~action was dismissed with prejudice and all class claims were released. As of December 31, 2014, the Company accrued a transfer of interests, primarily net profit interests which would generate cash in future years, in a certain number of future wells, plus a lesser value in an up-front cash payment. The mediation effort is ongoing; but there can be no assurance that the mediation meetings will continue or will result in a settlement on the terms we proposed or at all. During the quarter ended ~~June 30, 2014, we recorded a litigation charge of~~ ~~$20.8 million, included in general and administrative expense in the condensed consolidated statements of operations, for a total accrued~~ liability of ~~$24.1~~$37.5 million at ~~June 30, 2014~~, related to this litigation, which iswas included in other accrued expenses in the condensed consolidated balance sheet. ~~If the matter proceeds to trial, plaintiffs have indicated that they will seek damages of approximately~~ ~~$175 million, plus pre-judgment interest. We continue to believe we have good defenses to both the asserted claims and plaintiffs’ damage calculations.~~

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 minimize and mitigate the risks offrom environmental ~~contamination and related liabilities.~~contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of June 30, ~~2014~~2015 and December 31, ~~2013~~,2014, we had accrued environmental liabilities in the amount of ~~$6.2~~$3.8 million and ~~$5.4~~$0.8 million,, respectively, included in other accrued expenses on the condensed consolidated balance sheets. We are not aware of any environmental claims existing as of June 30, ~~2014~~2015 which have not been provided for or would otherwise ~~be expected to~~ have a material impact on our financial ~~statements. However,~~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.

In June 2014, we received an information request from the Environmental Protection Agency (the "EPA") pursuant to Sections 308 and 311 of the Clean Water Act (the "CWA") regarding a discharge of oil and related materials that occurred in May related to a mechanical failure during drilling at an Ohio location. The requested information relates to the facility from which the discharge occurred and details regarding the discharge. To date, the EPA has not issued any notice that a violation of the CWA occurred or sought to impose any fine or other relief in connection with the discharge. While the results cannot be predicted with certainty, we do not expect the ultimate resolution of this information request or any subsequent proceedings to have a material adverse effect on our financial condition or results of operation.

Employment Agreements with Executive Officers. Each of our senior executive officers ~~except the current Chief Executive Officer,~~ 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

NOTE 11 - COMMON STOCK

Sale of Equity Securities

In March 2015, we completed a public offering of 4,002,000 shares of our common stock, par value $0.01 per share, at a price to us of $50.73 per share. Net proceeds of the offering were $202.9 million, after deducting offering expenses and underwriting discounts, of which $40,020 is included in common shares-par value and $202.8 million is included in additional paid-in capital on the June ~~2014, we announced a leadership transition and entered into a consulting agreement with our current Chief Executive Officer~~30, 2015 condensed consolidated balance sheet. The shares were issued pursuant to ~~which he will provide consulting services to~~an effective shelf registration statement on Form S-3 filed with the ~~Company~~SEC in March 2015. ~~Under the agreement, the current Chief Executive Officer ceased to be a participant in our executive severance plan.~~

~~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 June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in thousands)												(in thousands)

Stock-based compensation expense	$	5,032		$	4,349		$	8,879		$	6,951		$	5,097		$	5,032		$	9,465		$	8,879
Income tax benefit	(1,912		)	(1,661		)	(3,374		)	(2,655		)	(1,936		)	(1,912		)	(3,595		)	(3,374		)
Net stock-based compensation expense	$	3,120		$	2,688		$	5,505		$	4,296		$	3,161		$	3,120		$	5,870		$	5,505

Stock Appreciation Rights ("SARs")

The SARs vest ratably over a three-year period and may be exercised at any point after vesting through 10ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

In January ~~2014,~~2015, the Compensation Committee awarded ~~88,248~~68,274 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:


	Six Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2015			2014

Expected term of award	6 years			6 years			6 years			6 years
Risk-free interest rate	2.1		%	1.0		%	1.6		%	2.1		%
Expected volatility	65.6		%	65.5		%	59.4		%	65.6		%
Weighted-average grant date fair value per share	$	29.96		$	21.96		$	21.99		$	29.96

The expected ~~life~~term 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:~~SARs for the periods presented:


	Six Months Ended June 30,										Six Months Ended June 30,
	2014					2013					2015						2014
	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)	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			279,011	$	38.77				190,763	$	33.77
Awarded	88,248	49.57				87,078	37.18				68,274	39.63					88,248	49.57
Outstanding at June 30,	279,011	38.77		8.3	6,803	205,910	33.50		8.6	3,703	347,285	38.94		7.8	$	5,107	279,011	38.77		8.3	$	6,803
Vested and expected to vest at June 30,	268,453	38.53		8.3	6,609	196,421	33.40		8.6	3,552	339,980	38.88		7.7	5,019		268,453	38.53		8.3	6,609
Exercisable at June 30,	109,920	32.71		7.3	3,346	67,069	29.99		7.6	1,441	191,149	35.68		6.9	3,433		109,920	32.71		7.3	3,346

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our condensed consolidated statement of operations as of June 30, ~~2014~~2015 was ~~$3.5 million~~.$2.8 million. The cost is expected to be recognized over a weighted-average period of ~~2.0~~1.8 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~~that a participant is continuously employed.

In January ~~2014,~~2015, the Compensation Committee awarded ~~a total of~~ ~~104,467~~ ~~time-based restricted shares~~ to our executive officers a total of 80,707 time-based restricted shares that vest ratably over a three-year period ending onin January ~~16, 2017.~~2018.

The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the six months ended June 30, ~~2014~~2015:


	Shares		Weighted-Average Grant-Date Fair Value		Shares		Weighted-Average Grant-Date Fair Value

Non-vested at December 31, 2013	651,781		$	36.36
Non-vested at December 31, 2014					564,332		$	46.02
Granted	280,835		56.56		291,903		48.54
Vested	(202,587	)	36.73		(201,006	)	43.82
Forfeited	(18,385	)	38.56		(11,003	)	54.94
Non-vested at June 30, 2014	711,644		44.18
Non-vested at June 30, 2015					644,226		47.69

~~Table of contents~~The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~


	As of/Year Ended June 30,				As of/for the Six Months Ended June 30,
	2014		2013		2015		2014
	(in thousands, except per share data)				(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	11,690	$	8,544	$	10,126	$	11,690
Total intrinsic value of time-based awards non-vested	44,940		37,082		34,556		44,940
Market price per common share as of June 30,	63.15		51.48		53.64		63.15
Weighted-average grant date fair value per share	56.56		44.24		48.54		56.56

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 June 30, ~~2014~~2015 was~~$24.0 million~~. $22.8 million. This cost is expected to be recognized over a weighted-average period of ~~2.2~~2.0 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~~three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.

In January ~~2014,~~2015, the Compensation Committee awarded a total of ~~42,151~~29,398 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~~2017 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:


	Six Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2015			2014

Expected term of award	3 years			3 years			3 years			3 years
Risk-free interest rate	0.8		%	0.4		%	0.9		%	0.8		%
Expected volatility	55.2		%	56.6		%	53.0		%	55.2		%
Weighted-average grant date fair value per share	$	56.87		$	49.04		$	57.35		$	56.87

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 the six months ended June 30, ~~2014~~2015:

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 June 30, 2014
114,262
48.59



	Shares	Weighted-Average Grant-Date Fair Value per Share

Non-vested at December 31, 2014	83,721	$	52.98
Granted	29,398	57.35
Non-vested at June 30, 2015	113,119	54.12

The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:


	As of/Year Ended June 30,				As of/for the Six Months Ended June 30,
	2014		2013		2015		2014
	(in thousands, except per share data)				(in thousands, except per share data)

Total intrinsic value of market-based awards non-vested	$	7,216	$	4,235	$	6,068	$	7,216
Market price per common share as of June 30,	63.15		51.48		53.64		63.15
Weighted-average grant date fair value per share	56.87		49.04		57.35		56.87

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our condensed consolidated ~~statement~~statements of operations as of June 30, ~~2014~~2015 was ~~$3.1 million~~.$2.9 million. This cost is expected to be recognized over a weighted-average period of ~~2.0~~1.8 years.

NOTE 1112 - 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.

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

Three Months Ended June 30, Six Months Ended June 30,
2014 2013 2014 2013
(in thousands)

Weighted-average common shares outstanding - basic 35,762
30,332
35,726
30,301
Dilutive effect of:
Restricted stock —
313
—
—
SARs —
26
—
—
Stock options —
1
—
—
Non-employee director deferred compensation —
4
—
—
Convertible notes —
338
—
—
Weighted-average common shares and equivalents outstanding - diluted 35,762
31,014
35,726
30,301



	Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014
	(in thousands)

Weighted-average common shares outstanding - basic	40,035	35,762	38,202	35,726
Weighted-average common shares and equivalents outstanding - diluted	40,035	35,762	38,202	35,726

We reported a net loss for the three and six months ended June 30, ~~2014~~2015 and ~~for the~~ ~~six~~ ~~months ended~~ ~~June 30, 2013~~.2014, respectively. As a result, our basic and diluted weighted-average common shares outstanding were the same ~~due to the fact that~~as the effect of the common share equivalents was anti-dilutive.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 June 30,		Six Months Ended June 30,		Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013	2015	2014	2015	2014
	(in thousands)				(in thousands)

Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	896	5	859	893	871	896	832	859
SARs	92	20	96	54	108	92	89	96
Stock options	4	—	4	7	4	4	4	4
Non-employee director deferred compensation	5	—	5	4	6	5	6	5
Convertible notes	881	—	758	206	677	881	523	758
Total anti-dilutive common share equivalents	1,878	25	1,722	1,164	1,666	1,878	1,454	1,722

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~~$42.40 per share. The Convertible Notes could be included in the ~~dilutive~~diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the ~~$42.40~~$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 and six months ended June 30, ~~2014~~2015 and ~~the six months ended~~ ~~June 30, 2013~~2014, respectively, as the effect would be anti-dilutive to our earnings per share. ~~Shares issuable upon conversion of the Convertible Notes were included in the diluted earnings per share calculation for the three months ended~~ ~~June 30, 2013~~ ~~as the average market price during the period exceeded the conversion price.~~

NOTE 1213 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS

~~Appalachian Basin.~~In ~~December 2013,~~October 2014, we ~~divested~~completed the sale of our ~~shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil~~entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and ~~natural gas properties previously~~other working capital adjustments, of approximately $192 million, comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million. The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned ~~directly~~ by ~~us,~~PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million. Proceeds from the divestiture were used to reduce outstanding borrowings on our revolving credit facility and to fund a portion of our 2014 capital budget. The divestiture represented a strategic shift that will have a major effect on our operations, in that our organizational structure no longer has joint venture partners or dry gas assets. Therefore, our proportionate share of ~~PDCM,~~PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the condensed consolidated statements of operations for ~~aggregate consideration of approximately $20.6 million, of which our share of~~ the ~~proceeds was approximately $5.1 million. We received our proportionate share of cash~~three and six months ended June 30, 2014.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

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, through our ownership in PDCM, 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. On~~ ~~July 29, 2014, we signed a definitive agreement to sell our entire 50% interest in PDCM to an unrelated third-party. See Note 15,~~ ~~Subsequent Events, for additional information.There can be no assurance we will be successful in closing the transaction. In addition, we may have greater than expected purchase price reductions.~~

~~Piceance Basin and NECO.~~ In June 2013, we divested our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets 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. Additionally, certain firm transportation obligations and natural gas hedging positions were assumed by the buyer. Following the sale, 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 thefollowing table presents condensed consolidated statement of operations ~~for the three months ended June 30, 2013. The sale of our other non-core Colorado oil and gas properties did not meet the requirements~~data related to ~~be accounted for as~~ discontinued ~~operations.~~operations:



Condensed consolidated statements of operations - discontinued operations	Three Months Ended June 30, 2014			Six Months Ended June 30, 2014

Revenues
Crude oil, natural gas and NGLs sales	$	8,907		$	18,738
Commodity price risk management loss, net	(768		)	(3,016		)
Well operations, pipeline income and other	30			52
Total revenues	8,169			15,774

Costs, expenses and other
Production costs	2,980			6,101
Impairment of crude oil and natural gas properties	90			159
Depreciation, depletion and amortization	4,107			7,857
Other	1,241			2,389
Gain on sale of properties and equipment	(340		)	(194		)
Total costs, expenses and other	8,078			16,312

Interest expense	(865		)	(1,512		)
Interest income	69			133
Loss from discontinued operations	(705		)	(1,917		)
Provision for income taxes	1,896			2,389
Income from discontinued operations, net of tax	$	1,191		$	472

The following table presents ~~statement of operations data~~supplemental cash flows information related to our 50% ownership interest in PDCM, which is classified as discontinued ~~operations for the Piceance Basin and NECO divestitures:~~operations:

Condensed consolidated statements of operations - discontinued operations Three Months Ended June 30, 2013 Six Months Ended June 30, 2013

Revenues
Crude oil, natural gas and NGLs sales $ 10,182
$ 20,456
Sales from natural gas marketing 586
1,036
Well operations, pipeline income and other 409
859
Total revenues 11,177
22,351

Costs, expenses and other
Production costs 2,564
7,957
Cost of natural gas marketing 540
994
Depreciation, depletion and amortization —
2,258
Other 1,959
2,454
Loss on sale of properties and equipment 1,076
1,076
Total costs, expenses and other 6,139
14,739

Income from discontinued operations 5,038
7,612
Provision for income taxes (1,622 ) (2,659 )
Income from discontinued operations, net of tax $ 3,416
$ 4,953



Supplemental cash flows information - discontinued operations	Six Months Ended June 30, 2014
	(in thousands)
Cash flows from investing activities:
Capital expenditures	$	(15,851	)

Significant non-cash investing items:
Change in accounts payable related to purchases of properties and equipment	(5,473		)

Assets held for sale of $2.9 million as of June 30, 2015 and December 31, 2014 represents the carrying value of approximately 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters.

~~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 $10.7 million~~ ~~and~~ ~~$20.1 million for the three and six months ended~~ ~~June 30, 2014, respectively, related to the marketing of natural gas on behalf of PDCM compared to $4.1 million and $7.8 million for the three and six months ended~~ ~~June 30, 2013, respectively. Our cost of natural gas marketing includes $0.3 million~~ ~~and~~ ~~$0.6 million for the three and six months ended~~ ~~June 30, 2013, respectively, related to the marketing of natural gas on behalf of our affiliated partnerships.~~

Amounts due from/to affiliates primarily relate to amounts billed for certain well operating and administrative services provided to PDCM and, to a lesser extent, costs resulting from audit and tax preparation services for our affiliated partnerships. Amounts billed to PDCM for these services were $2.1 million and ~~$4.4 million~~ ~~in the three and six months ended~~ ~~June 30, 2014, respectively, compared to $3.4 million and~~ ~~$6.8 million~~ ~~in the three and six months ended~~ ~~June 30, 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:

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

Three Months Ended June 30, Six Months Ended June 30,
Condensed consolidated statement of operations line item 2014 2013 2014 2013
(in thousands)

Production costs $ 417
$ 986
$ 1,022
$ 2,053
Exploration expense —
134
—
239
General and administrative expense 625
618
1,181
1,132

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.

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.~~Amounts. Unallocated income includes unallocated other revenue, less corporate general and 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 June 30, Six Months Ended June 30,
2014 2013 2014 2013
(in thousands)
Segment revenues:
Oil and gas exploration and production $ 87,057
$ 103,226
$ 190,382
$ 161,382
Gas marketing 22,415
18,079
49,352
31,749
Total revenues $ 109,472
$ 121,305
$ 239,734
$ 193,131

Segment income (loss) before income taxes:
Oil and gas exploration and production $ 6,265
$ 56,372
$ 40,271
$ 22,671
Gas marketing (13 ) 13
54
(52 )
Unallocated (54,985 ) (30,092 ) (92,572 ) (59,773 )
Income (loss) before income taxes $ (48,733 ) $ 26,293
$ (52,247 ) $ (37,154 )

June 30, 2014 December 31, 2013
(in thousands)
Segment assets:
Oil and gas exploration and production $ 1,977,181
$ 1,937,251
Gas marketing 23,669
20,342
Unallocated 85,575
67,610
Total assets $ 2,086,425
$ 2,025,203

1918

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

~~NOTE 15 - SUBSEQUENT EVENTS~~

The following tables present our segment information:

On ~~July 29, 2014, we signed a definitive agreement pursuant to which we agreed to sell our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration of approximately~~ ~~$250 million, subject to certain purchase price adjustments. Our net pre-tax proceeds from the sale, after our share of PDCM's debt repayment and other working capital adjustments, is expected to be approximately~~ ~~$190 million, comprised of~~ ~~$150 million~~ ~~in cash and a~~ ~~$40 million~~ promissory note due in 2020. The transaction includes the buyer's assumption of our share of the firm transportation obligations related to the assets owned by PDCM as well as our share of certain of PDCM's natural gas hedging positions for the years 2014 and 2015. The divestiture is expected to close in October 2014. There can be no assurance we will be successful in closing the transaction. In addition, we may have greater than expected purchase price reductions.



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)
Segment revenues:
Oil and gas exploration and production	$	48,437		$	78,888		$	189,836		$	174,608
Gas marketing	2,523			22,415			5,756			49,352
Total revenues	$	50,960		$	101,303		$	195,592		$	223,960

Segment loss before income taxes:
Oil and gas exploration and production	$	(46,425	)	$	4,586		$	11,736		$	37,727
Gas marketing	(313		)	(13		)	(337		)	54
Unallocated	(30,248		)	(52,601		)	(60,600		)	(88,111		)
Loss before income taxes	$	(76,986	)	$	(48,028	)	$	(49,201	)	$	(50,330	)



	June 30, 2015		December 31, 2014
	(in thousands)
Segment assets:
Oil and gas exploration and production	$	2,313,625	$	2,254,751
Gas marketing	4,525		6,979
Unallocated	70,593		75,984
Assets held for sale	2,874		2,874
Total assets	$	2,391,617	$	2,340,588

2019

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PDC ENERGY, INC.

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

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

EXECUTIVE SUMMARY

Financial Overview

~~We recorded substantial increases in crude oil, natural gas and NGLs sales~~Production volumes from continuing operations ~~during~~increased substantially to 3.4 MMboe and 6.3 MMboe for the three and six months ended June 30, ~~2014~~2015, respectively, representing an increase of 46% and 44%, as ~~a result of our significant increase in production and, to a lesser extent, higher commodity prices. Total crude oil, natural gas and NGLs sales increased~~ ~~$62.4 million, or~~ ~~81%, and~~ ~~$112.8 million, or~~ ~~72%, during the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014, respectively,~~ compared to the three and six months ended June 30, ~~2013. Our crude oil, natural gas and NGLs production from continuing operations averaged~~ ~~29.7~~ ~~Mboe per day and~~ ~~28.2~~ ~~Mboe per day during the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014, respectively, an increase of approximately~~ ~~64%~~ ~~and~~ ~~54%~~ ~~compared to the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2013, respectively.~~2014. The increase in production isvolumes was primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg ~~Field.~~Field and, to a lesser extent, the completion of two four-well pads in the Utica Shale. Crude oil production from continuing operations increased 47% and 36% for the three and six months ended June 30, 2015, respectively, while NGLs production from continuing operations increased 37% and 35%, respectively, compared to the same prior year periods. Crude oil production comprised approximately 47% of total production from continuing operations during the three and six months ended June 30, 2015. Our liquids percentage of total production from continuing operations was ~~55%~~64% and ~~57%~~63% during the three and six months ended June 30, ~~2014~~,2015, respectively. Natural gas production from continuing operations increased 49% and 59% during the three and six months ended June 30, 2015, respectively, compared to~~54%~~ ~~during each of~~ the same prior year ~~periods. Higher~~periods, due to our recent focus on developmental drilling in the inner and middle core of the Wattenberg Field. As a result of better than expected production during the first half of 2015, as well as improved drilling results and efficiencies and a reduction in well development costs, we have revised our expected 2015 production. See 2015 Operational Outlook below for additional information.

Crude oil, natural gas and NGLs sales from continuing operations, coupled with the impact of settlement of derivatives, increased during the three and six months ended June 30, 2015 as increased production and positive net settlements on derivative positions more than offset the effect of declines in commodity prices. Lower crude oil and natural gas index prices ~~at derivatives settlement resulted in~~during the three and six months ended June 30, 2015 were the primary reason for significant positive net settlements on derivative positions of $44.1 million and $94.5 million, respectively, compared to negative net settlements ~~on derivatives~~ of ~~$10.4~~$9.8 million and ~~$18.7~~$17.1 million during the three and six months ended June 30, 2014,~~, respectively, compared to positive net settlements on derivatives of~~ ~~$3.9 million~~ ~~and~~ ~~$12.4 million~~ ~~during the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2013~~, respectively. Crude oil, natural gas and NGLs sales, including the impact of net settlements on derivatives, ~~was~~ ~~$129.5~~were $141.0 million and ~~$251.1~~$265.5 million ~~during the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014, respectively, compared to~~ ~~$81.4 million~~ ~~and~~ ~~$169.4 million~~ ~~during the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2013, respectively. This represents increases of 59% and 48%~~ during the three and six months ended June 30, 2015, respectively, compared to $121.2 million and $233.9 million during the three and six months ended June 30, 2014, respectively. This represents increases of 16% and 14%, respectively, in the three and six months ended June 30, 2015, compared to the same prior year periods.

~~Three other areas showed significant~~Significant changes ~~during 2014 as compared~~impacting our results of operations for the three months ended June 30, 2015 include the following:

Crude oil, natural gas and NGLs sales from continuing operations decreased to ~~2013. General and administrative expense increased to $40.7 million and $64.3~~$96.9 million during the three ~~and~~ ~~six~~months ended June 30, ~~2014, respectively,~~2015 compared to ~~$15.8~~$131.0 million in the same prior year period, due to a 49% decrease in the weighted-average realized prices of crude oil, natural gas and ~~$30.9~~NGLs;

Positive net settlements on derivatives increased to $44.1 million during the three ~~and~~ ~~six~~months ended June 30, ~~2013, respectively, primarily attributable~~2015 compared to a ~~$20.8~~negative net settlements on derivatives of $9.8 million ~~and $24.1 million charge recorded during~~ in the ~~respective periods in connection with certain class action litigation. In addition, the~~same prior year period, due to lower crude oil and natural gas ~~forward curves shifted higher~~index settlement prices;

Negative net change in the fair value of unsettled derivative positions during the ~~current year resulting in~~three months ended June 30, 2015 was $93.1 million compared to a negative net change in the fair value of unsettled ~~derivatives~~derivative positions of ~~$43~~$42.8 million during the same prior year period, primarily attributable to the upward shift in the crude oil forward curve;

General and ~~$61.9~~administrative expense decreased to $18.7 million for the three months ended June 30, 2015 compared to $39.4 million in the same prior year period, primarily attributable to $20.8 million recorded during the three ~~and six~~ months ended June 30, 2014~~, respectively, compared~~ in connection with certain partnership-related class action litigation; and

Depreciation, depletion and amortization expense increased to ~~a positive net change in the fair value of unsettled derivatives of $20.8~~$70.1 million during the three months ended June 30, ~~2013~~ ~~and a negative net change~~2015 compared to $49.6 million in the ~~fair value of unsettled derivatives of $10 million during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2013. Finally,~~same prior year period, primarily due to increased production, offset in part by lower weighted-average depreciation, depletion and amortization ~~expense increased to $53.7 million and $100.4 million during the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014, respectively, compared to~~ ~~$27.8 million~~ ~~and~~ ~~$55.7 million~~ ~~during the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2013, respectively, due primarily to the increase in production.~~rates.

~~Select financial metrics for the three months ended~~ ~~June 30, 2014~~ ~~compared to the three months ended~~ ~~June 30, 2013~~ ~~were as follows:~~

~~Adjusted net loss~~Significant changes impacting our results of $1.5 million compared to an adjusted net income of $7.0 million in the prior period. Excluding the after-tax impact of the litigation charge recorded in general and administrative expense, adjusted net income in the current period would have been $11.4 million;

~~Adjusted cash flows from~~ operations of $55.0 million compared to $46.4 million in the prior period. Excluding the after-tax impact of the litigation charge recorded in general and administrative expense, adjusted cash flows from operations in the current period would have been $75.8 million; and

Adjusted EBITDA of $62.7 million compared to $54.1 million in the prior period. Excluding the impact of the litigation charge recorded in general and administrative expense, adjusted EBITDA in the current period would have been $83.5 million.

~~Select financial metrics~~ for the six months ended June 30, ~~2014~~ ~~compared to~~2015 include the ~~six months ended~~ ~~June 30, 2013~~ ~~were as follows:~~following:

~~Adjusted net income of~~ ~~$8.1~~Crude oil, natural gas and NGLs sales from continuing operations decreased to $171.0 million ~~compared to an adjusted net loss of~~ ~~$13.4 million~~ ~~in the prior period. Excluding the after-tax impact of the litigation charge recorded in general and administrative expense~~ during the six months ended June 30, ~~2014~~2015 compared to $251.0 million in the same prior year period, due to a 53% decrease in the weighted-average realized prices of crude oil, natural gas and NGLs;

Positive net settlements on derivatives increased to $94.5 million during the ~~impairment charge~~six months ended June 30, 2015 compared to negative net settlements on derivatives of $17.1 million in the same prior year period, due to lower crude oil and natural gas index settlement prices;

General and administrative expense decreased to $37.3 million for the six months ended June 30, 2015 compared to $61.9 million in the same prior year period, primarily attributable to $24.1 million recorded during the six months ended June 30, ~~2013~~ ~~related to our shallow Upper Devonian Appalachian Basin assets, adjusted net income~~2014 in ~~the current period would have been $23.0 million compared to $14.4 million during the prior period;~~

~~Adjusted cash flows from operations of~~ ~~$124.7 million~~ ~~compared to~~ ~~$98.7 million~~ ~~in the prior period. Excluding the after-tax impact of the litigation charge recorded in general~~connection with certain partnership-related class action litigation; and ~~administrative expense, adjusted cash flows from operations in the current period would have been $148.8 million; and~~

~~Adjusted EBITDA of~~ ~~$139.2 million~~ ~~compared to~~ ~~$115.3 million~~ ~~in the prior period. Excluding the impact of the litigation charge recorded in general and administrative expense, adjusted EBITDA in the current period would have been $163.3 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.~~

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Depreciation, depletion and amortization expense increased to $125.9 million during the six months ended June 30, 2015 compared to $92.5 million in the same prior year period, primarily due to increased production, offset in part by lower weighted-average depreciation, depletion and amortization rates.

Available liquidity as of June 30, ~~2014~~2015 was ~~$484.2~~$386.7 million ~~including $6.0 million related to PDCM,~~ compared to ~~$647.0~~$398.4 million ~~including $16.1 million related to PDCM,~~ as of December 31, ~~2013.~~2014. Available liquidity as of June 30, 2015 is comprised of ~~$40.4~~$1.4 million of cash and cash equivalents and ~~$443.8~~$385.3 million available for borrowing under our revolving credit ~~facilities as~~facility. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of ~~June 30, 2014~~.the agreement. In May 2015, we completed the semi-annual redetermination of the borrowing base under our revolving credit facility, which resulted in the reaffirmation of the borrowing base at $700 million. We have continued to elect to maintain the aggregate commitment at $450 million.

In March 2015, we completed a public offering of 4,002,000 shares of our common stock for net proceeds of approximately $203 million, after deducting offering expenses and underwriting discounts. We used a portion of the proceeds of the offering to repay all amounts then outstanding on our revolving credit facility and used the remaining amounts to fund a portion of our capital program. With our current derivative position, available liquidity and expected cash flows from operations, we believe we have sufficient liquidity to allow us to execute our ~~expanded drilling~~expected capital program through ~~2014.~~

In ~~July 2014, we signed a definitive agreement pursuant to which we agreed to sell our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration~~the remainder of ~~approximately~~ ~~$250 million, subject to certain purchase price adjustments. Our net pre-tax proceeds from the sale, after our share of PDCM's debt repayment and other working capital adjustments, is expected to be approximately~~ ~~$190 million, comprised of~~ ~~$150 million~~ ~~in cash and a~~ ~~$40 million~~ promissory note due in 2020. The transaction includes the buyer's assumption of our share of the firm transportation obligations related to the assets owned by PDCM as well as our share of certain PDCM's natural gas hedging positions for the years 2014 and 2015. The divestiture is expected to close in October 2014. We expect to use the proceeds from the divestiture to fund a portion of our 2014 capital program. There can be no assurance that this transaction will close as planned. In addition, we may have greater than expected purchase price reductions.

Operational Overview

Drilling Activities. During the six months ended June 30, ~~2014~~2015, we continued to execute our strategic plan of increasing ~~our overall~~ production, reserves and ~~liquids mix by focusing our~~cash flows from drilling operations ~~primarily~~ in the ~~liquid-rich~~ Wattenberg Field in Colorado and completion activities in the ~~emerging~~ Utica Shale play in southeastern Ohio.

In the Wattenberg Field, we are currently running five automated drilling rigs. ~~We spudded 55~~During the six months ended June 30, 2015, we spud 77 horizontal wells and ~~turned in line 40~~turned-in-line 60 horizontal wells ~~during~~in the ~~six~~ ~~months ended~~ ~~June 30, 2014~~.Wattenberg Field. We also participated in 4226 gross, ~~9.5~~2.7 net, horizontal non-operated drilling projects and ~~turned in line 22~~17 gross, ~~4.7~~4.1 net, horizontal non-operated ~~wells.~~wells which were turned-in-line. We began implementing several well-recovery enhancements in 2015, including tighter spacing between frac intervals on all wells and drilling 40% of our wells with extended reach laterals of 6,500 feet to 7,000 feet. In the Utica Shale, we ~~had one drilling rig running~~completed the hydraulic fracturing of a four-well pad during the six months ended June 30, ~~2014~~ ~~and added a second rig~~2015. These wells were turned-in-line in ~~early July 2014. We spudded five horizontal wells during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~ ~~and turned in line two horizontal wells. During~~ the second quarter ~~a mechanical failure occurred during the drilling~~ of ~~a Utica Shale horizontal well leading to a loss of well control and the plugging and abandonment of the well. Costs incurred to remediate environmental issues that occurred as~~2015. As a result of the ~~mechanical failure~~four-well pads turned-in-line at the end of ~~approximately $6 million are expected to be recouped~~2014 and the second quarter of 2015, production volumes from ~~our insurance carrier. In~~ the ~~Marcellus~~Utica Shale ~~PDCM finalized drilling~~increased 57% and ~~completion operations on four horizontal wells that were in-process at December 31, 2013. These wells were turned in line as of~~ 43% during the three and six months ended June 30, ~~2014~~.2015, respectively, compared to the same prior year periods.

~~2014~~2015 Operational Outlook

We have raised our ~~expectations with respect~~expected full-year 2015 production guidance to ~~2014 production from~~a range between ~~9.5~~14.7 MMBoe to 1015.0 MMBoe, or 40,275 to 41,100 Boe per day, from the previous range of 13.5 MMBoe to between 10.7 MMBoe and 10.9 MMBoe, excluding the effect of the planned PDCM divestiture. Assuming the planned divestiture of PDCM closes in mid-October 2014, we would expect the new 2014 production range to decrease by approximately 0.314.5 MMBoe. ~~Overall, our previously announced 2014 capital budget is unchanged at $647 million and~~Crude oil is expected to ~~be used~~comprise 47% of our revised production and we expect a year-end exit rate exceeding 48 MBoe per day. We expect to increase our capital program from $473 million to a range between $520 million and $550 million, and to direct that capital primarily ~~for development~~to our drilling and selective acquisitions of additional acreage. However, the budget now includes $555 million of development capital and $92 million for leasehold acquisitions, exploration and other expenditures. The approximately $20 million reduction in developmental capital is due to several non-operated projectsprogram in the Wattenberg Field ~~now being projected~~where we have reduced our per well costs to approximately $3.1 million for ~~2015, rather than the fourth quarter of 2014.~~standard length laterals and $4.1 million for extended reach laterals. The increase in ~~the budget for leasehold acquisitions is~~expected capital expenditures will be funded by cash flows from increased production and cost savings from lower than expected well development costs. Further, due to ~~several additional opportunities~~improved drilling techniques and reduced drilling time, we have ~~pursued~~raised the number of horizontal Niobrara or Codell horizontal wells expected to ~~purchase Utica acreage.~~be spud and turned-in-line in 2015 to approximately 155 and 125, respectively, from a previous estimate of 119 and 109, respectively. Due to the increases in our drilling rig efficiencies, we are expecting to decrease our rig count from five rigs to four in late 2015. We may again revise our capital ~~budget~~program during the remainder of the year as a result of, among other things, the level of non-operated spending, the impact of non-consent elections on PDC-operated drilling activities, commodity prices, acquisitions or dispositions of assets, drilling results ~~commodity prices,~~and efficiencies, changes in our borrowing capacity and/or significant changes in cash flows. In particular, a further deterioration of commodity prices could negatively impact our financial condition and results of operations and cause us to reduce our planned capital expenditures.

Wattenberg ~~Field.~~Field. We expect to invest approximately ~~$443~~$485 million to $515 million in the Wattenberg Field in ~~2014, where we are currently running a five-rig~~2015, consisting of $451 million to $481 million for our operated drilling ~~program.~~program, equipment and other projects and $34 million for non-operated projects. We expect to spud ~~123 gross operated~~approximately 155 and turn-in-line 121 horizontal Niobrara or Codell wells, ~~in the field,~~ of which 96approximately 40% are expected to be ~~turned in line during 2014.~~extended reach laterals of approximately 6,500 feet to 7,000 feet. Approximately ~~$76 million~~75% of the ~~total Wattenberg Field capital budget is~~wells are expected to ~~be allocated~~target the Niobrara formation, with the remainder targeting the Codell formation. We expect to participate in approximately 54 gross, 8.5 net, non-operated ~~projects.~~horizontal opportunities in 2015. During the six months ended June 30, ~~2014~~,2015, we invested approximately ~~$207.1~~$295 million,, or ~~47%~~between 57% and 61%, of our ~~2014~~revised 2015 capital ~~budget~~forecast for the Wattenberg Field.

Utica ~~Shale.~~Shale ~~We expect~~. Based on current low commodity prices and large natural gas price differentials in Appalachia, we have elected to ~~invest approximately~~ ~~$192 million~~temporarily cease drilling in the Utica Shale in favor of allocating more of our 2015 capital program to our higher return projects in the Wattenberg Field's inner and middle core areas. In 2015, we plan to invest a total of $35 million in the Utica Shale to complete and turn-in-line the four-well pad that was in-process as of December 31, 2014 and for lease maintenance, exploration and other expenditures. We expect to ~~spud 18 horizontal wells, of which eight are expected to be turned in line during 2014. A second~~resume our Utica Shale drilling ~~rig was deployed in early July 2014. The Utica capital budget includes approximately $59 million to acquire additional contiguous acreage.~~program when commodity prices and net-back realizations rebound. During the six months ended June 30, ~~2014~~,2015, we invested approximately ~~$65~~$20 million,, or ~~34%~~57%, of our ~~2014~~revised 2015 capital ~~budget~~forecast for the Utica ~~Shale.~~

~~Marcellus Shale.~~ AsShale, the majority of ~~June 30, 2014, PDCM had invested its full 2014 capital budget of approximately~~ ~~$10 million~~ inwhich was for completion activities on the ~~Marcellus Shale. PDCM's capital budget was funded by PDCM's operating activities and borrowing under its credit facility.~~

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~~PDC ENERGY, INC.~~

~~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.~~four-well pad.

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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 June 30,							Six Months Ended June 30,							Three Months Ended June 30,								Six Months Ended June 30,
	2014			2013		Percentage Change		2014			2013		Percentage Change		2015			2014			Percentage Change		2015			2014			Percentage Change
	(dollars in millions, except per unit data)														(dollars in millions, except per unit data)
Production (1)
Crude oil (MBbls)	1,077.1			617.7		74.4	%	2,120.0			1,286.0		64.9	%	1,581.4			1,077.1			46.8	%	2,888.1			2,120.0			36.2	%
Natural gas (MMcf)	7,283.2			4,511.5		61.4	%	13,161.5			9,061.3		45.2	%	7,323.7			4,920.5			48.8	%	13,848.1			8,701.0			59.2	%
NGLs (MBbls)	411.0			276.5		48.6	%	790.5			514.8		53.6	%	565.0			411.0			37.5	%	1,065.5			790.5			34.8	%
Crude oil equivalent (MBoe) (2)	2,702.1			1,646.1		64.2	%	5,104.2			3,311.1		54.2	%	3,367.1			2,308.3			45.9	%	6,261.7			4,360.7			43.6	%
Average MBoe per day	29.7			18.1		64.1	%	28.2			18.3		54.1	%	37.0			25.4			45.9	%	34.6			24.1			43.6	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	98.9		$	53.9	83.5	%	$	188.6		$	112.1	68.2	%	$	76.4		$	98.9		(22.8	)%	$	128.4		$	188.6		(31.9	)%
Natural gas	29.7			17.1		73.7	%	56.5			31.1		81.7	%	14.9			20.8			(28.4	)%	30.6			37.7			(18.8	)%
NGLs	11.3			6.5		73.8	%	24.7			13.8		79.0	%	5.6			11.3			(50.4	)%	12.0			24.7			(51.4	)%
Total crude oil, natural gas and NGLs sales	$	139.9		$	77.5	80.5	%	$	269.8		$	157.0	71.8	%	$	96.9		$	131.0		(26.0	)%	$	171.0		$	251.0		(31.9	)%

Net Settlements on Derivatives (3)
Natural gas	$	(1.9	)	$	3.1	*		$	(5.9	)	$	11.2	*		$	7.1		$	(1.3	)	*		$	12.8		$	(4.2	)	*
Crude oil	(8.5		)	0.8		*		(12.8		)	1.2		*		37.0			(8.5		)	*		81.7			(12.9		)	*
Total net settlements on derivatives	$	(10.4	)	$	3.9	*		$	(18.7	)	$	12.4	*		$	44.1		$	(9.8	)	*		$	94.5		$	(17.1	)	*

Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	91.77		$	87.32	5.1	%	$	88.94		$	87.13	2.1	%	$	48.31		$	91.77		(47.4	)%	$	44.47		$	88.94		(50.0	)%
Natural gas (per Mcf)	4.08			3.79		7.7	%	4.29			3.44		24.7	%	2.03			4.23			(52.0	)%	2.21			4.34			(49.1	)%
NGLs (per Bbl)	27.60			23.55		17.2	%	31.24			26.76		16.7	%	10.01			27.60			(63.7	)%	11.23			31.24			(64.1	)%
Crude oil equivalent (per Boe)	51.78			47.10		9.9	%	52.85			47.41		11.5	%	28.79			56.76			(49.3	)%	27.32			57.57			(52.5	)%

Average Lifting Cost (per Boe) (4)
Average Lease Operating Expenses (per Boe) (4)
Wattenberg Field	$	5.12		$	4.01	27.7	%	$	4.64		$	3.90	19.0	%	$	3.92		$	5.12		(23.4	)%	$	4.80		$	4.64		3.4	%
Utica Shale	1.85			3.21		(42.4	)%	1.30			3.00		(56.7	)%	1.55			1.85			(16.2	)%	1.67			1.30			28.5	%
Marcellus Shale	0.96			5.19		(81.5	)%	1.14			5.20		(78.1	)%
Weighted-average	4.28			4.19		2.1	%	3.87			4.09		(5.4	)%	3.71			4.85			(23.5	)%	4.52			4.35			3.9	%

Natural Gas Marketing Contribution Margin (5)	$	—		$	—	*		$	0.1		$	—	*		$	(0.3	)	$	—		*		$	(0.3	)	$	0.1		*

Other Costs and Expenses
Exploration expense	$	0.3		$	1.4	(80.7	)%	$	0.6		$	3.1	(81.3	)%	$	0.3		$	0.3		(0.4	)%	$	0.6		$	0.6		(3.9	)%
Impairment of crude oil and natural gas properties	0.9			1.5		(37.5	)%	1.9			48.0		*		2.8			0.8			227.0	%	5.3			1.8			199.0	%
General and administrative expense	40.7			15.8		157.7	%	64.3			30.9		108.0	%	18.7			39.4			(52.7	)%	37.3			61.9			(39.7	)%
Depreciation, depletion and amortization	53.7			27.8		93.3	%	100.4			55.7		80.1	%	70.1			49.6			41.2	%	125.9			92.5			36.1	%

Interest Expense	$	13.1		$	13.1	(0.2	)%	$	25.9		$	26.4	(2.1	)%
Interest expense															$	11.6		$	12.2		(5.1	)%	$	23.3		$	24.4		(4.5	)%


*	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 from continuing operations:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
Production by Operating Region	2014	2013	Percentage Change		2014	2013	Percentage Change		2015	2014	Percentage Change		2015	2014	Percentage Change
Crude oil (MBbls)
Wattenberg Field	1,008.5	605.5	66.6	%	1,961.1	1,256.2	56.1	%	1,449.7	1,008.5	43.7	%	2,640.9	1,961.1	34.7	%
Utica Shale	68.6	11.3	*		158.9	28.0	*		131.7	68.6	92.0	%	247.2	158.9	55.6	%
Marcellus Shale (1)	—	0.9	*		—	1.8	*
Total	1,077.1	617.7	74.4	%	2,120.0	1,286.0	64.9	%	1,581.4	1,077.1	46.8	%	2,888.1	2,120.0	36.2	%
Natural gas (MMcf)
Wattenberg Field	4,338.2	2,916.2	48.8	%	7,653.2	5,891.7	29.9	%	6,651.1	4,338.2	53.3	%	12,562.4	7,653.2	64.1	%
Utica Shale	582.3	43.6	*		1,011.6	43.9	*		672.6	582.3	15.5	%	1,285.7	1,047.8	22.7	%
Marcellus Shale (1)	2,362.7	1,551.7	52.3	%	4,496.7	3,125.7	43.9	%
Total	7,283.2	4,511.5	61.4	%	13,161.5	9,061.3	45.2	%	7,323.7	4,920.5	48.8	%	13,848.1	8,701.0	59.2	%
NGLs (MBbls)
Wattenberg Field	386.3	275.2	40.4	%	730.2	513.5	42.2	%	509.9	386.3	32.0	%	961.8	730.2	31.7	%
Utica Shale	24.7	1.3	*		60.3	1.3	*		55.1	24.7	123.1	%	103.7	60.3	72.0	%
Total	411.0	276.5	48.6	%	790.5	514.8	53.6	%	565.0	411.0	37.5	%	1,065.5	790.5	34.8	%
Crude oil equivalent (MBoe)
Wattenberg Field	2,117.9	1,366.7	55.0	%	3,966.8	2,751.7	44.2	%	3,068.2	2,117.9	44.9	%	5,696.5	3,966.8	43.6	%
Utica Shale	190.4	19.8	*		387.9	36.6	*		298.9	190.4	57.0	%	565.2	393.9	43.5	%
Marcellus Shale (1)	393.8	259.6	51.7	%	749.5	522.8	43.4	%
Total	2,702.1	1,646.1	64.2	%	5,104.2	3,311.1	54.2	%	3,367.1	2,308.3	45.9	%	6,261.7	4,360.7	43.6	%


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

Amounts may not recalculate due to rounding.


	Three Months Ended June 30,						Six Months Ended June 30,									Three Months Ended June 30,										Six Months Ended June 30,
Average Sales Price by Operating Region					Percentage Change									Percentage Change									Percentage Change										Percentage Change
(excluding net settlements on derivatives)	2014		2013			2014				2013				Percentage Change	2015				2014				Percentage Change		2015				2014				Percentage Change
Crude oil (per Bbl)
Wattenberg Field	$	91.56	$	87.31	Percentage Change	4.9%		$	88.88			$	87.09		2.1%		$	48.09			$	91.56		(47.5	)%		$	44.41			$	88.88		(50.0	)%
Utica Shale	94.79		87.72		8.1%		89.75				89.01			0.8%		50.78				94.79			(46.4	)%		45.12				89.75			(49.7	)%
Marcellus Shale (1)	—		88.05		*		—				87.93			*
Weighted-average price	91.77		87.32		5.1%		88.94				87.13			2.1%		48.31				91.77			(47.4	)%		44.47				88.94			(50.0	)%
Natural gas (per Mcf)
Wattenberg Field	$	4.26	$	3.71	14.8%		$	4.35			$	3.36		29.5%		$	2.03			$	4.26		(52.3	)%		$	2.21			$	4.35		(49.2	)%
Utica Shale	4.01		3.53		13.6%		4.27				3.52			21.3%		2.06				4.01			(48.6	)%		2.22				4.27			(48.0	)%
Marcellus Shale (1)	3.77		3.94		(4.3)%		4.20				3.58			17.3%
Weighted-average price	4.08		3.79		7.7%		4.29				3.44			24.7%		2.03				4.23			(52.0	)%		2.21				4.34			(49.1	)%
NGLs (per Bbl)
Wattenberg Field	$	26.67	$	23.46	13.7%		$	29.48			$	26.72		10.3%		$	10.01			$	26.67		(62.5	)%		$	10.91			$	29.48		(63.0	)%
Utica Shale	42.15		41.21		2.3%		52.59				41.21			27.6%		9.95				42.15			(76.4	)%		14.17				52.59			(73.1	)%
Weighted-average price	27.60		23.55		17.2%		31.24				26.76			16.7%		10.01				27.60			(63.7	)%		11.23				31.24			(64.1	)%
Crude oil equivalent (per Boe)
Wattenberg Field	$	57.19	$	51.32	11.4%		$	57.76			$	51.94		11.2%		$	28.78			$	57.19		(49.7	)%		$	27.31			$	57.76		(52.7	)%
Utica Shale	51.91		60.27		(13.9)%		56.10				73.72			(23.9)%		28.86				51.91			(44.4	)%		27.38				56.10			(51.2	)%
Marcellus Shale (1)	22.62		23.89		(5.3)%		25.19				21.72			16.0%
Weighted-average price	51.78		47.10		9.9%		52.85				47.41			11.5%		28.79				56.76			(49.3	)%		27.32				57.57			(52.5	)%


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

Amounts may not recalculate due to rounding.

~~______________~~

~~(1) On~~ ~~July 29, 2014~~, we signed a definitive agreement to sell our entire 50% interest in PDCM to an unrelated third-party. See Note 15, Subsequent Events, to our condensed consolidated financial statements included elsewhere in this report for additional information. There can be no assurance we will be successful in closing the transaction. In addition, we may have greater than expected purchase price reductions.

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For the three and six months ended June 30, ~~2014~~,2015, crude oil, natural gas and NGLs sales revenue ~~increased~~decreased compared to the three and six months ended June 30, ~~2013~~2014 due to the following (in millions):

June 30, 2014
Three Months Ended Six Months Ended
Increase in production $ 53.8
$ 94.1
Increase in average natural gas price 2.1
11.3
Increase in average crude oil price 4.8
3.8
Increase in average NGLs price 1.7
3.6
Total increase in crude oil, natural gas and NGLs sales revenue $ 62.4
$ 112.8



	June 30, 2015
	Three Months Ended			Six Months Ended
Decrease in average crude oil price	$	(68.7	)	(128.4		)
Decrease in average natural gas price	(16.2		)	(29.5		)
Decrease in average NGLs price	(10.0		)	(21.3		)
Increase in production	60.8			99.2
Total decrease in crude oil, natural gas and NGLs sales revenue	$	(34.1	)	$	(80.0	)

~~As expected, we have experienced increases~~Production from continuing operations for the second quarter of 2015 was 3.4 million Boe, up from 2.3 million Boe in ~~gathering system pressures~~the second quarter of 2014. Year-to-date, production from continuing operations was 6.3 million Boe, up from 4.4 million Boe in the first six months of 2014. Production increased as a result of continued drilling and completion activities as discussed in Operational Overview, notwithstanding the adverse effect of challenging weather conditions in the Wattenberg Field byin May and June and continued high line pressures on the midstream gathering system of our primary ~~third-party mid-stream provider~~service provider. The difficult weather conditions delayed the turning-in-line of approximately 20 wells and shut in approximately 125 vertical wells during the ~~first~~quarter. While the effect of high line pressures during the quarter reduced our net legacy vertical production, we had accounted for essentially all of this reduction in our 2015 guidance range. The Lucerne II processing plant and additional new compressor stations on this gathering system began initial operations in June, resulting in immediate reductions in system line pressures. We anticipate further line pressure reductions in the second half of ~~2014 and~~2015. Further, we ~~have factored these higher line pressures into our production estimates for 2014. Overall,~~expect sustained relief of gathering system pressure through 2016, depending upon the ~~line pressures in the first half~~impact of 2014 were within our expectations and were lower than they were in the comparable periods of 2012 and 2013, primarily due to the commissioning of the O’Connor gas plant in the fall of 2013, the recent startup of an additional compressor station in 2014 and relatively mild summer temperatures in 2014. Ongoing industryreduced drilling activity in the ~~area will continue to increase volumes on the gathering system and our midstream service provider will be challenged to keep pace with new midstream infrastructure. We and other operators in the~~ field are working with the midstream service provider, who continues to implement a multi-year facility expansion program that will significantly increase the long-term gathering and processing capacity of the system.going forward. 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. The price of crude oil increased during the first half of 2015 from the lows of December 2014, but prices remained far lower than they were in the first half of 2014. Natural gas prices remain at the low levels seen since late 2014, and are at significantly lower levels than the first half of 2014. NGL prices declined significantly during the first half of 2015 and also remain at low levels relative to those experienced in the first half of 2014. These declines in price ~~variations can~~ have had 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, primarily 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~~pricing. We began delivering crude oil in accordance with our long term commitment to the White Cliffs pipeline at the beginning of July 2015. This facilitates deliveries of a significant portion of our crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our wells in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability and reducing the overall physical footprint of our well pads. We continue to evaluate crude oil takeaway ~~capacity.~~options to determine the benefits of additional longer term commitments to deliver to competitive markets. In the Utica Shale, crude oil and condensate is sold to a local ~~purchasers~~purchaser at each individual well site based on NYMEX pricing, adjusted for quality 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 and local utility prices, adjusted for certain deductions, while natural gas produced in the Utica Shale ~~and Marcellus Shale~~ is based on TETCO M-2 pricing with approximately 50% of our volumes currently receiving an increase in price based upon delivery to the Chicago/Midwest market. Our sale of a significant portion of our Utica Shale gas to the Midwest market has helped to reduce the impact of the significant differentials that exist between the TETCO M-2 realizations and the NYMEX pricing, adjusted for differentials and other deductions. The differentials at our two primary sales hubs for these basins have recently widened primarily due to current oversupply in the Appalachian region.gas price. We anticipate that ~~these widened~~the significant Appalachian pipeline differentials will continue ~~through 2014.~~ at least into 2016.

Our price for NGLs produced in the Wattenberg Field is based on a combination of prices from ~~both~~ the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. The NGLs produced in the Utica Shale are sold based on month-to-month pricing into various markets. Due to an oversupply and growing inventories of nearly all domestic NGLs products, our realized sales price for NGLs has declined significantly and we expect this trend to continue.

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, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing 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~~or 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 June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013		2015		2014		2015		2014
	(in millions)								(in millions)

Lease operating expenses	$	11.6	$	6.9	$	19.8	$	13.5	$	12.5	$	11.2	$	28.3	$	18.9
Production taxes	8.7		5.3		16.3		10.7		3.9		7.6		7.7		14.0
Transportation, gathering and processing expenses	2.2		2.7		4.4		4.3		1.3		0.8		2.6		2.1
Overhead and other production expenses	4.3		1.3		7.5		3.5		3.8		4.2		7.0		6.9
Total production costs	$	26.8	$	16.2	$	48.0	$	32.0	$	21.5	$	23.8	$	45.6	$	41.9
Total production costs per Boe	$	9.90	$	9.83	$	9.40	$	9.67	$	6.38	$	10.30	$	7.29	$	9.60

Lease operating expenses. The ~~$4.7~~$1.3 million increase in lease operating expenses during the three months ended June 30, ~~2014~~2015 compared to the three months ended June 30, ~~2013~~2014 was primarily due to an increase of ~~$2.1 million for workover and maintenance related projects, an increase of $0.7~~$0.5 million for additional wages and employee benefits, ~~$0.7~~including costs for additional contract labor, $0.5 million for ~~environmental compliance and remediation projects and $0.3 million for~~lease operating expenses incurred on the ~~rental~~increasing number of ~~additional compressors used to accommodate high line pressures~~non-operated wells in the Wattenberg ~~Field. The~~ ~~$6.3~~Field, $0.4 million ~~increase in lease operating expenses during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~ ~~compared to the~~ ~~six~~ ~~months ended~~ ~~June 30, 2013~~ was primarily due to an increase of $2.4 million for workover and maintenance related projects, an increase of $1.0 million in additional wages and employee benefits, $0.9 million for environmental compliance and remediation projects, $0.7 million for the rental of additional compressors used to accommodate high line pressures in the Wattenberg Field, including costs for the rental of additional compressors and additional well maintenance, offset by a decrease of $0.5 million for workover, maintenance and repair related projects, including costs incurred for the plugging of older vertical wells. The $9.4 million increase in lease operating expenses during the six months ended June 30, 2015 compared to the six months ended June 30, 2014 was primarily due to an increase of $4.1 million for environmental remediation and regulatory compliance projects, an increase of $1.9 million for additional wages and employee benefits, including costs for additional contract labor, $1.2 million to accommodate high line pressures in the Wattenberg Field, including costs for the rental of additional compressors and additional well maintenance, an increase of $1.1 million for lease operating expenses incurred on the increasing number of non-operated ~~wells.~~wells in the Wattenberg Field and $0.6 million for additional costs pertaining to water hauling and disposal due to increased well counts and an increase in the number of related workovers performed in an effort to combat high line pressures.

Production taxes. Production taxes are directly related to crude oil, natural gas and NGLs sales. The ~~$3.4~~$3.7 million, or ~~64%~~49%, ~~increase~~decrease in production taxes for the three months ended June 30, ~~2014~~2015 compared to the three months ended June 30, ~~2013~~,2014, was primarily related to the ~~81% increase~~26% decrease in crude oil, natural gas and NGLs ~~sales.~~sales and, to a lesser extent, lower production tax rates. Similarly, the ~~$5.6~~$6.3 million, or ~~52%~~45%, ~~increase~~decrease in production taxes for the six months ended June 30, ~~2014~~2015 compared to the six months ended June 30, ~~2013~~,2014, was primarily related to the ~~72% increase~~32% decrease in crude oil, natural gas and NGLs ~~sales.~~

~~Transportation, gathering~~sales and, ~~processing expenses.~~ ~~The~~ ~~$0.5 million, or~~ ~~19%, decrease in transportation, gathering and processing expenses for the three months ended~~ ~~June 30, 2014~~ ~~compared to the three months ended~~ ~~June 30, 2013~~ ~~was primarily attributable~~ to a ~~reduction in our unutilized takeaway capacity costs resulting from the divestiture of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties. The~~ ~~$0.1 million, or~~ 2%~~, increase in transportation, gathering and processing expenses for the~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~ ~~compared to the~~ ~~six~~ ~~months ended~~ ~~June 30, 2013~~ was primarily attributable to an increase in Utica gas transportation expenses offset in part by a a reduction in our unutilized takeaway capacity costs resulting from the divestiture of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties.

~~Overhead and other~~lesser extent, lower production ~~expenses.~~ ~~Overhead and other production expenses increased $3.0 million during the three months ended~~ ~~June 30, 2014~~ ~~as compared to the three months ended~~ ~~June 30, 2013~~. The increase consisted of a $1.5 million increase in wages and employee benefits, mostly attributable to the fact that Utica Shale employee costs moved to production expense from exploration expense and an increase of $1.0 million for the write-off of costs due to changes in our drilling locations. Overhead and other production expenses increased $4.0 million during the ~~six~~ ~~months ended~~ ~~June 30, 2014~~ ~~as compared to the~~ ~~six~~ ~~months ended~~ ~~June 30, 2013~~. The increase consisted of a $2.9 million increase in wages and employee benefits, mostly attributable to the fact that Utica Shale employee costs moved to production expense from exploration expense and an increase of $0.9 million for the write-off of costs due to changes in our drilling locations.tax rates.

Commodity Price Risk Management, Net

We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our natural gas and crude oil production 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, before contract fees, related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps.

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~~

Net settlements are primarily the result of ~~Financial Instruments~~,crude oil and ~~Note 4,~~ ~~Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for additional details~~natural gas index prices at maturity of our derivative ~~financial instruments.~~instruments compared to the respective strike prices. Net change in fair value of unsettled derivatives is comprised of the net asset increase or decrease in the beginning-of-period fair value of derivative instruments that settled during the period and the net change in fair value of unsettled derivatives during the period. The corresponding impact of settlement of the derivative instruments that settled during the period is included in net settlements for the period as discussed above. Net change in fair value of unsettled derivatives during the period is primarily related to shifts in the crude oil and natural gas forward curves and changes in certain differentials.

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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 June 30,					Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013		2014			2013			2015			2014			2015			2014
	(in millions)											(in millions)
Commodity price risk management gain (loss), net:
Net settlements	$	(10.4	)	$	3.9	$	(18.7	)	$	12.4
Net settlements:
Natural gas												$	7.1		$	(1.3	)	$	12.7		$	(4.2	)
Crude oil												37.0			(8.5		)	81.7			(12.9		)
Total net settlements												44.1			(9.8		)	94.4			(17.1		)
Change in fair value of unsettled derivatives:
Reclassification of settlements included in prior period changes in fair value of derivatives												(54.3		)	7.6			(89.4		)	8.5
Natural gas fixed price swaps												(2.2		)	(0.9		)	12.1			(5.4		)
Natural gas basis swaps												(2.5		)	—			(2.0		)	(0.2		)
Natural gas collars												(0.8		)	(0.6		)	4.5			(0.9		)
Crude oil fixed price swaps												(24.5		)	(42.2		)	(1.5		)	(54.7		)
Crude oil collars												(8.8		)	(6.7		)	(0.5		)	(7.8		)
Net change in fair value of unsettled derivatives	(43.0		)	20.8		(61.9		)	(10.0		)	(93.1		)	(42.8		)	(76.8		)	(60.5		)
Total commodity price risk management gain (loss), net	$	(53.4	)	$	24.7	$	(80.6	)	$	2.4		$	(49.0	)	$	(52.6	)	$	17.6		$	(77.6	)

~~Net settlements for the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 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. For the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014, negative settlements on our crude oil positions were $8.5 million and $12.8 million, respectively, and negative settlements for the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~ on natural gas positions, exclusive of basis swaps, were $2.2 million and $6 million, respectively. The negative settlements were slightly offset by positive settlements on our basis swap positions of $0.3 million and $0.1 million for the three and ~~six~~ ~~months ended~~ ~~June 30, 2014, respectively. The net change in fair value of unsettled derivatives for the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~ includes a $7.9 million and $8.5 million net asset increase, respectively, 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 and ~~six~~ ~~months ended~~ ~~June 30, 2014~~ also includes a $50.9 million and $70.4 million decrease, respectively, in the fair value of unsettled derivatives during the period, primarily related to the upward shift in the crude oil forward curve.

~~Net settlements for the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 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. Positive settlements for the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2013~~ on our natural gas derivatives were $6.4 million and $18.6 million, respectively, and positive settlements were $0.8 million and $1.2 million, respectively, on our crude oil derivatives. The positive settlements on natural gas and crude oil derivatives were offset in part by negative settlements of $3.3 million and $7.4 million, respectively, on our basis swap positions. The net change in fair value of unsettled derivatives for the three and ~~six~~ ~~months ended~~ ~~June 30, 2013~~ includes a $3.2 million and $9.1 million net asset reduction, respectively, in the beginning-of-period fair value of derivative instruments that settled during the period and a $24 million and $7.8 million decrease, respectively, 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.

~~Table of contents~~

~~PDC ENERGY, INC.~~

Natural Gas Marketing

Fluctuations in our natural gas ~~marketing's~~marketing segment'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 June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013			2015			2014			2015			2014
	(in millions)												(in millions)
Natural gas sales revenue	$	22.2		$	16.7		$	50.0		$	31.1		$	2.4		$	22.2		$	5.7		$	50.0
Net settlements from derivatives	(0.1		)	(0.2		)	(0.6		)	—			0.2			(0.1		)	0.4			(0.6		)
Net change in fair value of unsettled derivatives	0.3			1.6			—			0.6			(0.1		)	0.3			(0.3		)	—
Other	—			—			—			0.1
Total sales from natural gas marketing	22.4			18.1			49.4			31.8			2.5			22.4			5.8			49.4

Costs of natural gas purchases	21.8			16.4			49.2			30.0			2.4			21.8			5.5			49.2
Net settlements from derivatives	(0.1		)	(0.2		)	(0.7		)	(0.1		)	0.2			(0.1		)	0.4			(0.7		)
Net change in fair value of unsettled derivatives	0.3			1.6			—			0.6			(0.1		)	0.3			(0.3		)	—
Other	0.4			0.3			0.8			1.3			0.3			0.4			0.5			0.8
Total costs of natural gas marketing	22.4			18.1			49.3			31.8			2.8			22.4			6.1			49.3

Natural gas marketing contribution margin	$	—		$	—		$	0.1		$	—		$	(0.3	)	$	—		$	(0.3	)	$	0.1

Natural gas sales revenue and cost of natural gas purchases ~~increased~~decreased in the three and six months ended June 30, ~~2014~~2015 compared to the three and six months ended June 30, ~~2013, mainly attributable to higher~~2014, as our Gas Marketing segment has scaled down following the divestiture of our Appalachian Basin natural gas ~~prices and production volumes.~~properties. Our Gas Marketing segment sold approximately 1.1 Bcf of natural gas at an average price of $1.30 per Mcf during the three months ended June 30, 2015, compared to approximately 5.6 Bcf of natural gas at an average price of $3.77 per Mcf during the three months ended June 30, 2014. Our Gas Marketing segment sold approximately 2.2 Bcf of natural gas at an average price of $1.57 per Mcf during the six months ended June 30, 2015, compared to approximately 11.4 Bcf of natural gas at an average price of $4.18 per Mcf during the six months ended June 30, 2014.

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

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

~~to offset those same physical positions.~~

~~Exploration Expense~~

~~The following table presents the major components of exploration expense:~~

Three Months Ended June 30, Six Months Ended June 30,
2014 2013 2014 2013
(in millions)

Geological and geophysical costs $ —
$ —
$ —
$ 0.5
Operating, personnel and other 0.3
1.4
0.6
2.6
Total exploration expense $ 0.3
$ 1.4
$ 0.6
$ 3.1

~~Geological and geophysical costs. Geological and geophysical costs during the~~ ~~six~~ ~~months ended~~ ~~June 30, 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 $1.1 million and~~ ~~$2.0 million~~ ~~decrease during the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~ compared to the same prior year period was primarily related to a reduction in Utica Shale personnel costs resulting from the reassignment of former exploration department personnel to other departments.

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to offset those same physical positions.

Impairment of Crude ~~oil~~Oil and Natural Gas Properties

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

Three Months Ended June 30, Six Months Ended June 30,
2014 2013 2014 2013
(in millions)

Impairment of proved properties $ —
$ —
$ —
$ 45.0
Impairment of individually significant unproved properties —
0.7
—
0.8
Amortization of individually insignificant unproved properties 0.9
0.8
1.9
2.1
Total impairment of crude oil and natural gas properties $ 0.9
$ 1.5
$ 1.9
$ 48.0

~~Impairment of proved properties.~~ ~~In the first quarter of 2013, we recognized an impairment charge of approximately~~ ~~$45.0~~increased to $2.8 million and $5.3 million for the three and six months ended June 30, 2015 compared to $0.8 million and $1.8 million for the three and six months ended June 30, 2014. The period-over-period increases were primarily related to ~~all~~a higher number of insignificant leases that were subject to amortization, primarily in the Utica Shale where we have altered drilling plans due to lower crude oil prices and, as a result, expect certain leases to expire. Further deterioration of commodity prices could result in additional impairment charges to our ~~shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia~~crude oil 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,~~ ~~to the accompanying condensed consolidated financial statements included elsewhere in this report for additional information regarding these properties, including the closing of the sale of these~~natural gas properties.

General and Administrative Expense

General and administrative expense ~~increased $24.9~~decreased $20.7 million to ~~$40.7~~$18.7 million for the three months ended June 30, ~~2014~~2015 compared to ~~$15.8~~$39.4 million for the three months ended June 30, ~~2013~~.2014. The ~~increase~~decrease was primarily attributable to a ~~$20.8~~$20.8 million ~~charge~~ recorded during the three months ended June 30, 2014 in connection with certain partnership-related class action litigation.

General and administrative expense decreased $24.6 million to $37.3 million for the six months ended June 30, 2015 compared to $61.9 million for the six months ended June 30, 2014. The decrease was primarily attributable to $24.1 million recorded during the six months ended June 30, 2014 in connection with certain partnership-related class action litigation ~~(not including~~and a ~~$3.3~~$1.3 million ~~charge recognized~~decrease in costs for legal and other professional services during the ~~first quarter of 2014),~~six months ended June 30, 2015. The decreases were offset in part by a ~~$2.2~~$0.9 million increase in payroll and employee benefits ~~of which $0.5 million was related to stock-based compensation, and a $1.4 million increase in costs for legal and other professional services.~~

~~General and administrative expense increased $33.4 million to $64.3 million for~~during the six months ended June 30, ~~2014~~ ~~compared to $30.9 million for the~~ ~~six~~ ~~months ended~~ ~~June 30, 2013. The increase was attributable to a $24.1 million charge recorded during the~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~ in connection with certain class action litigation, a $5 million increase in payroll and employee benefits, of which $1.6 million was related to stock-based compensation, and a $2.4 million increase in costs for legal and other professional services.2015.

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 ~~$52.3~~$69.0 million and ~~$97.6 million for the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014, respectively, compared to $26.6 million~~ ~~and~~ ~~$53.3 million~~ ~~for the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2013. The increase in our production for the three and~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~ ~~contributed $17 million and $28.9 million to these increases, respectively, while higher weighted-average depreciation, depletion and amortization rates contributed $8.7 million and $15.4~~$123.7 million for the three and six months ended June 30, ~~2014~~,2015, respectively, compared to $48.6 million and $90.4 million for the three and six months ended June 30, 2014. The period-over-period increases were comprised of increases of $22.3 million and $39.6 million due to higher production during the three and six months ended June 30, 2015, respectively, offset in part by decreases of $1.9 million and $6.3 million due to lower weighted-average depreciation, depletion and amortization rates during the three and six months ended June 30, 2015, respectively.

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
Operating Region/Area	2014		2013		2014		2013		2015		2014		2015		2014
	(per Boe)								(per Boe)
Wattenberg Field	$	20.55	$	17.91	$	19.91	$	17.45	$	21.09	$	20.55	$	20.50	$	19.91
Utica Shale	26.54		—		29.61		—		14.23		26.54		12.27		29.61
Marcellus Shale	9.51		8.07		9.51		10.13
Total weighted-average	19.37		16.14		19.12		16.10		20.48		21.05		19.76		20.77

The decrease in the Utica Shale DD&A expense rate during the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 was primarily due to the effect of an impairment recorded in December 2014 to write-down certain capitalized well costs on our Utica Shale proved producing properties, which lowered the net book value of the properties by approximately $112.6 million.

Non-crude oil and natural gas properties.Depreciation expense for non-crude oil and natural gas properties was ~~$1.4~~$1.1 million and ~~$2.8~~$2.2 million for the three and six months ended June 30, ~~2014~~,2015, respectively, compared to ~~$1.2~~$1.0 million and ~~$2.4~~$2.1 million for the three and six months ended June 30, ~~2013~~,2014, respectively.

Interest Income

Interest income increased to $1.1 million for the three months ended June 30, 2015 compared to $0.1 million for the three months ended June 30, 2014, mainly attributable to $1.1 million of non-cash interest income recognized during the three months ended June 30, 2015 on a promissory note received as part of the consideration for the sale of our entire 50% ownership interest in PDCM, of which $0.8 million was paid-in-kind.

Interest income increased to $2.2 million for the six months ended June 30, 2015 compared to $0.3 million for the six months ended June 30, 2014, mainly attributable to $2.2 million of non-cash interest income recognized during the six months ended June 30, 2015 on the above-mentioned promissory note, of which $1.6 million was paid-in-kind.

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Interest Expense

Interest expense decreased $0.6 million to ~~$25.9~~$11.6 million for the ~~six~~three months ended June 30, ~~2014~~2015 compared to ~~$26.4~~$12.2 million for the ~~six~~three months ended June 30, ~~2013~~.2014. The ~~year-over-year~~ decrease is primarily comprised of a ~~$0.7~~$0.9 million decrease attributable to an increase in ~~the~~capitalized interest, ~~expense capitalized~~offset in part by a $0.2 million increase due to higher average borrowings on our revolving credit facility during the ~~six~~three months ended June 30, ~~2014~~.2015.

Interest expense decreased $1.1 million to $23.3 million for the six months ended June 30, 2015 compared to $24.4 million for the six months ended June 30, 2014. The decrease is primarily comprised of a $2.0 million decrease attributable to an increase in capitalized interest, offset in part by a $0.7 million increase due to higher average borrowings on our revolving credit facility during the six months ended June 30, 2015.

Provision for Income Taxes

See Note 6, Income Taxes, to the accompanying condensed consolidated financial statements included elsewhere in this report for a discussion of the changes in our effective tax rate for the three and six months ended June 30, ~~2014~~2015 compared to the three and six months ended June 30, ~~2013~~.2014. The effective tax rate of ~~42.2%~~39.1% and ~~42.0%~~39.4% benefit on loss from continuing operations for the three and six months ended June 30, ~~2014~~,2015, respectively, are based on forecasted pre-tax income for the year adjusted for permanent differences. The forecasted full year effective tax rate has been applied to the quarter-to-date and year-to-date pre-tax loss resulting in a tax benefit for the respective periods. Because the estimate of full-year income may change from quarter to quarter, the effective tax rate for any particular quarter may not have a meaningful relationship to pre-tax income or loss for the quarter or the actual annual effective tax rate that is determined at the end of the year.

Discontinued Operations

In ~~February 2013,~~October 2014, we ~~entered into a purchase and~~completed the sale ~~agreement pursuant to which we agreed to sell~~of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our ~~Piceance Basin, NECO~~share of PDCM's debt repayment and ~~certain~~ other ~~non-core Colorado oil~~working capital adjustments, of approximately $192 million, comprised of approximately $153 million in net cash proceeds and ~~gas properties, leasehold mineral interests and related assets. Additionally, certain~~a promissory note due in 2020 of approximately $39 million. The transaction included the buyer's assumption of our share of the firm transportation ~~obligations and~~commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions ~~were assumed by~~for the ~~buyer. In June 2013, this~~years 2014 through 2017. The 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~~gain of ~~$2.3~~$76.3 million. ~~Following the sale, we do not have significant continuing involvement~~The divestiture represents a strategic shift in ~~the operations~~our operations. Accordingly, our proportionate share of ~~or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the~~PDCM's Marcellus Shale results of operations ~~related to these assets~~ have been separately reported as discontinued operations in the condensed consolidated statement of operations for the three and six months ended June 30, ~~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.~~2014.

See Note ~~12,~~13, 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.~~ownership interest in PDCM.

The table below presents production data related to ~~the~~PDCM's Marcellus Shale assets that have been divested and that are classified as discontinued operations:


	June 30, 2013		June 30, 2014
Discontinued Operations	Three Months Ended	Six Months Ended	Three Months Ended	Six Months Ended
Production
Crude oil (MBbls)	7.2	14.1
Natural gas (MMcf)	3,059.3	6,643.4	2,362.7	4,460.5
Crude oil equivalent (MBoe)	517.1	1,121.3	393.8	743.5

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

Net loss for the three ~~months ended~~ ~~June 30, 2014~~ ~~was~~ ~~$28.2 million~~ ~~compared to net income of~~ ~~$19.9 million~~ ~~for the same prior year period, while net loss for the~~and six months ended June 30, ~~2014~~2015 was $46.9 million and $29.8 million compared to a net loss of $28.2 million and $30.3 million for the three and six months ended June 30, ~~2013~~ ~~was~~ ~~$30.3 million~~ ~~and~~ ~~$19.5 million, respectively.~~2014. Adjusted net ~~loss,~~income, a non-U.S. GAAP financial measure, was ~~$1.5~~$10.8 million for the three months ended June 30, ~~2014~~2015 compared to adjusted net ~~income~~loss of ~~$7.0~~$1.5 million for the same prior year period. Adjusted net income ~~for the~~ ~~six~~ ~~months ended~~ ~~June 30, 2014~~was ~~$8.1~~$17.9 million ~~compared to adjusted net loss of~~ ~~$13.4 million~~ for the six months ended June 30, ~~2013~~.2015 compared to $8.1 million for the same prior year period. The quarter-over-quarter changes in net ~~income (loss)~~loss are discussed above, with the most significant changes related to the ~~increase~~decrease in crude oil, natural gas and NGLs sales and general and administrative expense, ~~DD&A expense~~ and the ~~loss from commodity price risk management activities~~increases in ~~the second quarter.~~DD&A expense. The year-over-year changes in net loss are discussed above, with the most significant changes related to the ~~increase~~decrease in crude oil, natural gas and NGLs sales and general and administrative expense, ~~DD&A expense,~~ and the ~~decrease~~increases in ~~impairment of crude oil and natural gas properties and loss from~~ commodity price risk management ~~activities.~~activity income and DD&A expense. 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.

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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 and asset ~~sales and entrance into joint ventures, such as PDCM.~~sales. For the six months ended June 30, ~~2014~~,2015, our primary sources of liquidity were the proceeds received from the March 2015 public offering of our common stock of approximately $203 million and net cash flows from operating activities of ~~$131.6 million~~$146.5 million. We used a portion of the proceeds of the offering to repay all amounts then outstanding on our revolving credit facility and used the remaining ~~cash from the August 2013 equity transaction noted below. In light~~amounts to fund a portion of our ~~current focus on the Wattenberg Field and the Utica Shale, in~~ ~~July 2014, we signed a definitive~~

~~agreement pursuant to which we agreed to sell our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration of approximately~~ ~~$250 million, subject to certain purchase price adjustments. See Note 15,~~ ~~Subsequent Events~~, to our condensed consolidated financial statements included elsewhere in this report for additional information. There can be no assurance we will be successful in closing the transaction. In addition, we may have greater than expected purchase price reductions.capital program.

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 for such related time period (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~~us from entering into hedges that would exceed 85% of our expected future production from proved developed producing ~~properties.~~properties during that time period. In addition, we may choose not to hedge the maximum amounts permitted under our covenants. 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. Given current commodity prices and our hedge position, we expect that positive net settlements on our derivative positions will continue to be a significant positive component of our 2015 cash flows from operations.

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 June 30, ~~2014~~,2015, we had a working capital deficit of ~~$167.8~~$56.4 million compared to a surplus of ~~$112.4~~$30.3 million at December 31, ~~2013~~.2014. The decrease in working capital to a deficit as of June 30, ~~2014~~2015 is ~~a direct~~primarily the result of classifying as a current liability the ~~reclassification~~carrying value of ~~our 3.25% convertible senior notes due 2016 (the "Convertible Notes") to current liabilities and a decrease in cash and cash equivalents.~~the Convertible Notes, net of discount, as the stated maturity of the Convertible Notes is May 2016.

We ended June ~~2014~~2015 with cash and cash equivalents of ~~$40.4~~$1.4 million and availability under our revolving credit facility ~~and our proportionate share~~ of ~~PDCM's credit facility of~~ ~~$443.8~~$385.3 million,, for a total liquidity position of ~~$484.2~~$386.7 million,, compared to ~~$647.0~~$398.4 million at December 31, ~~2013~~.2014. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the agreement. The decrease in liquidity of ~~$162.8~~$11.7 million,, or ~~25.2%~~2.9%, was primarily attributable to capital expenditures of ~~$293.6~~$358.1 million during the six months ended June 30, ~~2014, offset in part~~2015, which was financed by approximately $203 million received from the public offering of our common stock and cash flows provided by operating activities of ~~$131.6~~$146.5 million. Our revised forecast estimates our adjusted cash flows from operations will range from $400 million. to $420 million in 2015, based on estimated NYMEX crude oil and natural gas prices, before the effects of differentials or hedges, of $48.98 per barrel of crude oil, $2.87 per Mcf of natural gas and $9.61 per barrel of NGLs. Due to the derivative hedges in place as of June 30, 2015, a $10 per barrel change in the price of crude oil would change our estimated adjusted cash flows from operations for the remainder of 2015 by approximately $10 million to $15 million. Based on our current commodity mix and hedge position, we estimate that a decline in the price of natural gas will not have a material impact on our adjusted cash flows from operations in 2015. With our current derivative position, liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund our planned operations in 2014. Additionally, if we are successful in closing on the sale of our entire 50% ownership interest in PDCM, we expect to use the proceeds from the divestiture, along with internally generated cash flow and cash on hand, to fully fund our 2014 capital program ~~and thereby further defer drawing on our revolving credit facility.~~in 2015.

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 November 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.

~~In January 2012,~~March 2015, 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~~approximately four million shares of our common stock in ~~August 2013~~March 2015 in an underwritten public offering at a price to us of ~~$53.37~~$50.73 per share.

In recent periods, including the six months ended June 30, 2015, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of securities. We cannot, however, assure this will continue to be the case in the future. In light of recent weakened commodity prices, we continue to monitor market conditions and their potential impact on each of our revolving credit facility lenders, many of which are counterparties in our derivative transactions. Our 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. In May 2015, we completed the semi-annual redetermination of our revolving credit facility, which resulted in the reaffirmation of our borrowing base at $700 million. However, we have elected to maintain the aggregate commitment at $450 million. We had $53.0 million outstanding balance on our revolving credit facility as of June 30, 2015. While we have added and expect to continue to add producing reserves through our drilling operations, the effect of any such reserve additions on our borrowing base could be offset by other factors including, among other things, a prolonged period of depressed commodity prices or regulatory pressure on lenders to reduce their exposure to exploration and production companies.

Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.25 times the trailing 12 months 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

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liabilities calculation. At June 30, ~~2014~~,2015, we were in compliance with all debt covenants with a ~~2.0~~1.8 times debt to EBITDAX ratio and a ~~2.0~~1.6 to 1.0 current ratio. We expect to remain in compliance throughout the next year.

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 June 30, ~~2014~~,2015, we were in compliance with all covenants and expect to remain in compliance throughout the next year.

~~The Convertible Notes were convertible at the option of holders as of~~ ~~June 30, 2014~~. The conversion right on our Convertible Notes was triggered on June ~~20, 2014,~~30, 2015, when the closing sale price of our common stock on the NASDAQ Global Select Market exceeded ~~$55.12~~ (~~130%~~$55.12 (130% of the applicable conversion price) for the 20th trading day in the 30 consecutive trading days ending on June 30, ~~2014. As a result, the carrying value of the Convertible Notes, net of discount, was classified as a current liability as of~~ ~~June 30, 2014~~ ~~in our condensed consolidated balance sheet.~~2015. We have

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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. ~~Through August 8, 2014,~~As of the date of this filing, no holders of the Convertible Notes have elected to convert their notes.

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 ~~increase~~dincreased by ~~$89.6~~$14.9 million for the six months ended June 30, ~~2014~~2015, compared to the six months ended June 30, ~~2013~~.2014. The increase in cash provided by operating activities was primarily due to the increase in net settlements from our derivative positions of $113.2 million and a decrease in general and administrative expense of $24.6 million. The increase was partially offset by the decrease in crude oil, natural gas and NGLs sales of ~~$112.8~~$80.0 million and changes in assets and liabilities of ~~$63.6~~$31.2 million related to the timing of cash payments and receipts. ~~The increase was offset in part by the decrease in net settlements from our derivative positions of~~ ~~$31.1 million~~ ~~and increases in general and administrative expense of $33.4 million and production costs of~~ ~~$15.9 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 ~~$26.0~~$46.1 million during the six months ended June 30, ~~2014~~2015, compared to the six months ended June 30, ~~2013~~.2014. 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 ~~$23.9~~$43.8 million during the six months ended June 30, ~~2014~~2015 compared to the six months ended June 30, ~~2013~~.2014. The increase was primarily the result of the increase in net settlements from our derivative positions of $113.2 million and a decrease in general and administrative expense of $24.6 million. The increase was partially offset by the decrease in crude oil, natural gas and NGLs sales of ~~$112.8~~$80.0 million~~, offset in part by the~~ and an $8.9 million decrease in ~~net settlements on derivatives of~~ ~~$31.1 million~~ ~~and an increase in general and administrative expense of $33.4 million and production costs of~~ ~~$15.9 million~~.contribution margins from discontinued operations. 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 for a prolonged period 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 ~~leasehold acquisitions,~~the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. During the six months ended June 30, ~~2014~~,2015, our drilling program consisted of five drilling rigs operating in the ~~liquid-rich~~ horizontal Niobrara and Codell plays in our Wattenberg ~~Field and~~ ~~one~~ ~~rig in the Utica Shale play.~~Field. Net cash used in investing activities of ~~$292.2~~$357.9 million during the six months ended June 30, ~~2014~~2015 was primarily related to cash utilized for our drilling ~~operations of~~ ~~$293.6 million, offset in part by~~ ~~$1.4 million~~ ~~received from the sale of properties and equipment.~~operations.

Financing Activities. Net cash from financing activities for the six months ended June 30, ~~2014~~2015 increased by approximately ~~$50.4~~$189.0 million compared to the six months ended June 30, ~~2013~~.2014. Net cash from financing activities of ~~$7.7~~$196.7 million for the six months ended June 30, ~~2014~~2015 was primarily ~~represents~~related to the $202.9 million received from the issuance of our ~~proportionate share~~common stock in March 2015, partially offset by net payments of ~~PDCM's draw on its~~approximately $3.0 million to pay down amounts borrowed under our revolving 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,~~spud, turned-in-line and producing during the period. In-process wells represent wells that have been ~~spudded,~~spud, drilled or are waiting to be completed and/or for gas pipeline connection during the period.

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	Net Drilling Activity												Net Drilling Activity
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2014				2013		2014				2013		2015			2014			2015			2014
Operating Region/Area	Productive	In-Process	Dry		Productive	In-Process	Productive	In-Process	Dry		Productive	In-Process	Productive	In-Process	Dry (1)	Productive	In-Process	Dry (1)	Productive	In-Process	Dry (1)	Productive	In-Process	Dry (1)
Development Wells
Wattenberg Field	24.5	30.7	1.0	(1)	10.2	15.6	36.2	30.7	1.7	(1)	18.0	15.6	37.0	50.8	1.0	24.5	30.7	1.0	52.7	50.8	1.0	36.2	30.7	1.7
Utica Shale	—	3.5	1.0	(1)	—	—	2.0	3.5	1.0	(1)	—	—	3.0	—	—	—	3.5	1.0	3.0	—	—	2.0	3.5	1.0
Marcellus Shale (2)	0.5	—	—		—	3.5	2.0	—	—		—	3.5	—	—	—	0.5	—	—	—	—	—	2.0	—	—
Total net development wells	25.0	34.2	2.0		10.2	19.1	40.2	34.2	2.7		18.0	19.1
Exploratory Wells
Utica Shale	—	—	—		—	4.2	—	—	—		1.5	4.2
Total net exploratory wells	—	—	—		—	4.2	—	—	—		1.5	4.2
Total drilling activity	25.0	34.2	2.0		10.2	23.3	40.2	34.2	2.7		19.5	23.3	40.0	50.8	1.0	25.0	34.2	2.0	55.7	50.8	1.0	40.2	34.2	2.7

______________

(1) Represents ~~two~~ mechanical failures ~~in the Wattenberg Field and one mechanical failure in the Utica Shale~~ that resulted in the plugging and abandonment of the respective wells.

(2) Represents PDCM's drilling activity. On ~~July 29,~~October 14, 2014,, we ~~signed a definitive agreement to sell~~closed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party. See Note ~~15, Subsequent Events,~~13, Assets Held for Sale, Divestitures and Discontinued Operations to our condensed consolidated financial statements included elsewhere in this report for additional information. ~~There can be no assurance we will be successful in closing the transaction. In addition, we may have greater than expected purchase price reductions.~~

Off-Balance Sheet Arrangements

At June 30, ~~2014~~2015, we had no 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 9,10, 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 required 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~~2014 Form 10-K filed with the SEC on February ~~20, 2014.~~19, 2015.

Reconciliation of Non-U.S. GAAP Financial Measures

Adjusted cash flows from ~~operations.~~ 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.

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PDC ENERGY, INC.

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

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~~PDC ENERGY, INC.~~

(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~~operating 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 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.

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PDC ENERGY, INC.

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

Three Months Ended June 30, Six Months Ended June 30,
2014 2013 2014 2013
(in millions)
Adjusted cash flows from operations:
Adjusted cash flows from operations $ 55.0
$ 46.4
$ 124.7
$ 98.7
Changes in assets and liabilities (3.9 ) (48.6 ) 6.9
(56.7 )
Net cash from operating activities $ 51.1
$ (2.2 ) 131.6
$ 42.0

Adjusted net income (loss):
Adjusted net income (loss) $ (1.5 ) $ 7.0
$ 8.1
$ (13.4 )
Gain (loss) on commodity derivative instruments (53.4 ) 24.8
(80.6 ) 2.6
Net settlements on commodity derivative instruments 10.4
(4.0 ) 18.7
(12.5 )
Tax effect of above adjustments 16.3
(7.9 ) 23.5
3.8
Net income (loss) $ (28.2 ) $ 19.9
$ (30.3 ) $ (19.5 )

Adjusted EBITDA to net income (loss):
Adjusted EBITDA $ 62.7
$ 54.1
$ 139.2
$ 115.3
Gain (loss) on commodity derivative instruments (53.4 ) 24.8
(80.6 ) 2.6
Net settlements on commodity derivative instruments 10.4
(4.0 ) 18.7
(12.5 )
Interest expense, net (12.9 ) (13.1 ) (25.5 ) (26.4 )
Income tax provision 20.5
(11.4 ) 21.9
10.0
Impairment of crude oil and natural gas properties (0.9 ) (1.5 ) (1.9 ) (48.0 )
Depreciation, depletion and amortization (53.7 ) (27.8 ) (100.4 ) (58.0 )
Accretion of asset retirement obligations (0.9 ) (1.2 ) (1.7 ) (2.5 )
Net income (loss) $ (28.2 ) $ 19.9
$ (30.3 ) $ (19.5 )

Adjusted EBITDA to net cash from operating activities:
Adjusted EBITDA $ 62.7
$ 54.1
$ 139.2
$ 115.3
Interest expense, net (12.9 ) (13.1 ) (25.5 ) (26.4 )
Stock-based compensation 5.0
4.4
8.9
7.0
Amortization of debt discount and issuance costs 1.7
1.7
3.4
3.4
(Gain) loss on sale of properties and equipment (0.4 ) 1.1
0.4
1.0
Other (1.1 ) (1.8 ) (1.7 ) (1.6 )
Changes in assets and liabilities (3.9 ) (48.6 ) 6.9
(56.7 )
Net cash from operating activities $ 51.1
$ (2.2 ) $ 131.6
$ 42.0

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~~Ballot Initiative Update~~



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
Adjusted cash flows from operations:
Adjusted cash flows from operations	$	96.9		$	55.0		$	170.8		$	124.7
Changes in assets and liabilities	(32.3		)	(3.9		)	(24.3		)	6.9
Net cash from operating activities	$	64.6		$	51.1		$	146.5		$	131.6

Adjusted net (loss) income:
Adjusted net (loss) income	$	10.8		$	(1.5	)	$	17.9		$	8.1
Gain (loss) on commodity derivative instruments	(49.0		)	(53.4		)	17.6			(80.6		)
Net settlements on commodity derivative instruments	(44.1		)	10.4			(94.5		)	18.7
Tax effect of above adjustments	35.4			16.3			29.2			23.5
Net loss	$	(46.9	)	$	(28.2	)	$	(29.8	)	$	(30.3	)

Adjusted EBITDA to net income (loss):
Adjusted EBITDA	$	101.0		$	62.7		$	183.0		$	139.2
Gain (loss) on commodity derivative instruments	(49.0		)	(53.4		)	17.6			(80.6		)
Net settlements on commodity derivative instruments	(44.1		)	10.4			(94.5		)	18.7
Interest expense, net	(10.4		)	(12.9		)	(21.0		)	(25.5		)
Income tax provision	30.1			20.5			19.4			21.9
Impairment of crude oil and natural gas properties	(2.8		)	(0.9		)	(5.3		)	(1.9		)
Depreciation, depletion and amortization	(70.1		)	(53.7		)	(125.9		)	(100.4		)
Accretion of asset retirement obligations	(1.6		)	(0.9		)	(3.1		)	(1.7		)
Net loss	$	(46.9	)	$	(28.2	)	$	(29.8	)	$	(30.3	)

Adjusted EBITDA to net cash from operating activities:
Adjusted EBITDA	$	101.0		$	62.7		$	183.0		$	139.2
Interest expense, net	(10.4		)	(12.9		)	(21.0		)	(25.5		)
Stock-based compensation	5.1			5.0			9.5			8.9
Amortization of debt discount and issuance costs	1.8			1.7			3.5			3.4
(Gain) loss on sale of properties and equipment	(0.2		)	(0.4		)	(0.2		)	0.4
Other	(0.4		)	(1.1		)	(4.0		)	(1.7		)
Changes in assets and liabilities	(32.3		)	(3.9		)	(24.3		)	6.9
Net cash from operating activities	$	64.6		$	51.1		$	146.5		$	131.6

~~As discussed in the “Risk Factors” section of the 2013 Form 10-K, certain interest groups in Colorado opposed to oil~~Amounts above include results from continuing and natural gas development generally, or hydraulic fracturing in particular, have advanced various options for ballot initiatives aimed at significantly limiting or preventing oil and natural gas development. The initiative proponents ultimately submitted signatures for only two such initiatives, which would amend the state constitution to establish, respectively, an “environmental bill of rights,” and a 2000-foot statewide drilling setback from occupied structures. As part of a compromise negotiated by Governor John Hickenlooper, both initiatives were subsequently withdrawn and they will not appear on the November 2014 ballot.

Pursuant to this compromise, Governor Hickenlooper will create a task force charged with crafting recommendations to help minimize land use conflicts relating to the location of oil and gas facilities. The task force will be composed of 18 individuals representing a variety of interests involved in and affected by oil and gas development. The task force will have the power to make recommendations to the state legislature. We cannot predict the outcome of the processes, and proposals to be formulated, by the task force.

discontinued operations.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES 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 our Convertible Notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.

As of June 30, ~~2014~~2015, 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 June 30, ~~2014~~2015 was ~~$51.1~~$1.9 million with an average interest rate of ~~0.4%~~0.1%. Based on a sensitivity analysis of our interest bearing deposits as of June 30, ~~2014~~2015, it was estimated that if market interest rates would have increased by 1%, the impact on interest income for the six months ended June 30, ~~2014~~2015 would ~~result in a change of $0.3 million.~~be immaterial.

As of June 30, ~~2014~~2015, excluding the ~~$11.7~~$11.7 million irrevocable standby letter of credit, we had noa $53.0 million outstanding ~~draws~~balance on our revolving credit ~~facility and, representing our proportionate share,~~ ~~$47.0 million~~ ~~on PDCM's revolving credit~~ facility. ~~We estimate~~It was estimated that if market interest rates would have increased or decreased by 1%, ~~the impact on~~our interest expense for the six months ended June 30, ~~2014~~2015 would have ~~been immaterial.~~changed by approximately $0.3 million.

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 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 June 30, ~~2014~~2015:


	Collars					Fixed-Price Swaps			Basis Protection Swaps								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 June 30, 2014 (2) (in millions)			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 June 30, 2015 (2) (in millions)
		Floors		Ceilings									Floors					Ceilings
Natural Gas
NYMEX
2014	—	$	—	$	—	9,095.0	$	4.17	5,020.0	$	(0.19	)		$	(2.6	)
2015	5,860.0	4.00		4.48		12,950.0	4.10		3,420.0	(0.25		)		(1.9		)	5,495.0		$	3.92	$	4.30	5,815.0	$	3.98	9,600.0	$	(0.29	)	$	10.9
2016	4,820.0	4.03		4.48		13,000.0	4.00		—	—				(3.1		)	7,820.0		3.88		4.24		21,930.0	3.93		20,400.0	(0.31		)	21.5
2017	1,630.0	4.25		5.00		625.0	4.22		—	—				0.1			7,170.0		3.65		4.20		22,340.0	3.68		4,800.0	(0.30		)	10.1
2018																	480.0		3.00		3.90		4,080.0	3.40		—	—			(0.2		)

CIG
2014	—	—		—		2,524.0	3.98		—	—				(1.1		)
2015	—	—		—		2,730.0	4.01		—	—				0.3			—		—		—		1,198.0	4.01		—	—			1.6

Total Natural Gas	12,310.0					40,924.0			8,440.0					(8.3		)	20,965.0						55,363.0			34,800.0				43.9

Crude Oil
NYMEX
2014	414.0	82.37		101.99		1,804.0	90.77		—	—				(23.2		)
2015	686.0	85.63		96.86		4,514.0	89.12		—	—				(35.4		)	468.0		86.79		96.63		2,379.0	89.42		—	—			81.2
2016	1,740.0	77.59		97.55		1,080.0	89.87		—	—				(5.5		)	1,740.0		77.59		97.55		2,400.0	90.37		—	—			97.6
2017																	960.0		54.06		73.77		180.0	61.15		—	—			(0.1		)

Total Crude Oil	2,840.0					7,398.0			—					(64.1		)	3,168.0						4,959.0			—				178.7
Total Natural Gas and Crude Oil														$	(72.4	)														$	222.6

____________


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

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~~PDC ENERGY, INC.~~


(2)	Approximately ~~40.8%~~25.9% of the fair value of our derivative assets and ~~10%~~6.2% 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.

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PDC ENERGY, INC.

The following table presents 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:


	Six Months Ended		Year Ended		Three Months Ended		Six Months Ended		Year Ended
	June 30, 2014		December 31, 2013		June 30, 2015		June 30, 2015		December 31, 2014
Average Index Closing Price:
Crude oil (per Bbl)
NYMEX	$	100.84	$	97.97	$	57.94	$	53.29	$	92.91
Natural gas (per MMBtu)
NYMEX					$	2.64	$	2.81	$	4.42
CIG	$	4.52	$	3.45	2.33		2.55		4.17
NYMEX	4.80		3.65
TETCO M-2 (1)					1.38		1.73		3.35

Average Sales Price Realized:
Excluding net settlements on derivatives
Crude oil (per Bbl)	$	88.94	$	89.92	$	48.31	$	44.47	$	80.67
Natural gas (per Mcf)	4.29		3.29		2.03		2.21		3.87
NGLs (per Bbl)	31.24		27.97		10.01		11.23		27.39

_____________

(1) TETCO M-2 is an index price upon which a majority of our natural gas produced in the Utica Shale is sold.

Based on a sensitivity analysis as of June 30, ~~2014~~2015, 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 ~~$110.3 million;~~$67.4 million, whereas a 10% decrease in prices would have resulted in an increase in fair value of ~~$107.1~~$68.0 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. We monitor the creditworthiness of significant 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 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~~As commodity prices continue to remain depressed, customers under our ~~credit committee,~~Gas Marketing segment may begin to experience financial distress, which ~~utilizes a number of qualitative and quantitative tools~~may lead to ~~assess credit risk and takes mitigative actions if deemed necessary.~~certain contractual defaults. To date, we have had no material counterparty default losses relating to customers 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. 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. In addition, disruptionDisruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our derivative financial instruments. See Note 4, Derivative Financial Instruments, to our condensed consolidated financial statements included 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 June 30, ~~2014~~2015, 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 June 30, ~~2014~~2015, 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 June 30, ~~2014~~2015.

Changes in Internal Control over Financial Reporting

During the three months ended June 30, ~~2014~~2015, 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 9,10, Commitments and Contingencies – Litigation, to our condensed consolidated financial statements included elsewhere in this report.

ITEM 1A. RISK FACTORS

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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~~2014 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.

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

April 1 - 30, 2014 12,611
$ 62.14
May 1 - 31, 2014 15,662
61.76
June 1 - 30, 2014 8,576
63.57
Total second quarter purchases 36,849
62.31



Period	Total Number of Shares Purchased (1)	Average Price Paid per Share

April 1 - 30, 2015	26,364	$	54.03
May 1 - 31, 2015	10,056	56.69
June 1 - 30, 2015	—	—
Total second quarter purchases	36,420	54.76

__________


(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.~~

At our annual shareholders' meeting held on June 4, 2015, our shareholders approved a change in the Company’s state of incorporation from the State of Nevada to the State of Delaware, pursuant to a plan of conversion. The reincorporation became effective on June 5, 2015.

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ITEM 6. EXHIBITS

Incorporated by Reference
Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith

3.1 Fourth Amended and Restated Articles of Incorporation of PDC Energy, Inc. (the "Company")
8-K 000-07246 3.1 6/10/2014

10.1 Consulting Agreement with James M. Trimble, Chief Executive Officer and President, dated as of June, 18, 2014. X

10.2 Purchase and Sale Agreement by and among the Company, LR-Mountaineer Holdings, L.P., PDC Mountaineer, LLC and PDC Mountaineer Holdings, LLC, dated July 29, 2014. 8-K 000-07246 2.1 8/1/2014

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

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

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

101.INS XBRL Instance Document X

101.SCH XBRL Taxonomy Extension Schema Document X

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document X

101.DEF XBRL Taxonomy Extension Definition Linkbase Document X

101.LAB XBRL Taxonomy Extension Label Linkbase Document X

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document X

* Furnished herewith.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

2.1

Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the "Company")

8-K12B

000-07246

2.1

6/8/2015

3.1

Certificate of Incorporation of the Company.

8-K12B

000-07246

3.1

6/8/2015

3.2

By-laws of the Company.

8-K12B

000-07246

3.2

6/8/2015

4.1

Form of Common Stock Certificate of the Company.

8-K12B

000-07246

4.1

6/8/2015

10.1

Form of Indemnification Agreement

8-K

000-07246

10.1

6/8/2015

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.

99.1

Certificate of Conversion, effective June 5, 2015.

8-K12B

000-07246

99.1

6/8/2015

99.2

Articles of Conversion, effective June 5, 2015.

8-K12B

000-07246

99.2

6/8/2015

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.

4036

Table of contents

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: August ~~8, 2014~~10, 2015	/s/ ~~James M. Trimble~~Barton R. Brookman
	~~James M. Trimble~~Barton R. Brookman
	President and Chief Executive Officer
	(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)

4137



Condensed consolidated statements of operations - discontinued operations	Three Months Ended June 30, 2013			Six Months Ended June 30, 2013

Revenues
Crude oil, natural gas and NGLs sales	$	10,182		$	20,456
Sales from natural gas marketing	586			1,036
Well operations, pipeline income and other	409			859
Total revenues	11,177			22,351

Costs, expenses and other
Production costs	2,564			7,957
Cost of natural gas marketing	540			994
Depreciation, depletion and amortization	—			2,258
Other	1,959			2,454
Loss on sale of properties and equipment	1,076			1,076
Total costs, expenses and other	6,139			14,739

Income from discontinued operations	5,038			7,612
Provision for income taxes	(1,622		)	(2,659		)
Income from discontinued operations, net of tax	$	3,416		$	4,953