PDC ENERGY, INC. - FORM 10-Q - November 6, 2017

Attached files

file	filename
EX-32.1 - 906 CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - PDC ENERGY, INC.	a2017_10q3xexx321.htm
EX-31.2 - 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - PDC ENERGY, INC.	a2017_10q3xexx312.htm
EX-31.1 - 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - PDC ENERGY, INC.	a2017_10q3xexx311.htm
EX-10.1 - SIXTH AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT - PDC ENERGY, INC.	a2017_10q3xexx101.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2017

£ 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 001-37419

PDC ENERGY, INC.

(Exact name of registrant as specified in its charter)



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 x No o

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 x No o

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," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o
	Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 65,872,790 shares of the Company's Common Stock ($0.01 par value) were outstanding as of October 20, 2017.

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PDC ENERGY, INC.

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	PART I – FINANCIAL INFORMATION	Page

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets (unaudited)	1
	Condensed Consolidated Statements of Operations (unaudited)	2
	Condensed Consolidated Statements of Cash Flows (unaudited)	3
	Condensed Consolidated Statement of Equity (unaudited)	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	55

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	57
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57
Item 3.	Defaults Upon Senior Securities	57
Item 4.	Mine Safety Disclosures	57
Item 5.	Other Information	57
Item 6.	Exhibits	58

	SIGNATURES	59

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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"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"), and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." 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. Forward-looking statements may include, among other things, statements regarding the closing of pending transactions and the effects of such transactions, including the fact that the pending acquisition of certain properties owned by Bayswater Exploration & Production, LLC and certain related parties and the pending acreage exchanges are subject to continuing diligence between the parties and may not occur within the expected timeframe or we may not successfully close such transactions; the potential sale of our Utica Shale properties and the timing of such sale; the level of non-operated well activity following the pending acreage exchanges; future reserves, production, costs, cash flows, and earnings; drilling locations and growth opportunities; capital investments and projects, including expected lateral lengths of wells, drill times and number of rigs employed; potential future impairments; the finalization of a consent decree resolving pending litigation; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments and the estimated in-service date of the facilities being constructed by our midstream providers.

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. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:


•	changes in worldwide production volumes and demand, including economic conditions that might impact demand and prices for the products we produce;


•	volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;


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


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


•	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;


•	availability of sufficient pipeline, gathering, and other transportation facilities and related infrastructure to process and transport our production 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;


•	losses from our gas marketing business exceeding our expectations;


•	difficulties in integrating our operations as a result of any significant acquisitions, including our pending acquisitions and acreage exchanges in the Wattenberg Field;


•	increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion, and facilities costs;


•	availability of supplies, materials, contractors, and services that may delay the drilling or completion of our wells;


•	potential losses of acreage due to lease expirations or otherwise;


•	increases or adverse changes in construction costs and procurement costs associated with future build out of midstream-related assets;

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•	future cash flows, liquidity, and financial condition;


•	competition within the oil and gas industry;


•	availability and cost of capital;


•	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, including recent environmental litigation;


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


•	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, 2016 (the "2016 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 28, 2017, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations, and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect 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.

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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)



	September 30, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	136,429		$	244,100
Accounts receivable, net	167,276			143,392
Fair value of derivatives	22,916			8,791
Prepaid expenses and other current assets	8,081			3,542
Total current assets	334,702			399,825
Properties and equipment, net	3,882,700			4,002,994
Assets held-for-sale, net	41,484			5,272
Fair value of derivatives	4,605			2,386
Goodwill	—			62,041
Other assets	43,796			13,324
Total Assets	$	4,307,287		$	4,485,842

Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	164,080		$	66,322
Production tax liability	36,954			24,767
Fair value of derivatives	25,987			53,595
Funds held for distribution	94,387			71,339
Accrued interest payable	18,929			15,930
Other accrued expenses	33,451			38,625
Total current liabilities	373,788			270,578
Long-term debt	1,051,571			1,043,954
Deferred income taxes	326,472			400,867
Asset retirement obligations	78,188			82,612
Fair value of derivatives	7,261			27,595
Other liabilities	43,405			37,482
Total liabilities	1,880,685			1,863,088

Commitments and contingent liabilities

Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,928,295 and 65,704,568 issued as of September 30, 2017 and December 31, 2016, respectively	659			657
Additional paid-in capital	2,500,532			2,489,557
Retained earnings (deficit)	(70,933		)	134,208
Treasury shares - at cost, 62,772 and 28,763 as of September 30, 2017 and December 31, 2016, respectively	(3,656		)	(1,668		)
Total stockholders' equity	2,426,602			2,622,754
Total Liabilities and Stockholders' Equity	$	4,307,287		$	4,485,842

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues
Crude oil, natural gas, and NGLs sales	$	232,733		$	141,805		$	636,027		$	328,013
Commodity price risk management gain (loss), net of settlements	(52,178		)	19,397			86,458			(62,348		)
Other income	2,680			2,688			9,615			9,153
Total revenues	183,235			163,890			732,100			274,818
Costs, expenses and other
Lease operating expenses	25,353			14,001			65,170			43,006
Production taxes	15,516			9,568			42,957			19,682
Transportation, gathering and processing expenses	9,794			5,048			22,184			13,554
General and administrative expense	29,299			32,510			85,145			78,868
Exploration, geologic, and geophysical expense	41,908			241			43,895			688
Depreciation, depletion and amortization	125,238			112,927			360,567			317,329
Impairment of properties and equipment	252,740			933			282,499			6,104
Impairment of goodwill	75,121			—			75,121			—
Accretion of asset retirement obligations	1,472			1,777			4,906			5,400
Gain on sale of properties and equipment	(62		)	(219		)	(754		)	(43		)
Provision for uncollectible notes receivable	—			(700		)	(40,203		)	44,038
Other expenses	2,947			3,092			10,365			7,795
Total costs, expenses and other	579,326			179,178			951,852			536,421
Loss from operations	(396,091		)	(15,288		)	(219,752		)	(261,603		)
Interest expense	(19,275		)	(20,193		)	(58,359		)	(42,759		)
Interest income	479			140			1,487			1,875
Loss before income taxes	(414,887		)	(35,341		)	(276,624		)	(302,487		)
Income tax benefit	122,350			12,032			71,483			112,198
Net loss	$	(292,537	)	$	(23,309	)	$	(205,141	)	$	(190,289	)

Earnings per share:
Basic	$	(4.44	)	$	(0.48	)	$	(3.12	)	$	(4.16	)
Diluted	$	(4.44	)	$	(0.48	)	$	(3.12	)	$	(4.16	)

Weighted-average common shares outstanding:
Basic	65,865			48,839			65,825			45,741
Diluted	65,865			48,839			65,825			45,741

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(unaudited; in thousands)



	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities:
Net loss	$	(205,141	)	$	(190,289	)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	(64,307		)	230,177
Depreciation, depletion and amortization	360,567			317,329
Impairment of properties and equipment	282,499			6,104
Impairment of goodwill	75,121			—
Exploratory dry hole costs	41,187			—
Provision for uncollectible notes receivable	(40,203		)	44,038
Accretion of asset retirement obligations	4,906			5,400
Non-cash stock-based compensation	14,587			15,205
Gain on sale of properties and equipment	(754		)	(43		)
Amortization of debt discount and issuance costs	9,628			12,951
Deferred income taxes	(71,529		)	(114,136		)
Other	986			(526		)
Changes in assets and liabilities	3,855			34,621
Net cash from operating activities	411,402			360,831
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(528,850		)	(352,213		)
Capital expenditures for other properties and equipment	(3,740		)	(1,509		)
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition	(14,482		)	(100,000		)
Proceeds from sale of properties and equipment	3,322			4,945
Sale of promissory note	40,203			—
Restricted cash	(9,250		)	—
Sale of short-term investments	49,890			—
Purchase of short-term investments	(49,890		)	—
Net cash from investing activities	(512,797		)	(448,777		)
Cash flows from financing activities:
Proceeds from issuance of equity, net of issuance cost	—			855,072
Proceeds from senior notes	—			392,250
Proceeds from convertible senior notes	—			193,979
Proceeds from revolving credit facility	—			85,000
Repayment of revolving credit facility	—			(122,000		)
Redemption of convertible notes	—			(115,000		)
Purchase of treasury shares	(5,325		)	(5,106		)
Other	(951		)	593
Net cash from financing activities	(6,276		)	1,284,788
Net change in cash and cash equivalents	(107,671		)	1,196,842
Cash and cash equivalents, beginning of period	244,100			850
Cash and cash equivalents, end of period	$	136,429		$	1,197,692

Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest	$	45,719		$	19,499
Income taxes	(2,623		)	167
Non-cash investing and financing activities:
Change in accounts payable related to purchases of properties and equipment	$	89,974		$	(31,497	)
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals	3,357			1,137
Purchase of properties and equipment under capital leases	3,363			1,231

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statement of Equity

(unaudited; in thousands, except share data)



	Common Stock							Treasury Stock
	Shares		Amount		Additional Paid-in Capital			Shares		Amount			Retained Earnings (Deficit)			Total Stockholders' Equity

Balance, December 31, 2016	65,704,568		$	657	$	2,489,557		(28,763	)	$	(1,668	)	$	134,208		$	2,622,754
Net loss	—		—		—			—		—			(205,141		)	(205,141		)
Purchase of treasury shares	—		—		—			(80,572	)	(5,325		)	—			(5,325		)
Issuance of treasury shares	(49,446	)	—		(3,513		)	49,446		3,513			—			—
Non-employee directors' deferred compensation plan	—		—		—			(2,883	)	(176		)	—			(176		)
Issuance of stock awards, net of forfeitures	273,173		2		(2		)	—		—			—			—
Stock-based compensation expense	—		—		14,587			—		—			—			14,587
Other	—		—		(97		)	—		—			—			(97		)
Balance, September 30, 2017	65,928,295		$	659	$	2,500,532		(62,772	)	$	(3,656	)	$	(70,933	)	$	2,426,602

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, and explores for crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado and, beginning in December 2016, the Delaware Basin in Reeves and Culberson Counties, Texas. We also have operations in the Utica Shale in Southeastern Ohio. During the third quarter of 2017, as part of plans to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are currently focused in the Wolfcamp zones. As of September 30, 2017, we owned an interest in approximately 2,900 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning in 2017, our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our two affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.

In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2016 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. 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 2016 Form 10-K. Our results of operations and cash flows for the three and nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain immaterial reclassifications have been made to our prior period balance sheet and statement of operations to conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings, earnings per share or stockholders' equity.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recently Adopted Accounting Standard

In January 2017, the FASB issued an accounting update to simplify the measurement of goodwill. The update eliminates the two-step process that required identification of potential impairment and a separate measure of actual impairment. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the second quarter of 2017. Our annual evaluation of goodwill for impairment was expected to occur in the fourth quarter of 2017; however, we experienced an impairment triggering event as of September 30, 2017 and implemented the new guidance as part of the impairment evaluation. See the footnote titled Goodwill for a detailed description of the results of our impairment testing.

Recently Issued Accounting Standards

In May 2014, the FASB and the International Accounting Standards Board 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 standard has been updated and now includes technical corrections. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

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: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when or as each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; we are adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard will have on our consolidated financial statements, we are performing a comprehensive review of our significant revenue streams. The focus of this review includes, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of transaction price. We are also reviewing our current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, may be required by the adoption of the revenue standard. We have determined that we will adopt the standard under the modified retrospective method. We have not made a complete determination regarding the impact that the adoption will have on our consolidated financial statements as of the time of this filing.

In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In January 2017, the FASB issued an accounting update clarifying the definition of a business, with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 3 - BUSINESS COMBINATION

Delaware Basin Acquisition. On December 6, 2016, we closed on an acquisition which was accounted for as a business combination. The acquisition consisted of the purchase of stock of an entity and assets of other entities under common control. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 completed and producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion, after preliminary post-closing adjustments. The total consideration to sellers was comprised of approximately $946.0 million in cash, including the payment of $40.0 million of debt of the sellers at closing and other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed. The purchase accounting for the entity of which we acquired the stock reflected oil and gas assets that did not receive fair value step-up of the tax basis. As a result, a significant deferred income tax liability was calculated based on the acquired allocated fair value of the assets in excess of the tax basis of assets inside the entity. This calculation resulted in approximately $375.0 million of non-cash basis needing to be allocated to the acquired assets. No deferred tax liability was established for the calculated goodwill as the goodwill did not qualify as tax goodwill.

The final fair value allocation of the assets acquired and liabilities assumed in the acquisition are presented below and include customary post-closing adjustments. The most significant item to be completed during the final purchase price allocation in the third quarter of 2017 was the final allocation of value to the unproved oil and gas properties associated with the acquired acreage. Adjustments to the preliminary purchase price primarily stem from additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and liabilities assumed, including detailed lease terms, location of the acreage, and intent to develop the acreage as of the date of closing. There were a significant number of leases acquired with complex lease terms and evaluation of these terms and the timing of the lease expirations impacted the manner in which the final purchase price was allocated. Our final determination of the value of goodwill has been adjusted for all post-closing adjustments.

The details of the final purchase price and the allocation of the purchase price for the transaction, are presented below (in thousands):



	September 30, 2017
Acquisition costs:
Cash, net of cash acquired	$	905,962
Retirement of seller's debt	40,000
Total cash consideration	945,962
Common stock, 9.4 million shares	690,702
Other purchase price adjustments	426
Total acquisition costs	$	1,637,090

Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	6,401
Crude oil and natural gas properties - proved	216,000
Crude oil and natural gas properties - unproved	1,697,000
Infrastructure, pipeline, and other	33,153
Construction in progress	12,323
Goodwill	75,121
Total assets acquired	2,039,998
Liabilities assumed:
Current liabilities	(24,496		)
Asset retirement obligations	(3,705		)
Deferred tax liabilities, net	(374,707		)
Total liabilities assumed	(402,908		)
Total identifiable net assets acquired	$	1,637,090

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations, and a market-based weighted-average cost of capital rate. Within the unproven properties, the allocation of the value to the underlying leases also required significant judgment and was based on a combination of comparable market transactions, the term and conditions associated with the individual leases, our ability and intent to develop specific leases, and our initial assessment of the underlying relative value of the leases given our knowledge of the geology at the time of closing. These inputs require significant judgments and estimates by management at the time of the valuation and were the most sensitive and subject to change.

This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.

Goodwill. Goodwill was calculated as the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be derived in the future, such as production from future development of additional producing zones. The amount of the final goodwill that was recorded in the third quarter of 2017 related to the Delaware Basin acquisition was $75.1 million and was higher than the initial estimated amount recorded as of December 31, 2016, primarily related to finalization of the aggregate acreage position acquired and the related lease terms and a final settlement with the sellers in connection with a revised valuation of certain acquired leases and the retirement of estimated environmental remediation liabilities. Any value assigned to goodwill was not expected to be deductible for income tax purposes.

The following table presents the changes in goodwill from the preliminary allocation at December 31, 2016, and the final allocation determined during the quarter ended September 30, 2017:



	Amount
	(in thousands)

Preliminary purchase price allocation	$	62,041
Adjustments	13,080
Final purchase price allocation	$	75,121

See the footnote titled Goodwill for the details regarding the impairment of goodwill as of September 30, 2017.

NOTE 4 - PENDING ACQUISITION AND ACREAGE EXCHANGES

Pending Acquisition. In September 2017, we entered into an acquisition agreement to acquire certain assets from Bayswater Exploration & Production, LLC ("Bayswater") and certain related parties, pursuant to which, subject to the terms and conditions of the agreement, we have agreed to acquire approximately 8,300 net acres, 30 operated drilled uncompleted wells ("DUCs"), and an estimated 240 gross drilling locations, for approximately $210 million in cash, subject to certain pre- and post-closing adjustments. We plan to turn-in-line 18 of these DUCs at approximately year-end 2017, with the completion costs expected to be treated as an increase to the purchase price. Upon executing the purchase and sale agreement, we paid a $21 million deposit toward the purchase price into an escrow account, which is included in other assets on our September 30, 2017 condensed consolidated balance sheet. Assuming all conditions required for closing are met, the acquisition is expected to close in December 2017 and is expected to be funded by a combination of available cash and debt.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

primarily due to variances in working and net revenue interests. The acreage exchange is expected to close in the fourth quarter of 2017; however, there can be no assurance that conditions to closing will be satisfied.

In June 2017, we entered into an acreage exchange transaction that also involves the consolidation of certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we estimate that we will receive approximately 3,900 net acres in exchange for approximately 4,100 net acres with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. This acreage exchange is also expected to close in the fourth quarter 2017; however, there can be no assurance that conditions to closing will be satisfied.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 5 - EXPLORATION, GEOLOGIC, AND GEOPHYSICAL EXPENSE

The following table presents the major components of exploration, geologic, and geophysical expense:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)

Exploratory dry hole costs	$	41,187	$	—	$	41,187	$	—
Geological and geophysical costs, including seismic purchases	463		—		1,790		—
Operating, personnel and other	258		241		918		688
Total exploration, geologic, and geophysical expense	$	41,908	$	241	$	43,895	$	688

Exploratory dry hole costs. During the three and nine months ended September 30, 2017, two exploratory dry hole wells, associated lease costs, and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.2 million. The conclusion to expense these items was due to the conclusion that the acreage on which these wells were drilled was exploratory in nature and, following drilling, the lack of hydrocarbon production necessary for the wells to be deemed economically viable.

NOTE 6 - PROPERTIES AND EQUIPMENT AND ASSETS HELD-FOR-SALE

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



	September 30, 2017			December 31, 2016
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	3,759,501		$	3,499,718
Unproved	1,559,717			1,874,671
Total crude oil and natural gas properties	5,319,218			5,374,389
Infrastructure, pipeline, and other	104,568			62,093
Land and buildings	10,714			6,392
Construction in progress	177,341			122,591
Properties and equipment, at cost	5,611,841			5,565,465
Accumulated DD&A	(1,729,141		)	(1,562,471		)
Properties and equipment, net	$	3,882,700		$	4,002,994

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)

Impairment of unproved properties	$	252,623	$	338	$	282,188	$	2,391
Amortization of individually insignificant unproved properties	117		595		311		681
Impairment of crude oil and natural gas properties	252,740		933		282,499		3,072
Land and buildings	—		—		—		3,032
Total impairment of properties and equipment	$	252,740	$	933	$	282,499	$	6,104

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

current increased cost environment for drilling and completion services in the Delaware Basin, (iii) our decreased future commodity price outlook, and (iv) the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during the third quarter of 2017. The amount of the impairment of these unproved properties was based on the value assigned to individual lease acres in the final purchase price allocation of the business combination. This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. Due to the aforementioned events and circumstances in the third quarter of 2017, we evaluated our proved property for possible impairment and concluded that these assets were not impaired during the period.

Classification of Assets as Held-for-Sale. During the third quarter of 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017.

The following table presents balance sheet data related to assets held-for-sale, which include the Utica Shale properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities, that are expected to be assumed by the purchasers:



	September 30, 2017		December 31, 2016
	(in thousands)
Assets
Properties and equipment, net	$	41,983	$	5,272
Total assets	$	41,983	$	5,272

Liabilities
Asset retirement obligation	$	499	$	—
Total liabilities	$	499	$	—

Net assets	$	41,484	$	5,272

NOTE 7 - GOODWILL

The final goodwill that resulted from the purchase price allocation of the assets acquired in the Delaware Basin was determined to be $75.1 million. With the creation of goodwill from this transaction, we expected to perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin since the time of the acquisition, in conjunction with our lower future commodity price outlook, we determined a triggering event had occurred in the quarter ended September 30, 2017. In addition to the factors mentioned above, we also considered our recent impairments of certain unproven leasehold costs, and the impact of these items on our internal expectations for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill asset group, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $75.1 million was required; therefore, the charge was recorded in the quarter ended September 30, 2017.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 8 - COMMODITY 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, natural gas, and propane, which is an element of our NGLs, we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases.

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of September 30, 2017, we had derivative instruments, which were comprised of collars, fixed-price swaps, and basis protection swaps, in place for a portion of our anticipated 2017 and 2018 production for a total of 14,337 MBbls of crude oil, 69,715 BBtu of natural gas, and 412 MBbls of propane. Our commodity derivative contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.

We have not elected to designate any of our derivative instruments as cash flow hedges, and therefore these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations.

The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:



			Fair Value
Derivative instruments:		Condensed consolidated balance sheet line item	September 30, 2017		December 31, 2016
			(in thousands)
Derivative assets:	Current
	Commodity derivative contracts	Fair value of derivatives	$	19,042	$	8,490
	Basis protection derivative contracts	Fair value of derivatives	3,874		301
			22,916		8,791
	Non-current
	Commodity derivative contracts	Fair value of derivatives	3,942		1,123
	Basis protection derivative contracts	Fair value of derivatives	663		1,263
			4,605		2,386
Total derivative assets			$	27,521	$	11,177

Derivative liabilities:	Current
	Commodity derivative contracts	Fair value of derivatives	$	25,895	$	53,565
	Basis protection derivative contracts	Fair value of derivatives	92		30
			25,987		53,595
	Non-current
	Commodity derivative contracts	Fair value of derivatives	7,244		27,595
	Basis protection derivative contracts	Fair value of derivatives	17		—
			7,261		27,595
Total derivative liabilities			$	33,248	$	81,190

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
Condensed consolidated statement of operations line item	2017			2016			2017		2016
	(in thousands)
Commodity price risk management gain, net
Net settlements	$	9,585		$	47,728		$	22,151	$	167,859
Net change in fair value of unsettled derivatives	(61,763		)	(28,331		)	64,307		(230,207		)
Total commodity price risk management gain, net	$	(52,178	)	$	19,397		$	86,458	$	(62,348	)

Net settlements of commodity derivatives decreased for the three and nine months ended September 30, 2017 as compared to the three and nine months ended September 30, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value agreements settled by the end of 2016. Net settlements for the three and nine months ended September 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. Based on forward strip pricing at September 30, 2017, we expect that settlements will continue to be substantially lower in 2017 on a relative basis as compared to those in 2016.

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. 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 September 30, 2017	Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	27,521	$	(15,010	)	$	12,511

Liability derivatives:
Derivative instruments, at fair value	$	33,248	$	(15,010	)	$	18,238



As of December 31, 2016	Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	11,177	$	(10,930	)	$	247

Liability derivatives:
Derivative instruments, at fair value	$	81,190	$	(10,930	)	$	70,260

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 9 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Determination of Fair Value

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

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

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

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 upon 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, determination that the source of the inputs is valid, corroboration of the original source of inputs through access to multiple quotes, if available, or other information, and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and 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:



	September 30, 2017									December 31, 2016
	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
	(in thousands)
Assets:
Total assets	$	24,553		$	2,968		$	27,521		$	6,350		$	4,827		$	11,177
Total liabilities	(23,811		)	(9,437		)	(33,248		)	(66,789		)	(14,401		)	(81,190		)
Net asset (liability)	$	742		$	(6,469	)	$	(5,727	)	$	(60,439	)	$	(9,574	)	$	(70,013	)

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period	$	8,619		$	27,375		$	(9,574	)	$	91,288
Changes in fair value included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net	(14,075		)	4,234			8,547			(16,023		)
Settlements included in condensed consolidated statement of operations line items:
Commodity price risk management gain (loss), net	(1,013		)	(15,587		)	(5,442		)	(59,243		)
Fair value of Level 3 instruments, net asset end of period	$	(6,469	)	$	16,022		$	(6,469	)	$	16,022

Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net	$	(8,711	)	$	(2,240	)	$	(583	)	$	(8,273	)

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 during the periods covered by this report.

Non-Derivative Financial Assets and Liabilities

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

We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties and goodwill for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 3 input, in the derivation of the value estimation.

The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of September 30, 2017.



		Estimated Fair Value		Percent of Par
		(in millions)
Senior notes:
	2021 Convertible Notes	$	196.3	98.1	%
	2022 Senior Notes	521.9		104.4	%
	2024 Senior Notes	412.5		103.1	%

The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

Concentration of Risk

Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts. An insignificant portion of our commodity derivative instruments may be with other counterparties. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at September 30, 2017, taking into account the estimated likelihood of nonperformance.

Cash and Cash Equivalents. We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at September 30, 2017. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also major lenders under our revolving credit facility.

NOTE 10 - NOTE RECEIVABLE

In October 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $39.0 million, bearing variable interest rates. The interest was to be paid quarterly, in arrears and at the option of the issuer could be paid-in-kind (“PIK Interest”). Any such PIK Interest would be subject to the then current interest rate.

We regularly analyzed the Promissory Note for evidence of collectability, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the issuer's assets. Based upon this analysis, during the quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million accumulated outstanding balance, including interest. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Promissory Note and began accounting for the interest on the Promissory Note under the cash basis method.

We performed this analysis as of March 31, 2017 and evaluated preliminary 2016 year-end financial statements of the note issuer which were available at such time, related information about the operations of the issuer, and existing market conditions for natural gas. Based upon this evaluation, it was determined that collection of the Promissory Note and the PIK Interest continued to be doubtful and the full valuation allowance on the Promissory Note remained appropriate as of that date. This evaluation assumed that repayment of the Promissory Note would be made exclusively from the existing operations of the issuer of the Promissory Note based on the latest available information.

In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash. The sales agreement transferred all of our legal rights to collect from the issuer of the Promissory Note. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 11 - 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. Consequently, based upon the mix and timing of our actual annual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective income tax rate, adjusted for the effect of discrete items.

The effective income tax rates for the three and nine months ended September 30, 2017 were 29.5 percent and 25.8 percent benefit on loss, respectively, compared to 34.0 percent and 37.1 percent benefit on loss for the three and nine months ended September 30, 2016. The most significant element related to the decrease in the effective income tax rate was the impact from the $75.1 million impairment of the goodwill in the quarter ended September 30, 2017. This goodwill did not have an associated deferred tax liability at the time it was created, therefore, no deferred tax benefit was realized upon the impairment of the goodwill. The effective income tax rates for the three and nine months ended September 30, 2017, are based upon a full year forecasted tax benefit on loss. In addition to the impact from the goodwill impairment, the effective income tax rate for the three months ended September 30, 2017 includes discrete income tax benefits of $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state income tax returns. The effective income tax rate for the nine months ended September 30, 2017 includes discrete income tax benefits of $1.8 million relating to the excess income tax benefit recognized with the vesting of stock awards and $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state tax returns. These discrete tax benefits during the three and nine months ended September 30, 2017 resulted in a 0.2 percent and 0.9 percent increase to our effective income tax rates. We anticipate the potential for increased periodic volatility in future effective income tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items.

The effective income tax rates for the three and nine months ended September 30, 2016, were based upon a full year forecasted income tax benefit on loss and were greater than the statutory federal income tax rate, primarily due to state income taxes and percentage depletion, partially offset by nondeductible officers’ compensation and nondeductible lobbying expenses. There were no significant discrete income tax items recorded during the three and nine months ended September 30, 2016.

As of September 30, 2017, there is no liability for unrecognized income tax 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 any state income tax examinations. We continue to voluntarily participate in the Internal Revenue Service's Compliance Assurance Program for the 2016 and 2017 tax years, and received final acceptance of our 2015 federal income tax return and partial acceptance of the recently filed 2016 federal income tax return that is now going through the IRS CAP post-filing review process.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 12 - LONG-TERM DEBT

Long-term debt consisted of the following as of:



	September 30, 2017			December 31, 2016
	(in thousands)
Senior notes:
1.125% Convertible Notes due 2021:
Principal amount	$	200,000		$	200,000
Unamortized discount	(32,153		)	(37,475		)
Unamortized debt issuance costs	(3,859		)	(4,584		)
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs	163,988			157,941

7.75% Senior Notes due 2022:
Principal amount	500,000			500,000
Unamortized debt issuance costs	(5,602		)	(6,443		)
7.75% Senior Notes due 2022, net of unamortized debt issuance costs	494,398			493,557

6.125% Senior Notes due 2024:
Principal amount	400,000			400,000
Unamortized debt issuance costs	(6,815		)	(7,544		)
6.125% Senior Notes due 2024, net of unamortized debt issuance costs	393,185			392,456

Total senior notes	1,051,571			1,043,954

Revolving credit facility	—			—
Total long-term debt, net of unamortized discount and debt issuance costs	$	1,051,571		$	1,043,954

Senior Notes

2021 Convertible Notes. In September 2016, we issued $200 million of 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in a public offering. The maturity for the payment of principal is September 15, 2021. Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15. The conversion stock price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, priced on the same day we issued the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs. As of September 30, 2017, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of 5.8 percent.

Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares of our common stock, as well as cash in lieu of fractional shares.

2022 Senior Notes. In October 2012, we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”). The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15. Approximately $11.0 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method.

2024 Senior Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”) in a private placement to qualified institutional buyers. In May 2017, in accordance with the registration rights agreement that we entered into with the initial purchasers when we issued the 2024

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

Senior Notes, we filed a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms, and we completed the exchange offer in September 2017. The 2024 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method.

In January 2017, pursuant to the filing of supplemental indentures for the 2021 Convertible Notes, 2022 Senior Notes, and the 2024 Senior Notes (collectively, the "Notes"), our wholly-owned subsidiary, PDC Permian, Inc. became a guarantor of our obligations under the Notes. Accordingly, condensed consolidating financial information for PDC and PDC Permian, Inc. is presented in the footnote titled Subsidiary Guarantor.

As of September 30, 2017, we were in compliance with all covenants related to the Notes, and expect to remain in compliance throughout the next 12-month period.

Revolving Credit Facility

Revolving Credit Facility. The revolving credit facility is available for working capital requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility matures in May 2020 and provides for a maximum of $1.0 billion in allowable borrowing capacity, subject to the borrowing base and certain limitations under our senior notes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility.

In May 2017, we entered into a Fifth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amended the revolving credit facility to reflect an increase in the borrowing base from $700 million to $950 million. In addition, the Fifth Amendment made changes to certain of the financial and non-financial covenants in the existing agreement, as well as other administrative changes.

In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment amends the revolving credit facility to allow the borrowing base to increase above the maximum allowable borrowing capacity of $1.0 billion. We have elected to increase the fall 2017 borrowing base to $1.1 billion and maintain a $700 million commitment level as of the date of this report. As of September 30, 2017, available funds under our revolving credit facility were $700 million based on our elected commitment level.

As of September 30, 2017 and December 31, 2016, debt issuance costs related to our revolving credit facility were $6.8 million and $8.8 million, respectively, and are included in other assets on the condensed consolidated balance sheets. We had no outstanding balance on our revolving credit facility as of September 30, 2017 or December 31, 2016. The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin, and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of September 30, 2017, the applicable interest margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.5 percent. No principal payments are generally required until the revolving credit facility expires in May 2020, or in the event that the borrowing base falls below the outstanding balance.

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 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of September 30, 2017, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. As defined by the revolving credit facility, our leverage ratio was 1.8 and our current ratio was 2.9 as of September 30, 2017.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 13 - OTHER ACCRUED EXPENSES

Other Accrued Expenses. The following table presents the components of other accrued expenses as of:



	September 30, 2017		December 31, 2016
	(in thousands)

Employee benefits	$	14,401	$	22,282
Asset retirement obligations	13,128		9,775
Other	5,922		6,568
Other accrued expenses	$	33,451	$	38,625

NOTE 14 - CAPITAL LEASES

We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease.

The following table presents vehicles under capital lease as of:



	September 30, 2017			December 31, 2016
	(in thousands)
Vehicles	$	6,301		$	2,975
Accumulated depreciation	(1,435		)	(776		)
	$	4,866		$	2,199

Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following:



For the Twelve Months Ending September 30,	Amount
	(in thousands)
2018	$	2,207
2019	1,617
2020	1,758
	5,582
Less executory cost	(258		)
Less amount representing interest	(615		)
Present value of minimum lease payments	$	4,709

Short-term capital lease obligations	$	1,768
Long-term capital lease obligations	2,941
	$	4,709

Short-term capital lease obligations are included in other accrued expenses on the condensed consolidated balance sheets and long-term capital lease obligations are included in other liabilities on the condensed consolidated balance sheets.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

NOTE 15 - ASSET RETIREMENT OBLIGATIONS

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



	Amount
	(in thousands)

Balance at December 31, 2016	$	92,387
Obligations incurred with development activities	3,296
Accretion expense	4,906
Revisions in estimated cash flows	155
Obligations discharged with asset retirements	(8,929		)
Balance at September 30, 2017	91,815
Less liabilities held for sale	(499		)
Less current portion	(13,128		)
Long-term portion	$	78,188

Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging and abandonment costs considering federal and state regulatory requirements in effect. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. As of September 30, 2017, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.

NOTE 16 - COMMITMENTS AND CONTINGENCIES

Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing 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 our affiliated partnerships and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. Our condensed consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered.

The following table presents gross volume information related to our long-term firm transportation and processing agreements for pipeline capacity:



	For the Twelve Months Ending September 30,
Area	2018		2019		2020		2021		2022 and Through Expiration		Total		Expiration Date

Natural gas (MMcf)
Wattenberg Field	—		16,760		30,850		31,025		131,287		209,922		March 31, 2026
Delaware Basin	14,600		14,600		14,640		3,680		—		47,520		December 31, 2020
Gas Marketing	7,117		7,117		7,136		7,117		6,227		34,714		August 31, 2022
Utica Shale	2,738		2,738		2,745		2,738		5,016		15,975		July 22, 2023
Total	24,455		41,215		55,371		44,560		142,530		308,131

Crude oil (MBbls)
Wattenberg Field	2,413		2,413		1,812		—		—		6,638		June 30, 2020

Dollar commitment (in thousands)	$	18,410	$	35,170	$	44,949	$	33,776	$	129,546	$	261,851

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

In anticipation of our future drilling activities in the Wattenberg Field, we entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct two new 200 MMcfd cryogenic plants. We will be bound to the volume requirements in these agreements on the first day of the calendar month after the actual in-service date of the plants, which in the above table is scheduled to be in the fourth quarter of 2018 for the first plant and April 2019 for the second plant. We are currently working with this midstream provider to identify opportunities to accelerate the completion of the first of these processing facilities. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall of these volume commitments may be offset by additional third party producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. We currently expect that our future development plans will support the utilization of the incremental commitments.

In April 2017, we entered into a transportation service agreement for delivery of 40,000 dekatherms per day of our Delaware Basin natural gas production to the Waha market hub in West Texas.

For each of the three and nine months ended September 30, 2017, commitments for long-term transportation volumes, net to our interest, for Wattenberg Field crude oil, Delaware Basin natural gas, and Utica Shale natural gas were $2.6 million and $7.4 million, respectively, and were recorded in transportation, gathering, and processing expenses in our condensed consolidated statements of operations. For each of the three and nine months ended September 30, 2016, commitments for long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $2.6 million and $7.2 million, respectively.

Litigation and Legal Items. The Company is involved in various legal proceedings. 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. Management has provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. However, the liability ultimately incurred with respect to a matter may exceed the related accrual. 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.

Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills 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. Except as discussed herein, we are not aware of any material environmental claims existing as of September 30, 2017 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws will not be discovered on our properties. However, the liability ultimately incurred with respect to a matter may exceed the related accrual. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets.

Clean Air Act Tentative Agreement and Related Consent Decree. In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado ("DJ Basin"). The Information Request focused on historical operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016.

In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law.

For more than a year, we held a series of meetings with the EPA, Department of Justice (“DOJ”) and CDPHE on the above matters. On June 26, 2017, the DOJ on behalf of the EPA and the State of Colorado filed a complaint against us based on the above matters. We continued to conduct meetings with these agencies in working toward a resolution of the matters. On September 28, 2017, the parties jointly filed for an extension of time for PDC to reply to the complaint. The extension was requested because the parties reached an agreement to resolve the case subject to final approval by the appropriate persons within the federal government and state government, as well as outcome of the period of public comment on the proposed decree.

A consent decree was signed by all parties on October 31, 2017 and is subject to a 30-day comment period in which it will be publicly published in the Federal Register. The consent decree provides that we will implement changes to our design, operation, and maintenance of most of our field-wide storage tank systems to enhance our emission management in the DJ Basin. Agreed upon and planned efforts include, but are not limited to, vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. We voluntarily included in the consent decree approximately 40 additional facilities associated with our pending acquisition of additional assets in the basin. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects); (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million. Certain expenditures for the injunctive relief are believed to have been incurred in 2016 and 2017, with the remainder expected to be incurred over the next few years. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. Although we believe the consent decree will be approved by the court following the comment period, this cannot be guaranteed.

NOTE 17 - COMMON STOCK

Sale of Equity Securities

During December 2016, we issued 9.4 million shares of our common stock as partial consideration for 100 percent of the common stock of Arris Petroleum and for the acquisition of certain Delaware Basin properties. Pursuant to the terms of previously disclosed lock-up agreements, the resale of these shares was restricted. The lock-up period ended on June 4, 2017. We have registered the 9.4 million shares of our common stock for resale under the Securities Act of 1933.

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)

Stock-based compensation expense	$	4,761		$	4,079		$	14,587		$	15,205
Income tax benefit	(1,781		)	(1,552		)	(5,457		)	(5,786		)
Net stock-based compensation expense	$	2,980		$	2,527		$	9,130		$	9,419

Stock Appreciation Rights

The stock appreciation right ("SARs") vest ratably over a three-year period and may be exercised at any point after vesting through ten 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

September 30, 2017

(unaudited)

The Compensation Committee of our Board of Directors awarded SARs to our executive officers during the nine months ended September 30, 2017 and 2016. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:



	Nine Months Ended September 30,
	2017			2016

Expected term of award (in years)	6			6
Risk-free interest rate	2.0		%	1.8		%
Expected volatility	53.3		%	54.5		%
Weighted-average grant date fair value per share	$	38.58		$	26.96

The expected 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 for the nine months ended September 30, 2017:



	Number of SARs	Weighted-Average Exercise Price		Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2016	244,078	$	41.36	6.9	$	7,620
Awarded	54,142	74.57		—	—
Outstanding at September 30, 2017	298,220	47.39		6.7	2,043
Exercisable at September 30, 2017	186,248	39.38		5.6	1,867

Total compensation cost related to non-vested SARs granted and not yet recognized in our condensed consolidated statement of operations as of September 30, 2017 was $2.3 million. The cost is expected to be recognized over a weighted-average period of 1.9 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 generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed.

The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the nine months ended September 30, 2017:



	Shares		Weighted-Average Grant Date Fair Value per Share

Non-vested at December 31, 2016	479,642		$	56.09
Granted	260,019		66.00
Vested	(206,242	)	56.44
Forfeited	(7,990	)	64.32
Non-vested at September 30, 2017	525,429		60.73

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

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



	As of/Nine Months Ended September 30,
	2017		2016
	(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	13,266	$	14,675
Total intrinsic value of time-based awards non-vested	25,762		35,079
Market price per common share as of September 30,	49.03		67.06
Weighted-average grant date fair value per share	66.00		57.12

Total compensation cost related to non-vested time-based awards and not yet recognized in our condensed consolidated statements of operations as of September 30, 2017 was $22.0 million. This cost is expected to be recognized over a weighted-average period of 1.9 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 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.

The Compensation Committee of our Board of Directors awarded a total of 28,069 market-based restricted shares to our executive officers during the nine months ended September 30, 2017. In addition to continuous employment, the vesting of these shares is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2019, and can result in a payout between 0 percent and 200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions:



	Nine Months Ended September 30,
	2017			2016

Expected term of award (in years)	3			3
Risk-free interest rate	1.4		%	1.2		%
Expected volatility	51.4		%	52.3		%
Weighted-average grant date fair value per share	$	94.02		$	72.54

The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility.

The following table presents the change in non-vested market-based awards during the nine months ended September 30, 2017:



	Shares	Weighted-Average Grant Date Fair Value per Share

Non-vested at December 31, 2016	48,420	$	64.97
Granted	28,069	94.02
Non-vested at September 30, 2017	76,489	75.63

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

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



	As of /Nine Months Ended September 30,
	2017		2016
	(in thousands, except per share data)

Total intrinsic value of market-based awards vested	$	—	$	1,174
Total intrinsic value of market-based awards non-vested	3,750		5,670
Market price per common share as of September 30,	49.03		67.06
Weighted-average grant date fair value per share	94.02		72.54

Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operations as of September 30, 2017 was $2.9 million. This cost is expected to be recognized over a weighted-average period of 1.9 years.

Treasury Share Purchases

In June 2010, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, as amended in June 2013, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares granted may be either authorized but unissued shares, treasury shares, or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of SARs, paid out in the form of cash. In accordance with our stock-based compensation plans, employees and directors may surrender shares of our common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are reissued for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to additional paid-in capital. As of December 31, 2016, we had 10,397 shares remaining available for reissuance pursuant to our 2010 plan. Additionally, as of December 31, 2016, we had 18,366 of shares of treasury stock related to a rabbi trust. During the nine months ended September 30, 2017, we acquired 80,572 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 49,446 shares were reissued and 41,523 shares are available for reissuance pursuant to the 2010 Plan.

Preferred Stock

We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Board from time to time. Through September 30, 2017, no preferred shares have been issued.

NOTE 18 - EARNINGS PER SHARE

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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
	(in thousands)

Weighted-average common shares outstanding - basic	65,865	48,839	65,825	45,741
Weighted-average common shares and equivalents outstanding - diluted	65,865	48,839	65,825	45,741

We reported a net loss for the three and nine months ended September 30, 2017 and 2016. As a result, our basic and diluted weighted-average common shares outstanding were the same for each period because the effect of the common share equivalents was anti-dilutive.

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
	(in thousands)

Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
Restricted stock	588	660	585	705
Convertible notes	—	—	—	345
Other equity-based awards	48	97	82	103
Total anti-dilutive common share equivalents	636	757	667	1,153

In September 2016, we issued the 2021 Convertible Notes, which give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during the periods presented. During the three and nine months ended September 30, 2017, the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion of the 2021 Convertible Notes were not included in the diluted earnings per share calculation.

In November 2010, we issued $115.0 million aggregate principal amount of 3.25% convertible senior notes that were due in 2016 ("2016 Convertible Notes"), which gave the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured in May 2016. Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method when the average market share price exceeded the $42.40 conversion price during the periods presented.

NOTE 19 - SUBSIDIARY GUARANTOR

Our subsidiary PDC Permian, Inc. guarantees our obligations under our publicly-registered Notes. The following presents the condensed consolidating financial information separately for:



(i)	PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries;
(ii)	PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our Notes;
(iii)	Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and
(iv)	Parent and subsidiaries on a consolidated basis ("Consolidated").

The Guarantor is 100% owned by the Parent beginning in December 2016. The Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)

the occurrence of certain customary conditions. Each entity in the condensed consolidating financial information follows the same accounting policies as described in the notes to the condensed consolidated financial statements.

The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column.



	Condensed Consolidating Balance Sheets
	September 30, 2017
	Parent		Guarantor		Eliminations			Consolidated
	(in thousands)
Assets
Current assets	$	299,239	$	35,463	$	—		$	334,702
Properties and equipment, net	1,911,759		1,970,941		—			3,882,700
Intercompany receivable	199,871		—		(199,871		)	—
Investment in subsidiaries	1,467,623		—		(1,467,623		)	—
Noncurrent assets	89,245		640		—			89,885
Total Assets	$	3,967,737	$	2,007,044	$	(1,667,494	)	$	4,307,287

Liabilities and Stockholders' Equity
Current liabilities	$	310,997	$	62,791	$	—		$	373,788
Intercompany payable	—		199,871		(199,871		)	—
Long-term debt	1,051,571		—		—			1,051,571
Other noncurrent liabilities	178,567		276,759		—			455,326
Stockholders' equity	2,426,602		1,467,623		(1,467,623		)	2,426,602
Total Liabilities and Stockholders' Equity	$	3,967,737	$	2,007,044	$	(1,667,494	)	$	4,307,287



	Condensed Consolidating Balance Sheets
	December 31, 2016
	Parent		Guarantor		Eliminations			Consolidated
	(in thousands)
Assets
Current assets	$	387,309	$	12,516	$	—		$	399,825
Properties and equipment, net	1,884,147		2,118,847		—			4,002,994
Intercompany receivable	9,415		—		(9,415		)	—
Investment in subsidiaries	1,765,092		—		(1,765,092		)	—
Goodwill	—		62,041		—			62,041
Noncurrent assets	20,811		171		—			20,982
Total Assets	$	4,066,774	$	2,193,575	$	(1,774,507	)	$	4,485,842

Liabilities and Stockholders' Equity
Current liabilities	$	235,121	$	35,457	$	—		$	270,578
Intercompany payable	—		9,415		(9,415		)	—
Long-term debt	1,043,954		—		—			1,043,954
Other noncurrent liabilities	164,945		383,611		—			548,556
Stockholders' equity	2,622,754		1,765,092		(1,765,092		)	2,622,754
Total Liabilities and Stockholders' Equity	$	4,066,774	$	2,193,575	$	(1,774,507	)	$	4,485,842

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)



	Condensed Consolidating Statements of Operations
	Three Months Ended September 30, 2017
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Operating and other revenues	$	150,015		$	33,220		$	—	$	183,235
Production and other operating expenses	41,891			13,129			—		55,020
General and administrative	26,207			3,092			—		29,299
Exploration, geologic, and geophysical expense	217			41,691			—		41,908
Depreciation depletion and amortization	106,623			18,615			—		125,238
Impairment of properties and equipment	1,148			251,592			—		252,740
Impairment of goodwill	—			75,121			—		75,121
Interest (expense) income	(19,168		)	372			—		(18,796		)
Loss before income taxes	(45,239		)	(369,648		)	—		(414,887		)
Income tax benefit	30,274			92,076			—		122,350
Equity in loss of subsidiary	(277,572		)	—			277,572		—
Net loss	$	(292,537	)	$	(277,572	)	$	277,572	$	(292,537	)



	Condensed Consolidating Statements of Operations
	Nine Months Ended September 30, 2017
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Operating and other revenues	$	657,102		$	74,998		$	—	$	732,100
Production and other operating expenses	118,779			26,049			—		144,828
General and administrative	76,353			8,792			—		85,145
Exploration, geologic, and geophysical expense	744			43,151			—		43,895
Depreciation depletion and amortization	317,088			43,479			—		360,567
Impairment of properties and equipment	2,282			280,217			—		282,499
Impairment of goodwill	—			75,121			—		75,121
Provision for uncollectible notes receivable	(40,203		)	—			—		(40,203		)
Interest (expense) income	(57,557		)	685			—		(56,872		)
Income (loss) before income taxes	124,502			(401,126		)	—		(276,624		)
Income tax expense (benefit)	(32,174		)	103,657			—		71,483
Equity in loss of subsidiary	(297,469		)	—			297,469		—
Net loss	$	(205,141	)	$	(297,469	)	$	297,469	$	(205,141	)

Net losses of the Guarantor for the three and nine months ended September 30, 2017 are primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions during the relevant periods, and the impairment of goodwill during the three months ended September 30, 2017.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2017

(unaudited)



	Condensed Consolidating Statements of Cash Flows
	Nine Months Ended September 30, 2017
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Cash flows from operating activities	$	382,715		$	28,687		$	—		$	411,402
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural properties	(315,718		)	(213,132		)	—			(528,850		)
Capital expenditures for other properties and equipment	(2,488		)	(1,252		)	—			(3,740		)
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition	(19,761		)	5,279			—			(14,482		)
Proceeds from sale of properties and equipment	3,322			—			—			3,322
Sale of promissory note	40,203			—			—			40,203
Restricted cash	(9,250		)	—			—			(9,250		)
Sales of short-term investments	49,890			—			—			49,890
Purchases of short-term investments	(49,890		)	—			—			(49,890		)
Intercompany transfers	(189,239		)	—			189,239			—
Net cash from investing activities	(492,931		)	(209,105		)	189,239			(512,797		)
Cash flows from financing activities:
Purchase of treasury stock	(5,325		)	—			—			(5,325		)
Other	(906		)	(45		)	—			(951		)
Intercompany transfers	—			189,239			(189,239		)	—
Net cash from financing activities	(6,231		)	189,194			(189,239		)	(6,276		)
Net change in cash and cash equivalents	(116,447		)	8,776			—			(107,671		)
Cash and cash equivalents, beginning of period	240,487			3,613			—			244,100
Cash and cash equivalents, end of period	$	124,040		$	12,389		$	—		$	136,429

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

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

EXECUTIVE SUMMARY

Production and Financial Overview

Production volumes increased to 8.5 MMboe and 23.2 MMboe for the three and nine months ended September 30, 2017, respectively, representing increases of 42 percent and 47 percent as compared to the three and nine months ended September 30, 2016, respectively. The increases in production volumes were primarily attributable to the continued success of our horizontal Niobrara and Codell drilling program in the Wattenberg Field and growing production from our Delaware Basin properties. Crude oil production increased 47 percent for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016, respectively. Crude oil production comprised approximately 40 percent of total production in each of the three and nine months ended September 30, 2017. NGL production increased 33 percent and 54 percent for the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016. Natural gas production increased 42 percent and 43 percent in the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016. On a combined basis, total liquids production comprised 63 percent of our total production during each of the three months ended September 30, 2017 and September 30, 2016, and 62 percent and 61 percent of total production during the nine months ended September 30, 2017 and September 30, 2016, respectively. For the three months ended September 30, 2017, we maintained an average daily production rate of approximately 92,500 Boe per day, including 12,800 Boe per day from the Delaware Basin, up from approximately 65,300 Boe per day for the three months ended September 30, 2016.

On a sequential quarterly basis, total production volumes for the three months ended September 30, 2017 as compared to the three months ended June 30, 2017 increased with contributions from both the Wattenberg Field and Delaware Basin. For the three months ended September 30, 2017 as compared to the three months ended June 30, 2017, total production and crude oil production each increased by six percent. Continued high line pressures in the Wattenberg Field have temporarily tempered the growth rate in the Wattenberg Field; however, we are expecting an overall modest sequential quarterly increase in production in the fourth quarter of 2017.

Crude oil, natural gas, and NGLs sales increased to $232.7 million and $636.0 million in the three and nine months ended September 30, 2017, respectively, compared to $141.8 million and $328.0 million in the three and nine months ended September 30, 2016, respectively. These 64 percent and 94 percent increases in sales revenues were driven by the 42 percent and 47 percent increases in production and 16 percent and 32 percent increases in average realized commodity prices.

We had positive net settlements from our commodity derivative contracts of $9.6 million for the three months ended September 30, 2017 as compared to positive net settlements of $47.7 million for the three months ended September 30, 2016. We had positive net settlements of $22.2 million for the nine months ended September 30, 2017, as compared to positive net settlements of $167.9 million for the nine months ended September 30, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value derivatives settled by the end of 2016. Net settlements for the three and nine months ended September 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. Based upon the forward strip pricing at September 30, 2017, we expect that settlements will continue to be substantially lower in 2017 than in 2016. See Results of Operations - Commodity Price Risk Management, Net for further details of our settlements of derivatives and changes in the fair value of unsettled derivatives.

The combined revenue from crude oil, natural gas, and NGLs sales and net settlements received on our commodity derivative instruments increased 28 percent to $242.3 million in the three months ended September 30, 2017 from $189.5 million in the three months ended September 30, 2016, and increased 33 percent to $658.2 million in the nine months ended September 30, 2017 from $495.9 million in the nine months ended September 30, 2016.

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During the three months ended September 30, 2017, we recorded exploratory dry hole well expense of $41.2 million, an unproved property impairment charge of $251.6 million, and we impaired all of the goodwill associated with the assets acquired in the Delaware Basin, which resulted in an impairment charge of $75.1 million. For more information regarding these expenses and charges see Results of Operations - Exploration, Geologic, and Geophysical Expense, Results of Operations - Impairments of Properties, and Results of Operations - Impairment of Goodwill.

In the three and nine months ended September 30, 2017, we generated a net loss of $292.5 million and $205.1 million, respectively, or $4.44 and $3.12 per diluted share, respectively. Our net income was negatively impacted by the aforementioned impairment charges and expensing of exploratory dry hole well costs. During the same periods, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $166.9 million and $497.6 million, respectively. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic and geophysical expense in our reconciliation of adjusted EBITDAX. In prior periods, we reported adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments. All prior periods have been conformed for comparability of this updated presentation. In the three and nine months ended September 30, 2016, our net loss per diluted share was $0.48 and $4.16, respectively, and our adjusted EBITDAX was $133.0 million and $313.3 million, respectively. Our cash flow from operations was $411.4 million and our adjusted cash flow from operations, a non-U.S. GAAP financial measure, was $407.5 million in the nine months ended September 30, 2017. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.

Liquidity

Available liquidity as of September 30, 2017 was $836.4 million, which was comprised of $136.4 million of cash and cash equivalents and $700 million available for borrowing under our revolving credit facility at our current commitment level. We expect decreases in our cash balance during the remainder of 2017 due to: (i) the expected closing of the pending Wattenberg Field acquisition described below, (ii) continued planned development in the core Wattenberg Field, and (iii) further capital investment in our Delaware Basin assets. In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment allowed the borrowing base to be set above the $1.0 billion allowable borrowing capacity of the facility. The borrowing base redetermination for the fall of 2017 was confirmed at $1.1 billion and we elected to maintain a $700 million commitment level as of the date of this report.

We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, potential utilization of our borrowing capacity under our revolving credit facility, and if warranted, capital markets transactions from time to time.

Pending Acquisition and Acreage Exchanges

Pending Acquisition. In September 2017, we entered into a purchase and sale agreement to acquire certain assets from Bayswater and certain related parties, pursuant to which, subject to the terms and conditions of the agreement, we have agreed to acquire approximately 8,300 net acres, 30 DUCs, and an incremental 240 gross drilling locations, for approximately $210 million in cash, subject to certain pre- and post-closing adjustments. We plan to turn-in-line 18 of these DUCs at approximately year-end 2017, with the completion costs expected to be treated as an increase to the purchase price. Upon executing the purchase and sale agreement, we paid a $21 million deposit toward the purchase price into an escrow account, which is included in other assets in our September 30, 2017 condensed consolidated balance sheet. Assuming all conditions required for closing are met, the acquisition is expected to close in December 2017 and will be funded by a combination of available cash and debt.

Pending Acreage Exchanges. In September 2017, we entered into an acreage exchange transaction to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we will exchange leasehold acreage with some limited in-process development wells. Upon closing, we expect to receive approximately 11,700 net acres in exchange for approximately 12,100 net acres, with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. The acreage exchange is anticipated to close in the fourth quarter of 2017; however, there can be no assurance that conditions to closing will be satisfied.

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exchange for approximately 4,100 net acres with minimal cash exchanged between the parties. The difference in net acres is primarily due to variances in working and net revenue interests. This acreage exchange is also expected to close in the fourth quarter of 2017; however, there can be no assurance that conditions to closing will be satisfied.

Operational Overview

During the nine months ended September 30, 2017, we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. Our drilling efficiency in the Wattenberg Field over the last nine months has resulted in shorter drill cycle times; therefore, we decreased our rig count to three rigs in the fourth quarter of 2017. Because of the shorter drill times, the impact of the reduced rig count on our expected turn-in-line count in the Wattenberg Field is expected to be minimal in 2017. In the Delaware Basin, during the three months ended September 30, 2017, we adjusted to operating three drilling rigs. During the third quarter of 2017, we turned in line to sales 39 wells in Wattenberg and four wells in the Delaware Basin.

The following tables summarizes our drilling and completion activity for the nine months ended September 30, 2017:



	Wells Operated by PDC
	Wattenberg Field				Delaware Basin				Total
	Gross		Net		Gross		Net		Gross		Net
In-process as of December 31, 2016	64		52.7		5		4.8		69		57.5
Wells spud	119		105.6		18		16.6		137		122.2
Wells turned-in-line to sales	(111	)	(93.6	)	(11	)	(10.2	)	(122	)	(103.8	)
Exploratory dry holes	—		—		(2	)	(2.0	)	(2	)	(2.0	)
In-process as of September 30, 2017	72		64.7		10		9.2		82		73.9



	Wells Operated by Others
	Wattenberg Field				Delaware Basin				Total
	Gross		Net		Gross		Net		Gross		Net
In-process as of December 31, 2016	18		3.4		—		—		18		3.4
Wells spud	89		12.2		7		1.0		96		13.2
Wells turned-in-line to sales	(40	)	(4.5	)	(2	)	(0.4	)	(42	)	(4.9	)
In-process as of September 30, 2017	67		11.1		5		0.6		72		11.7

Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our DUCs are generally completed and turned in-line to sales within three to nine months of drilling. The majority of the PDC-operated in-process wells at each period end are DUCs, as we do not begin the completion process until the entire well pad is drilled. As we continue to monitor our capital investment and due to the efficiencies gained by our operating team in the Wattenberg Field, we expect that we will have an increase of approximately 25 wells in our in-process well count at December 31, 2017 relative to September 30, 2017. All appropriate costs incurred through the end of the period have been capitalized, while the capital investment to complete the wells will be incurred in the period in which the wells are completed. We expect that the level of non-operated well activity reflected in the table above will decrease upon the anticipated closing of our aforementioned pending acreage exchanges.

2017 Operational Outlook

Based on our revised timing of well completions and the estimated productivity of wells associated with our capital investment program, we currently believe that our 2017 production will be approximately 32 MMBoe. We expect that approximately 40 percent of our 2017 production will be crude oil and approximately 23 percent will be NGLs, for total liquids of approximately 63 percent. The anticipated percentage of production from NGLs has increased due to the success of field recovery efforts and improved yields by our third-party processors in the Wattenberg Field.

We expect our capital expenditures to be approximately $800 million in 2017, which takes into account the current increased per well costs in the Delaware Basin and the anticipated increase in the expected number of wells to be spud in the Wattenberg Field during the year compared to our original 2017 budget. As previously disclosed, we added a third and fourth rig in the first quarter of 2017 in the Delaware Basin, which was sooner than initially contemplated in our budget, in order to protect certain leasehold positions and to create greater future operational flexibility. Finally, some additional

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capital investment has been included in our forecast for the closed and anticipated Wattenberg Field acreage trades that would, if completed, increase our working interest in certain wells.

Wattenberg Field. The 2017 capital investment forecast is estimated at approximately $450 million in the Wattenberg Field. Our plan contemplates running three rigs in the field in the fourth quarter of 2017. Approximately $445 million is expected to be allocated to development activities, comprised of approximately $425 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder is expected to be used for miscellaneous well equipment and capital projects. Wells in the Wattenberg Field typically have productive horizons at a depth of approximately 6,500 to 7,500 feet below the surface. Our revised investment forecast anticipates spudding approximately 155 and turning-in-line approximately 133 horizontal operated wells with lateral lengths of 4,000 to 10,000 feet. We do not expect to increase our 2017 capital investment forecast in connection with the acquisition agreement we entered into with Bayswater and certain related parties, as the acquisition is expected to close late in December. There are expected to be costs in addition to the $210 million purchase price as a result of continued capital activity on the DUCs being acquired in the transaction, which will be accounted for as additional purchase price.

Delaware Basin. We are currently operating a three-rig drilling program in the Delaware Basin. Total capital investment in the Delaware Basin for the year is estimated to be approximately $345 million, of which approximately $285 million is expected to be used to spud 24 and turn-in-line an estimated 20 wells. Expected per well drilling costs in the Delaware Basin have increased by approximately 10 to 15 percent during the third quarter of 2017 as compared to the second quarter of 2017, primarily due to higher costs of services and supplies and longer than anticipated drill cycle times. To enhance our understanding of the geology in the Delaware Basin, we initiated various engineering studies on a large portion of our Delaware Basin wells, including expanded depth pilot holes and logging/seismic services. These studies are providing important information to our operating team; however, they have come with additional unexpected costs. Additionally, mechanical issues have resulted in cost overruns for certain wells we have drilled in the area. Of the 20 planned turn-in-lines during 2017, nine are expected to have extended laterals of approximately 10,000 horizontal feet with an estimated 70 to 75 completion stages per well. Similarly spaced completion stages are anticipated for the remaining 11 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at a depth of approximately 9,000 to 11,000 feet below the surface. We plan to invest approximately $15 million for leasing, seismic, and technical studies with an additional $35 million for midstream-related projects including gas connections and surface location infrastructure. The remaining $10 million of the Delaware Basin capital investment program is expected to be used for non-operated capital projects.

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Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results:



	Three Months Ended September 30,							Nine Months Ended September 30,
	2017			2016		Percentage Change		2017			2016		Percentage Change
	(dollars in millions, except per unit data)
Production
Crude oil (MBbls)	3,439			2,340		47.0	%	9,184			6,241		47.2	%
Natural gas (MMcf)	19,070			13,417		42.1	%	52,437			36,768		42.6	%
NGLs (MBbls)	1,892			1,428		32.5	%	5,249			3,402		54.3	%
Crude oil equivalent (MBoe)	8,509			6,004		41.7	%	23,172			15,771		46.9	%
Average Boe per day (Boe)	92,491			65,263		41.7	%	84,880			57,558		47.5	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	157.0		$	98.5	59.4	%	$	428.8		$	233.0	84.0	%
Natural gas	41.5			27.4		51.5	%	116.7			59.6		95.8	%
NGLs	34.2			15.9		115.1	%	90.5			35.4		155.6	%
Total crude oil, natural gas, and NGLs sales	$	232.7		$	141.8	64.1	%	$	636.0		$	328.0	93.9	%

Net Settlements on Commodity Derivatives
Crude oil	$	5.4		$	39.5	(86.3	)%	$	7.4		$	131.6	(94.4	)%
Natural gas	6.3			8.2		(23.2	)%	16.8			36.3		(53.7	)%
NGLs (propane portion)	(2.1		)	—		*		(2.0		)	—		*
Total net settlements on derivatives	$	9.6		$	47.7	(79.9	)%	$	22.2		$	167.9	(86.8	)%

Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	45.66		$	42.11	8.4	%	$	46.69		$	37.33	25.1	%
Natural gas (per Mcf)	2.17			2.04		6.4	%	2.23			1.62		37.7	%
NGLs (per Bbl)	18.11			11.12		62.9	%	17.24			10.41		65.6	%
Crude oil equivalent (per Boe)	27.35			23.62		15.8	%	27.45			20.80		32.0	%

Average Costs and Expenses (per Boe)
Lease operating expenses	$	2.98		$	2.33	27.9	%	$	2.81		$	2.73	2.9	%
Production taxes	1.82			1.59		14.5	%	1.85			1.25		48.0	%
Transportation, gathering and processing expenses	1.15			0.84		36.9	%	0.96			0.86		11.6	%
General and administrative expense	3.44			5.41		(36.4	)%	3.67			5.00		(26.6	)%
Depreciation, depletion and amortization	14.72			18.81		(21.7	)%	15.56			20.12		(22.7	)%

Lease Operating Expenses by Operating Region (per Boe)
Wattenberg Field	$	2.49		$	2.39	4.2	%	$	2.45		$	2.77	(11.6	)%
Delaware Basin	6.07			—		*		5.76			—		*
Utica Shale	1.91			1.27		50.4	%	1.60			1.87		(14.4	)%


*	Percentage change is not meaningful.

Amounts may not recalculate due to rounding.

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Crude Oil, Natural Gas, and NGLs Sales

For the three and nine months ended September 30, 2017, crude oil, natural gas, and NGLs sales revenue increased compared to the three and nine months ended September 30, 2016 due to the following (in millions):



	September 30, 2017
	Three Months Ended		Nine Months Ended
	(in millions)
Increase in production	$	63.0	$	154.5
Increase in average crude oil price	12.2		86.0
Increase in average natural gas price	2.5		31.7
Increase in average NGLs price	13.2		35.8
Total increase in crude oil, natural gas and NGLs sales revenue	$	90.9	$	308.0

Crude Oil, Natural Gas, and NGLs Production

The following tables present crude oil, natural gas, and NGLs production. Our acquisitions of assets in the Delaware Basin closed in December 2016; therefore, there is no comparative data for the three and nine months ended September 30, 2016:



	Three Months Ended September 30,				Nine Months Ended September 30,
Production by Operating Region	2017	2016	Percentage Change		2017	2016	Percentage Change
Crude oil (MBbls)
Wattenberg Field	2,943	2,216	32.8	%	7,883	5,929	33.0	%
Delaware Basin	436	—	*		1,075	—	*
Utica Shale	60	124	(51.4	)%	226	312	(27.7	)%
Total	3,439	2,340	47.0	%	9,184	6,241	47.2	%
Natural gas (MMcf)
Wattenberg Field	15,788	12,700	24.3	%	44,694	34,968	27.8	%
Delaware Basin	2,781	—	*		6,052	—	*
Utica Shale	501	717	(30.2	)%	1,691	1,800	(6.0	)%
Total	19,070	13,417	42.1	%	52,437	36,768	42.6	%
NGLs (MBbls)
Wattenberg Field	1,564	1,353	15.6	%	4,473	3,240	38.0	%
Delaware Basin	282	—	*		625	—	*
Utica Shale	46	75	(38.7	)%	151	162	(7.3	)%
Total	1,892	1,428	32.5	%	5,249	3,402	54.3	%
Crude oil equivalent (MBoe)
Wattenberg Field	7,138	5,686	25.5	%	19,805	14,997	32.1	%
Delaware Basin	1,182	—	*		2,709	—	*
Utica Shale	189	318	(40.6	)%	658	774	(15.0	)%
Total	8,509	6,004	41.7	%	23,172	15,771	46.9	%
Average crude oil equivalent per day (Boe)
Wattenberg Field	77,582	61,804	25.5	%	72,545	54,733	32.5	%
Delaware Basin	12,845	—	*		9,923	—	*
Utica Shale	2,064	3,459	(40.3	)%	2,412	2,825	(14.6	)%
Total	92,491	65,263	41.7	%	84,880	57,558	47.5	%

* Percentage change is not meaningful.

Amounts may not recalculate due to rounding.

In the Wattenberg Field, we rely on third-party midstream service providers to construct gathering, compression, and processing facilities to keep pace with our and the overall field's natural gas production growth. From time-to-time, our production has been adversely affected by high line pressures on the gas gathering facilities, primarily due to higher ambient temperatures and increases in field-wide production volumes. As a result, we have experienced some production

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curtailments from time to time, including in the third quarter of 2017. We believe that our 2017 production guidance range appropriately reflects the impact of such higher gathering system line pressures. Our primary midstream service provider has added some additional capacity to its system in 2017, and cooler weather is expected to help increase the efficiency of the system in the fourth quarter of 2017. For the nine months ended September 30, 2017, 93 percent of our production in the Wattenberg Field was delivered from horizontal wells, with the remaining seven percent coming from vertical wells. The horizontal wells are less prone to issues than the vertical wells in that they are newer and have greater producing capacity and higher formation pressures, and therefore tend to be more resilient to gas system pressure issues. While this will lessen the impact of the pressures, we expect to continue to operate in a constrained environment through the first nine months of 2018, at which time additional processing capacity is scheduled to be brought into operation by our primary midstream provider.

We continue to work closely with our third-party midstream providers in an effort to ensure that adequate midstream system capacity is available going forward in the Wattenberg Field. We along with other operators made a commitment with DCP Midstream, LP ("DCP") to support DCP's construction of two additional processing facilities with associated gathering pipe and compression in the field. These expansions are expected to increase DCP's system capacity, assist in the control of line pressures on its natural gas gathering facilities, and reduce production curtailments in the field. We will be bound to the incremental volume requirements in these agreements on the first day of the calendar month after the actual in-service dates of the plants, which are currently scheduled to occur in the fourth quarter of 2018 and April 2019. We are currently working with DCP to identify opportunities to accelerate the completion of the first of these facilities. The agreements impose a baseline volume commitment and a guarantee of a certain target profit margin to DCP on those volumes during the initial three years of the contracts. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments, and we believe that the contractual target profit margin will be achieved without additional payment from us. See footnote titled Commitments and Contingencies for additional details regarding the agreements. We also continue to work with all of our midstream service providers in the field in an effort to ensure all of the existing infrastructure is fully utilized and that all options for system expansions are evaluated and implemented, where possible.

The ultimate timing and availability of adequate infrastructure is not within our control and if our midstream service providers' construction projects are delayed, we could experience higher gathering line pressures that may negatively impact our ability to fulfill our growth plans. Total system infrastructure performance may also be affected by a number of other factors, including potential additional increases in production from the Wattenberg Field.

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Crude Oil, Natural Gas, and NGLs Pricing

Our results of operations depend upon many factors. Key factors include the price of crude oil, natural gas, and NGLs and our ability to market our production effectively. Crude oil, natural gas, and NGL prices have a high degree of volatility and our realizations can change substantially. Our sales prices for crude oil, natural gas, and NGLs increased during the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016. NYMEX crude oil prices increased seven percent and 20 percent, respectively, and NYMEX natural gas prices increased seven percent and 38 percent, respectively, as compared to the three and nine months ended September 30, 2016. The NGL prices in the Wattenberg Field are reflected in the tables below, net of the processing and transport costs that are embedded in the applicable percent-of-proceeds contracts, as are a portion of our Delaware Basin NGL sales.

The following tables present weighted-average sales prices of crude oil, natural gas, and NGLs for the periods presented. Our acquisitions of assets in the Delaware Basin closed in December 2016; therefore, there is no comparative data for the three and nine months ended September 30, 2016:



	Three Months Ended September 30,						Nine Months Ended September 30,
Weighted-Average Realized Sales Price by Operating Region					Percentage Change						Percentage Change
(excluding net settlements on derivatives)	2017		2016		Percentage Change		2017		2016		Percentage Change
Crude oil (per Bbl)
Wattenberg Field	$	45.80	$	42.29	8.3	%	$	46.84	$	37.42	25.2	%
Delaware Basin	45.06		—		*		46.05		—		*
Utica Shale	43.03		38.93		10.5	%	44.51		35.61		25.0	%
Weighted-average price	45.66		42.11		8.4	%	46.69		37.33		25.1	%
Natural gas (per Mcf)
Wattenberg Field	$	2.09	$	2.08	0.5	%	$	2.23	$	1.63	36.8	%
Delaware Basin	2.74		—		*		2.13		—		*
Utica Shale	1.81		1.33		36.1	%	2.56		1.44		77.8	%
Weighted-average price	2.17		2.04		6.4	%	2.23		1.62		37.7	%
NGLs (per Bbl)
Wattenberg Field	$	17.49	$	11.07	58.0	%	$	16.68	$	10.32	61.6	%
Delaware Basin	20.87		—		*		20.02		—		*
Utica Shale	22.00		12.14		81.2	%	22.40		12.22		83.3	%
Weighted-average price	18.11		11.12		62.9	%	17.24		10.41		65.6	%
Crude oil equivalent (per Boe)
Wattenberg Field	$	27.33	$	23.77	15.0	%	$	27.44	$	20.83	31.7	%
Delaware Basin	28.07		—		*		27.65		—		*
Utica Shale	23.75		20.98		13.2	%	26.98		20.26		33.2	%
Weighted-average price	27.35		23.62		15.8	%	27.45		20.80		32.0	%

* Percentage change is not meaningful.

Amounts may not recalculate due to rounding.

During the three months ended September 30, 2017, the weighted-average realized sales price for natural gas in the Delaware Basin was impacted by the entry into a natural gas gathering contract that we accounted for under the gross method of accounting; therefore, our realized price was based on the gross selling price.

Our crude oil, natural gas, and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method of accounting for natural gas and NGLs, as well as the majority of our crude oil production from the Wattenberg Field, for all of our crude oil, NGLs, and a portion of our natural gas in the Delaware Basin, and for crude oil from the Utica Shale, as the purchasers of these commodities also provide transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. We sell our commodities at the wellhead, or what is equivalent to the wellhead in situations where we gather multiple wells into larger pads, 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 therefore embedded in the wellhead price. The net-back method results in the recognition of a net sales

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price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we earn.

We use the gross method of accounting for Wattenberg Field crude oil delivered through certain pipelines, a portion of our natural gas in the Delaware Basin, and for natural gas and NGLs sales related to production from the Utica Shale, as the purchasers do not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing based on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses.

As discussed above, we enter into agreements for the sale and transportation, gathering, and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications in the condensed consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based upon average daily prices throughout each month and our natural gas average NYMEX pricing is based upon first-of-the-month index prices as this is the method used to sell the majority of each of these commodities pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after transportation, gathering, and processing expenses shown in the table below represents our approximate composite per barrel price for NGLs.



For the three months ended September 30, 2017	Average NYMEX Price		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	48.20	95	%	$	45.66	$	1.41	$	44.25
Natural gas (per MMBtu)	3.00		72	%	2.17		0.24		1.93
NGLs (per Bbl)	48.20		38	%	18.11		0.25		17.86
Crude oil equivalent (per Boe)	36.92		74	%	27.35		1.15		26.20

For the three months ended September 30, 2016	Average NYMEX Price		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	44.94	94	%	$	42.11	$	1.52	$	40.59
Natural gas (per MMBtu)	2.81		73	%	2.04		0.08		1.96
NGLs (per Bbl)	44.94		25	%	11.12		0.29		10.83
Crude oil equivalent (per Boe)	34.48		69	%	23.62		0.84		22.78

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For the nine months ended September 30, 2017	Average NYMEX Price		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	49.47	94	%	$	46.69	$	1.42	$	45.27
Natural gas (per MMBtu)	3.17		70	%	2.23		0.15		2.08
NGLs (per Bbl)	49.47		35	%	17.24		0.29		16.95
Crude oil equivalent (per Boe)	37.99		72	%	27.45		0.96		26.49

For the nine months ended September 30, 2016	Average NYMEX Price		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	41.33	90	%	$	37.33	$	1.56	$	35.77
Natural gas (per MMBtu)	2.29		71	%	1.62		0.08		1.54
NGLs (per Bbl)	41.33		25	%	10.41		0.29		10.12
Crude oil equivalent (per Boe)	30.61		68	%	20.80		0.86		19.94

Commodity Price Risk Management, Net

We use commodity derivative instruments to manage fluctuations in crude oil, natural gas, and NGLs prices. We have in place a variety of collars, fixed-price swaps, and basis swaps on a portion of our estimated crude oil, natural gas, and propane production. Because we sell all of our crude oil, natural gas, and NGLs production at prices related to the indexes inherent to our underlying derivative instruments, we ultimately realize value related to our collars of no less than the floor and no more than the ceiling. For our commodity swaps, we ultimately realize the fixed price value related to the swaps. See the footnote titled Commodity Derivative Financial Instruments for a detailed presentation of our derivative positions as of September 30, 2017.

Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, as well as the change in fair value of unsettled commodity derivatives related to our crude oil, natural gas, and propane production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing, which are included in other income and other expenses.

Net settlements of commodity derivative instruments are based on the difference between the crude oil, natural gas, and propane index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net value increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period, and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The corresponding impact of settlement of the commodity derivative instruments during the period is included in net settlements for the period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil, natural gas, and NGLs 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil fixed price swaps and collars	$	5.4		$	39.5		$	7.4		$	131.6
Natural gas fixed price swaps and collars	5.1			7.7			13.5			35.8
Natural gas basis protection swaps	1.2			0.5			3.3			0.5
NGLs (propane portion) fixed price swaps	(2.1		)	—			(2.0		)	—
Total net settlements of commodity derivative instruments	9.6			47.7			22.2			167.9
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	(15.6		)	(40.6		)	31.0			(169.5		)
Crude oil fixed price swaps and collars	(40.0		)	4.8			26.3			(48.3		)
Natural gas fixed price swaps and collars	(2.1		)	6.1			9.2			(13.1		)
Natural gas basis protection swaps	1.5			1.4			3.4			0.7
NGLs (propane portion) fixed price swaps	(5.6		)	—			(5.6		)	—
Net change in fair value of unsettled commodity derivative instruments	(61.8		)	(28.3		)	64.3			(230.2		)
Total commodity price risk management gain (loss), net	$	(52.2	)	$	19.4		$	86.5		$	(62.3	)

Net settlements of commodity derivatives decreased for the three and nine months ended September 30, 2017, as compared to the three and nine months ended September 30, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value agreements had settled by the end of 2016. Net settlements for the three and nine months ended September 30, 2017, reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. Based upon the forward strip pricing at September 30, 2017, we expect that settlements will continue to be substantially lower in 2017 on a relative basis as compared to those in 2016.

Lease Operating Expenses

Lease operating expenses increased to $2.98 per Boe and $2.81 per Boe during the three and nine months ended September 30, 2017, respectively, compared to $2.33 per Boe and $2.73 per Boe during the three and nine months ended September 30, 2016, respectively. Our lease operating expenses per Boe were $2.50 per Boe during the three months ended June 30, 2017 and $2.98 per Boe during the three months ended March 31, 2017. Our per Boe costs have increased compared to prior year periods primarily due to the expected higher per Boe costs in the Delaware Basin. The per Boe costs during the three months ended September 30, 2017 increased as compared to the three months ended September 30, 2016, primarily due to increases of $0.19 per Boe for water disposal, $0.15 per Boe for environmental remediation costs, and $0.14 per Boe for increased workover projects.

Aggregate lease operating expenses during the three months ended September 30, 2017, increased $11.4 million as compared to the three months ended September 30, 2016, of which $7.2 million related to our properties in the Delaware Basin. The increase of $11.4 million is primarily due to increases of $2.9 million for payroll and employee benefits related to increases in headcount, $1.9 million for produced water disposal, $1.8 million for increased workover projects, $1.5 million for environmental remediation costs, and $1.3 million related to additional compressor rentals to combat increased gathering system line pressures.

Aggregate lease operating expenses during the nine months ended September 30, 2017, increased $22.2 million as compared to the nine months ended September 30, 2016, of which $15.6 million related to our properties in the Delaware Basin. The increase of $22.2 million is primarily due to increases of $7.2 million for payroll and employee benefits related to increases in headcount, $3.7 million for produced water disposal, $3.5 million for workover projects, $3.1 million related to

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additional compressor rentals to combat increased gathering system line pressures, and $2.5 million related to vehicle and equipment expenses. We expect continued increases in our headcount through the remainder of 2017 as we grow our Delaware Basin production base and production team. On a per unit basis, we expect much of this increased cost of personnel will be offset by increases in our production.

Production Taxes

Production taxes are comprised mainly of severance tax and ad valorem tax and are directly related to crude oil, natural gas, and NGLs sales and are generally assessed as a percentage of net revenues. From time-to-time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative commodity prices from year-to-year. The $5.9 million and $23.3 million increases in production taxes during the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016 were primarily related to the 64 percent and 94 percent increases in crude oil, natural gas, and NGLs sales.

Transportation, Gathering, and Processing Expenses

Transportation, gathering, and processing expenses increased $4.7 million and $8.6 million during the three and nine months ended September 30, 2017, respectively, compared to the three and nine months ended September 30, 2016. The primary drivers of these increases were $1.3 million and $3.7 million increases in oil transportation costs due to increased volumes delivered through a pipeline in the Wattenberg Field and increases of $3.8 million and $5.2 million, respectively, related to natural gas gathering and transportation operations in the Delaware Basin. The increases during the three and nine months ended September 30, 2017 were slightly offset by decreases related to lower production in the Utica Shale. When feasible, we use pipelines in the Wattenberg Field to deliver crude oil to the market in an effort to decrease field truck traffic and air emissions. Transportation, gathering, and processing expenses per Boe increased to $1.15 and $0.96 for the three and nine months ended September 30, 2017, respectively, compared to $0.84 and $0.86 for the three and nine months ended September 30, 2016, respectively. As disclosed previously in this section, there is an interaction with the marketing contracts in determining if transportation, gathering, and processing costs are presented separately or presented net in the revenue section of our financial statements; therefore, the net realized price analysis is a useful analysis to understand our net realized prices.

Exploration, Geologic, and Geophysical Expense

The following table presents the major components of exploration, geologic, and geophysical expense:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)

Exploratory dry hole costs	$	41.2	$	—	$	41.2	$	—
Geological and geophysical costs, including seismic purchases	0.5		—		1.8		—
Operating, personnel and other	0.2		0.2		0.9		0.7
Total exploration, geologic, and geophysical expense	$	41.9	$	0.2	$	43.9	$	0.7

Exploratory dry hole costs. During the three and nine months ended September 30, 2017, two exploratory dry hole wells, associated lease costs, and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.2 million. The conclusion to expense these items was due to the determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, the lack of hydrocarbon production necessary for the wells to be deemed economically viable.

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Impairment of Properties and Equipment

The following table sets forth the major components of our impairment of properties and equipment expense:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)

Impairment of unproved properties	$	252.6	$	0.3	$	282.2	$	2.4
Amortization of individually insignificant unproved properties	0.1		0.6		0.3		0.7
Impairment of crude oil and natural gas properties	252.7		0.9		282.5		3.1
Land and buildings	—		—		—		3.0
Total impairment of properties and equipment	$	252.7	$	0.9	$	282.5	$	6.1

Impairment of unproved properties. Amounts represent the retirement or expiration of certain leases that are no longer part of our development plan or that we do not plan to extend and will allow to expire. Deterioration of commodity prices or other operating circumstances could result in additional impairment charges as such a change could decrease the number of wells drilled in future periods.

During the three months ended September 30, 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin, as referenced previously. We then assessed the impact of the dry holes and various factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost environment for drilling and completion services in the Delaware, (iii) our decreased future commodity price outlook, and (iv) the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during the third quarter of 2017. The amount of the impairment was based on the value assigned to individual lease acres in the final purchase price allocation of the business combination. This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. Due to the aforementioned events and circumstances in the third quarter of 2017, we evaluated our proved property for possible impairment and concluded that these assets were not impaired during the period.

Impairment of Goodwill

General and Administrative Expense

General and administrative expense decreased $3.2 million for the three months ended September 30, 2017, as compared to the three months ended September 30, 2016. The decrease of $3.2 million was primarily attributable to a decrease of $10.2 million in professional fees related to the Delaware Basin acquisition that were incurred in 2016, partially offset by

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increases of $3.7 million in payroll and employee benefits related to an increase in headcount for 2017 as compared to 2016, $2.0 million related to professional services, and $0.8 million for adjustments to the accounts receivable allowance.

General and administrative expense increased $6.3 million for the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. The increase of $6.3 million was primarily attributable to increases of $7.5 million in payroll and employee benefits due to an increase in headcount for 2017 as compared to 2016, $2.9 million related to professional services, $2.4 million related to legal settlements, $1.0 million in software maintenance agreements and subscriptions, and $1.0 million in rent expense. The increases were partially offset by a decrease of $10.2 million in professional fees related to the Delaware Basin acquisition during the third quarter of 2016. We expect continued increases in our headcount through the remainder of 2017 as we build out our Delaware Basin operations and the associated supporting service elements.

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 $123.6 million and $355.7 million for the three and nine months ended September 30, 2017, respectively, compared to $112.1 million and $314.4 million for the three and nine months ended September 30, 2016, respectively.

The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following:



	September 30, 2017
	Three Months Ended			Nine Months Ended
	(in millions)
Increase in production	$	44.5		$	138.5
Decrease in weighted-average depreciation, depletion and amortization rates	(33.0		)	(97.2		)
Total increase in DD&A expense related to crude oil and natural gas properties	$	11.5		$	41.3

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



	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Region/Area	2017		2016		2017		2016
	(per Boe)
Wattenberg Field	$	14.60	$	19.17	$	15.53	$	20.42
Delaware Basin	15.14		—		15.32		—
Utica Shale	7.64		9.59		10.21		10.52
Total weighted-average	14.52		18.66		15.35		19.94

During the three months ended September 30, 2017, as part of plans to divest the Utica Shale properties, we engaged an investment banking group and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification at the beginning of September 2017. As a result of the properties being classified as held-for-sale, we stopped recording DD&A expense on these properties during the three month period ended September 30, 2017, which has lowered the rate for the quarter.

Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $1.7 million and $4.8 million for the three and nine months ended September 30, 2017, respectively, compared to $0.9 million and $2.9 million for the three and nine months ended September 30, 2016, respectively.

Provision for Uncollectible Notes Receivable

In the first quarter of 2016, we recorded a provision for uncollectible notes receivable of $44.7 million to impair two third-party notes receivable whose collection was not reasonably assured. As described in the footnote titled Fair Value of Financial Instruments, in April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the associated notes receivable to an unrelated third-party. Accordingly, we reversed $40.2 million of the provision for

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uncollectible notes receivable during the nine months ended September 30, 2017, since all cash was collected in April 2017 from the sale of the note.

Interest Expense

Interest expense decreased $0.9 million to $19.3 million for the three months ended September 30, 2017 compared to $20.2 million for the three months ended September 30, 2016. The decrease is primarily attributable to a $9.0 million charge for a bridge loan commitment related to acquisitions of properties in the Delaware Basin during the three months ended September 30, 2016 and a $0.4 million decrease in interest expense on our 2016 Convertible Notes, which were settled in May 2016. The decreases were partially offset by a $5.3 million increase in interest relating to the issuance of our 2024 Senior Notes, a $2.6 million increase in interest expense relating to the issuance of our 2021 Convertible Notes, and a $0.9 million increase related to fees for the redetermination of the borrowing base under our revolving credit facility.

Interest expense increased $15.6 million to $58.4 million for the nine months ended September 30, 2017 compared to $42.8 million for the nine months ended September 30, 2016. The increase is primarily attributable to an $18.0 million increase in interest expense relating to the issuance of our 2024 Senior Notes, a $7.7 million increase in interest expense relating to the issuance of our 2021 Convertible Notes, and a $2.5 million increase related to fees for the redetermination of the borrowing base under our revolving credit facility. These increases were partially offset by a $9.0 million charge for the bridge loan commitment related to acquisitions of properties in the Delaware Basin during the three months ended September 30, 2016 and a $3.9 million decrease in interest expense on our 2016 Convertible Notes, which were settled in May 2016.

Provision for Income Taxes

The effective income tax rates for the three and nine months ended September 30, 2017 were 29.5 percent and 25.8 percent benefit on loss, respectively, compared to 34.0 percent and 37.1 percent benefit on loss for the three and nine months ended September 30, 2016, respectively. The most significant element related to the decrease in the effective income tax rate was the impact from the impairment of the goodwill in the quarter ended September 30, 2017. This goodwill did not have an associated deferred tax liability associated with the goodwill at the time it was created, therefore, no deferred tax benefit was realized upon the impairment of the goodwill. The effective income tax rates are based upon a full year forecasted pre-tax loss for the year adjusted for permanent differences. The forecasted full year effective income tax rate has been applied to the quarter-to-date pre-tax loss, resulting in an income tax benefit for the period. Because the estimate of full-year income or loss may change from quarter to quarter, the effective income 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 income tax rate that is determined at the end of the year. In addition to the impact from the goodwill impairment, the effective income tax rate for the three months ended September 30, 2017 includes discrete income tax benefits of $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state income tax returns. The effective income tax rate for the nine months ended September 30, 2017 includes discrete income tax benefits of $1.8 million relating to the excess income tax benefit recognized with the vesting of stock awards and $0.8 million for additional deductions and credits claimed on the filed 2016 federal and state tax returns. These discrete tax benefits during the three and nine months ended September 30, 2017 resulted in a 0.2 percent and 0.9 percent increase to our effective income tax rates.

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

The factors resulting in changes in net loss in the three and nine months ended September 30, 2017 of $292.5 million and $205.1 million, respectively, and a net loss in the three and nine months ended September 30, 2016 of $23.3 million and $190.3 million, respectively, are discussed above. These same reasons similarly impacted adjusted net loss, a non-U.S. GAAP financial measure, with the exception of the tax affected net change in fair value of unsettled derivatives of $38.6 million and $40.3 million for the three and nine months ended September 30, 2017, respectively, and $17.5 million and $142.6 million for the three and nine months ended September 30, 2016, respectively. Adjusted net loss, a non-U.S. GAAP financial measure, was $253.9 million and $245.4 million for the three and nine months ended September 30, 2017, respectively, and adjusted net loss was $5.8 million and $47.7 million for the three and nine months ended September 30, 2016, respectively. See Reconciliation of Non-U.S. GAAP Financial Measures, below for a more detailed discussion of this non-U.S. GAAP financial measure and a reconciliation of this measure to the most comparable U.S. GAAP measure.

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Financial Condition, Liquidity and Capital Resources

Our primary sources of liquidity are cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity capital market transactions, and asset sales. For the nine months ended September 30, 2017, our net cash flows from operating activities were $411.4 million.

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 principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage a portion of this volatility through our use of derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Based upon our hedge position and assuming forward strip pricing as of September 30, 2017, our derivatives may not be a significant source of cash flow in the near term.

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 September 30, 2017, we had a working capital deficit of $39.1 million compared to working capital of $129.2 million at December 31, 2016. The decrease in working capital as of September 30, 2017 is primarily the result of a decrease in cash and cash equivalents of $107.7 million related to capital investment exceeding operating cash flows and an increase in accounts payable of $97.8 million related to increased development and exploration activity, which was partially offset by an increase in the net fair value of our unsettled commodity derivative instruments of $41.7 million.

Our cash and cash equivalents were $136.4 million at September 30, 2017 and availability under our revolving credit facility was $700.0 million, providing for a total liquidity position of $836.4 million as of September 30, 2017. Our liquidity was augmented in 2017 by the $40.2 million of proceeds received in the second quarter of 2017 from the sale of the Promissory Note, as described previously. We anticipate that our capital investments will exceed our cash flows from operating activities in 2017. With this outspend, along with the expected closing of the acquisition of certain properties owned by Bayswater and certain related parties, we expect to have borrowings on our revolving credit facility at December 31, 2017.

Based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we have sufficient capital to fund our planned activities during 2017.

Our revolving credit facility is a borrowing base facility and availability under the facility is subject to redetermination generally each May and November, based upon a quantification of our proved reserves at each December 31 and June 30, respectively. The maturity date of our revolving credit facility is May 2020. Our ability to borrow under the revolving credit facility is limited under our 2022 Senior Notes to the greater of $700 million or the calculated value under an Adjusted Consolidated Tangible Net Asset test, as defined.

In May 2017, we entered into a Fifth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amends the revolving credit facility to reflect an increase of the borrowing base from $700 million to $950 million. In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other administrative changes.

In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment amends the revolving credit facility to allow the borrowing base to increase above the maximum allowable borrowing capacity of $1.0 billion. We have elected to increase the borrowing base to $1.1 billion for our fall 2017 borrowing base redetermination and have elected to maintain a $700 million commitment level as of the date of this report.

Amounts borrowed under the revolving credit facility bear interest at either an alternate base rate option or a LIBOR option as defined in the revolving credit facility plus an applicable margin, depending on the percentage of the commitment that has been utilized. As of September 30, 2017, the applicable margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.5 percent.

We had no balance outstanding on our revolving credit facility as of September 30, 2017. In May 2017, we replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-party transportation service

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provider to secure a firm transportation obligation with a $9.3 million deposit, which is classified as restricted cash and is included in other assets on the condensed consolidated balance sheet. As of September 30, 2017, the available funds under our revolving credit facility were $700 million based on our elected commitment level.

Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain (i) a leverage ratio defined as total debt of less than 4.0 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled commodity derivatives, exploration expense, gains (losses) on sales of assets and other non-cash gains (losses) and (ii) an adjusted current ratio of at least 1.0:1.0. 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 commodity derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At September 30, 2017, we were in compliance with all debt covenants, as defined by the revolving credit agreement, with a leverage ratio of 1.8 and a current ratio of 2.9. We expect to remain in compliance throughout the next 12-month period.

The indentures governing our 2022 Senior Notes and 2024 Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including under our revolving credit facility, (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 September 30, 2017, we were in compliance with all covenants and expect to remain in compliance throughout the next 12-month period.

In January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Senior Notes, the 2022 Senior Notes, and the 2024 Senior Notes, our subsidiary PDC Permian, Inc. became a guarantor of the notes.

Cash Flows

Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative expenses. Cash flows from operating activities increased by $50.6 million to $411.4 million for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, primarily due to increases in crude oil, natural gas and NGLs sales of $308.0 million. These increases were offset in part by a decrease in commodity derivative settlements of $145.7 million and a decrease in changes in assets and liabilities of $30.8 million related to the timing of cash payments and increases in production taxes of $23.3 million, lease operating expenses of $22.2 million, interest expense of $15.6 million, transportation, gathering, and processing expenses of $8.6 million, and general and administrative expenses of $6.3 million.

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $81.3 million to $407.5 million during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016. 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 EBITDAX, a non-U.S. GAAP financial measure, increased by $184.3 million during the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016. The increase was primarily the result of increases in crude oil, natural gas and NGLs sales of $308.0 million, the recording of a provision for uncollectible notes receivable of $44.7 million during the nine months ended September 30, 2016, and the reversal of a provision for uncollectible notes receivable of $40.2 million during the nine months ended September 30, 2017. These increases were partially offset by a decrease in commodity derivative settlements of $145.7 million and increases in production taxes of $23.3 million, lease operating expenses of $22.2 million, transportation, gathering, and processing expenses of $8.6 million, and general and administrative expenses of $6.3 million. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of non-U.S. GAAP financial measures.

Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments.

Cash flows from investing activities primarily consist of the acquisition, exploration, and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $512.8 million during the nine months ended September 30, 2017, was primarily related to cash utilized for our drilling operations, including completion activities of $528.9 million, $21.0 million deposit toward the purchase price of the acquisition of certain

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properties owned by Bayswater and certain related parties, purchases of short-term investments of $49.9 million, and a $9.3 million deposit with a third-party transportation service provider for surety of an existing firm transportation obligation previously secured by a letter of credit. Partially offsetting these investments was the receipt of approximately $49.9 million related to the sale of short-term investments, $40.2 million from the sale of the Promissory Note, and $5.4 million related to post-closing settlements of properties acquired in 2016.

Financing Activities. Net cash from financing activities for the nine months ended September 30, 2017 decreased by approximately $1,291.1 million compared to the nine months ended September 30, 2016. Certain capital markets and financing activities occurred in 2016 including $855.1 million received from an issuance of our common stock, $392.3 million of proceeds from the issuance of the 2024 Senior Notes, and the $194.0 million of proceeds from the issuance of the 2021 Convertible Notes. These amounts were partially offset by the $115.0 million payment of principal amounts owed upon the maturity of the 2016 Convertible Notes and net payments of approximately $37.0 million to pay down amounts borrowed under our revolving credit facility in the first quarter of 2016.

Off-Balance Sheet Arrangements

At September 30, 2017, we had no off-balance sheet arrangements, as defined under SEC rules, which 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 investments, or capital resources.

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Commitments and Contingencies

See the footnote titled Commitments and Contingencies to the accompanying condensed consolidated financial statements included elsewhere in this report.

Recent Accounting Standards

See the footnote titled Summary of Significant Accounting Policies to the accompanying condensed consolidated financial statements included elsewhere in this report.

Recent Regulatory Developments

On May 2, 2017, in response to an incident in Firestone, Colorado, the Colorado Oil & Gas Conservation Commission (“COGCC”) issued a Notice to Operators (the “Notice”). Among other things, the Notice included requirements for all operators of oil and gas wells in Colorado to inspect all existing flowlines and pipelines located within 1,000 feet of a building unit; inspect any abandoned flowlines or pipelines, regardless of distance to ensure proper abandonment; and test integrity of all connected flowlines.

We timely complied with both phases of the Notice. We have an existing Flowline Integrity Management Program to inspect all Denver-Julesburg Basin wells and related pipelines on an annual basis, and will continue to engage in this process.

On August 22, 2017, the State announced its response to the incident, following a three month review of oil and gas operations. The policy initiatives proposed could come either through rulemaking or legislation.

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 condensed consolidated financial statements and accompanying notes contained in our 2016 Form 10-K filed with the SEC on February 28, 2017.

Reconciliation of Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDAX," 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. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic and geophysical expense in our reconciliation of adjusted EBITDAX calculation. In prior periods, we included adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments. We have elected to disclose Adjusted EBITDAX rather than Adjusted EBITDA in this report and other public disclosures because we believe it is more comparable to similar metrics presented by others in the industry. All prior periods have been conformed for comparability of this information. 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.

Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We

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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 generally been 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.

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

Adjusted EBITDAX. We define adjusted EBITDAX as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, exploration, geologic, and geophysical expense, depreciation, depletion and amortization expense, accretion of asset retirement obligations, and non-cash stock-based compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDAX 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 EBITDAX includes certain non-cash costs incurred by us and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDAX differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDAX 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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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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Adjusted cash flows from operations:
Net cash from operating activities	$	148.2		$	163.0		411.4			$	360.8
Changes in assets and liabilities	2.7			(40.4		)	(3.9		)	(34.6		)
Adjusted cash flows from operations	$	150.9		$	122.6		$	407.5		$	326.2

Adjusted net loss:
Net loss	$	(292.5	)	$	(23.3	)	$	(205.1	)	$	(190.3	)
(Gain) loss on commodity derivative instruments	52.2			(19.4		)	(86.5		)	62.3
Net settlements on commodity derivative instruments	9.6			47.7			22.2			167.9
Tax effect of above adjustments	(23.2		)	(10.8		)	24.0			(87.6		)
Adjusted net loss	$	(253.9	)	$	(5.8	)	$	(245.4	)	$	(47.7	)

Net loss to adjusted EBITDAX:
Net loss	$	(292.5	)	$	(23.3	)	$	(205.1	)	$	(190.3	)
(Gain) loss on commodity derivative instruments	52.2			(19.4		)	(86.5		)	62.3
Net settlements on commodity derivative instruments	9.6			47.7			22.2			167.9
Non-cash stock-based compensation	4.8			4.1			14.6			15.2
Interest expense, net	18.8			20.1			56.9			40.9
Income tax benefit	(122.4		)	(12.0		)	(71.5		)	(112.2		)
Impairment of properties and equipment	252.7			0.9			282.5			6.1
Impairment of goodwill	75.1			—			75.1			—
Exploration, geologic, and geophysical expense	41.9			0.2			43.9			0.7
Depreciation, depletion, and amortization	125.2			112.9			360.6			317.3
Accretion of asset retirement obligations	1.5			1.8			4.9			5.4
Adjusted EBITDAX	$	166.9		$	133.0		$	497.6		$	313.3

Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$	148.2		$	163.0		$	411.4		$	360.8
Interest expense, net	18.8			20.1			56.9			40.9
Amortization of debt discount and issuance costs	(3.2		)	(9.9		)	(9.6		)	(13.0		)
Gain on sale of properties and equipment	0.1			0.2			0.8			—
Exploration, geologic, and geophysical expense	41.9			0.2			43.9			0.7
Exploratory dry hole costs	(41.2		)	—			(41.2		)	—
Other	(0.4		)	(0.2		)	39.3			(41.5		)
Changes in assets and liabilities	2.7			(40.4		)	(3.9		)	(34.6		)
Adjusted EBITDAX	$	166.9		$	133.0		$	497.6		$	313.3

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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 2021 Convertible Notes, 2024 Senior Notes, and 2022 Senior Notes have fixed rates, and therefore near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.

As of September 30, 2017, 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 September 30, 2017 was $105.6 million with a weighted-average interest rate of 1.0 percent. Based on a sensitivity analysis of our interest-bearing deposits as of September 30, 2017 and assuming we had $105.6 million outstanding throughout the period, we estimate that a one percent increase in interest rates would have increased interest income for the nine months ended September 30, 2017 by approximately $0.8 million.

As of September 30, 2017, we had no outstanding balance on our revolving credit facility.

Commodity Price Risk

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

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The following table presents our commodity and basis derivative positions related to crude oil, natural gas, and propane in effect as of September 30, 2017:



	Collars					Fixed-Price Swaps
Commodity/ Index/ Maturity Period	Quantity (Gas - BBtu Oil - MBbls)	Weighted-Average Contract Price				Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls)	Weighted- Average Contract Price			Fair Value September 30, 2017 (1) (in millions)
Commodity/ Index/ Maturity Period	Quantity (Gas - BBtu Oil - MBbls)	Floors		Ceilings		Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls)	Weighted- Average Contract Price			Fair Value September 30, 2017 (1) (in millions)
Crude Oil
NYMEX
2017	616.0	$	49.54	$	62.32	1,837.1	$	50.13		$	(2.6	)
2018	1,512.0	41.85		54.31		7,972.0	52.11			(0.6		)
2019	—	—		—		2,400.0	50.25			(1.8		)
Total Crude Oil	2,128.0					12,209.1				$	(5.0	)

Natural Gas
NYMEX
2017	2,895.1	$	3.38	$	4.02	10,310.0	$	3.39		$	4.6
2018	5,230.0	3.00		3.54		51,280.0	2.95			(4.1		)
Total Natural Gas	8,125.1					61,590.0				$	0.5

Basis Protection
CIG
2017	—	—		—		13,264.2	$	(0.34	)	$	0.6
2018	—	—		—		30,200.0	(0.34		)	3.7
Waha
2018	—	—		—		6,000.0	(0.50		)	0.1
Total Basis Protection	—					49,464.2				$	4.4

Propane
Mont Belvieu
2017	—	—		—		411.9	$	27.22		$	(4.3	)
2018	—	—		—		428.6	29.14			(1.3		)
Total Propane						840.5				$	(5.6	)
Commodity Derivatives Fair Value										$	(5.7	)

____________


(1)	Approximately 10.8 percent of the fair value of our commodity derivative assets and 28.4 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

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PDC ENERGY, INC.

In addition to our commodity derivative positions as of September 30, 2017, we entered into the following commodity derivative positions subsequent to September 30, 2017 that are effective as of November 3, 2017:



	Fixed-Price Swaps
Commodity/ Index/ Maturity Period	Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls)	Weighted- Average Contract Price
Commodity/ Index/ Maturity Period	Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls)	Weighted- Average Contract Price
Crude Oil
NYMEX
2018	600.0	$	53.30
2019	600.0	$	51.43

Total Crude Oil	1,200.0

Basis Protection
CIG
2018	5,000.0	$	(0.51	)

El Paso
2018	3,000.0	$	(0.62	)

Total Basis Swaps	8,000.0

Rollfactor (1)
2018	3,648.0	$	0.03

(1)

These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month (the "trade month roll").

Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas, and NGLs production:



	Three Months Ended		Nine Months Ended		Year Ended
	September 30, 2017		September 30, 2017		December 31, 2016
Average NYMEX Index Price:
Crude oil (per Bbl)	$	48.20	$	49.47	$	43.32
Natural gas (per MMBtu)	3.00		3.17		2.46

Average Sales Price Realized:
Excluding net settlements on commodity derivatives
Crude oil (per Bbl)	$	45.66	$	46.69	$	39.96
Natural gas (per Mcf)	2.17		2.23		1.77
NGLs (per Bbl)	18.11		17.24		11.80

Based on a sensitivity analysis as of September 30, 2017, we estimate that a ten percent increase in natural gas, crude oil, and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives

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PDC ENERGY, INC.

in place, would have resulted in a decrease in the fair value of our derivative positions of $83.9 million, whereas a ten percent decrease in prices would have resulted in an increase in fair value of $83.7 million.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty fails to perform 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 counterparty’s 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 business'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 business are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions, and end-users in various industries. The underlying operations of these entities are geographically concentrated in the same region, which increases the credit risk associated with this business. As natural gas prices continue to remain depressed, certain third-party producers relating to our gas marketing business continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. We have initiated several legal actions for breach of contract, collection and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in two default judgments. We expect this trend to continue for this business.

We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, 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 commodity derivative financial instruments. See the footnote titled Commodity Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments.

Disclosure of Limitations

Because the information above included only those exposures that existed at September 30, 2017, 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of September 30, 2017, 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 September 30, 2017.

Changes in Internal Control over Financial Reporting

During the three months ended September 30, 2017, 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

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ITEM 1. LEGAL PROCEEDINGS

From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations, or liquidity.

Environmental

Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills 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. Except as discussed herein, we are not aware of any environmental claims existing as of September 30, 2017 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets.

Clean Air Act Tentative Agreement and Related Consent Decree

In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado ("DJ Basin"). The Information Request focused on historical operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016.

Action Regarding Firm Transportation Contracts

In June 2016, a group of 42 independent West Virginia natural gas producers filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. ("Dominion"), certain entities affiliated with Dominion, and our

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subsidiary RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. The case has been transferred to the Business Court Division of the Circuit Court of Marshall County, West Virginia, and the parties are awaiting that court's ruling on previously-filed pre-trial pleadings. RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses.

ITEM 1A. RISK FACTORS

We face many risks. Factors that could materially adversely affect our business, financial condition, operating results, or liquidity and the trading price of our common stock are described under Item 1A, Risk Factors, of our 2016 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

There have been no material changes from the risk factors previously disclosed in our 2016 Form 10-K.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers



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

July 1 - 31, 2017	1,360	$	42.68
August 1 - 31, 2017	—	—
September 1 - 30, 2017	12	39.58
Total third quarter 2017 purchases	1,372	$	42.65

__________


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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES - None.

ITEM 4. MINE SAFETY DISCLOSURES - Not applicable.

ITEM 5. OTHER INFORMATION - None.

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PDC ENERGY, INC.

ITEM 6. EXHIBITS

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

10.1

Sixth Amendment to the Third Amended and Restated Credit Agreement, dated as of October 6, 2017, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders.

31.1

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

31.2

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

32.1*

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

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

* Furnished herewith.

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PDC ENERGY, INC.

SIGNATURES

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



	PDC Energy, Inc.
	(Registrant)




Date: November 6, 2017	/s/ Barton R. Brookman
	Barton R. Brookman
	President and Chief Executive Officer
	(principal executive officer)

	/s/ David W. Honeyfield
	David W. Honeyfield
	Senior Vice President and Chief Financial Officer
	(principal financial officer)

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