10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2016

or

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

For the transition period from __________ to _________

Commission File Number 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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, par value $0.01 per share	NASDAQ Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T No £

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

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

The aggregate market value of our common stock held by non-affiliates on June 30, 2016 was $2.7 billion (based on the closing price of $57.61 per share as of the last business day of the fiscal quarter ending June 30, 2016).

As of February 15, 2017, there were 65,763,315 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Meeting of Stockholders.

PDC ENERGY, INC.

2016 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

	PART I	Page
Items 1. and 2.	Business and Properties	2
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	37
Item 3.	Legal Proceedings	37
Item 4.	Mine Safety Disclosures	37
	PART II
Item 5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	40
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	105
Item 9A.	Controls and Procedures	105
Item 9B.	Other Information	105
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	106
Item 11.	Executive Compensation	106
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	106
Item 13.	Certain Relationships and Related Transactions, and Director Independence	106
Item 14.	Principal Accounting Fees and Services	106
	PART IV
Item15.	Exhibits, Financial Statement Schedules	106
Item 16.	Form 10-K Summary	112
	Signatures	110
	Glossary of Units of Measurements and Industry Terms	111

PART I

REFERENCES TO THE REGISTRANT

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 remaining affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture owned 50 percent by PDC until its sale in October 2014. PDC is a Delaware corporation having reincorporated from Nevada in 2015.

GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS

Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical facts included in this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: reserves, production, costs, cash flows and earnings; drilling locations and growth opportunities; capital expenditures and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments.    

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 terms “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 the 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;

• 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 related to 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 further impairments;

• changes in estimates of proved reserves;

• inaccuracy of estimated reserves and 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 segment exceeding our expectations;

• difficulties in integrating our operations as a result of any significant acquisitions, including our recent acquisitions in the Delaware Basin;

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

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

• 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;

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• effect of crude oil and natural gas derivatives activities;

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

• cost of pending or future litigation;

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

• 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 Item 1A, Risk Factors, made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

The Company

We are a domestic independent exploration and production company that acquires, produces, develops, and explores for crude oil, natural gas, and NGLs. Our operations are located in the Wattenberg Field in Colorado; the Utica Shale in southeastern Ohio; and, with the closing of our $1.76 billion acquisitions of proved producing, proved undeveloped, and unproved leaseholds in December 2016, in the Delaware Basin in Texas (see "Business Strategy - Strategic acquisitions" below).

As of December 31, 2016, we own an interest in approximately 2,900 gross (2,400 net) productive wells, of which approximately 25 percent are horizontal. We operate 88 percent of the wells in which we have an interest. We produced 22.2 MMBoe in 2016, including 0.2 MMBoe contributed from the newly acquired Delaware Basin assets, representing an increase of 44 percent compared to 2015. For the month ended December 31, 2016, we maintained an average production rate of 73 MBoe per day. This exit rate represents a 42 percent increase from December 2015. We were able to achieve this strong growth rate while maintaining a robust liquidity position, comprised of cash and cash equivalents and available capacity under our revolving credit facility totaling $932.4 million as of December 31, 2016. Our debt to EBITDAX ratio as of December 31, 2016, as defined in our revolving credit facility agreement, was 2.10 to 1.00, well within our compliance limit of 4.00 to 1.00. As of December 31, 2016, we had 341.4 MMBoe of proved reserves, 29 percent of which are proved developed, including 32.5 MMBoe related to acquisitions of properties in the Delaware Basin. Approximately 59 percent of our reserves at December 31, 2016 are liquids, which includes crude oil and NGLs. Our 341.4 MMBoe of total proved reserves as of December 31, 2016, represented an increase of 68.6 MMBoe, or 25 percent, relative to December 31, 2015. Our proved reserve additions were primarily a result of: 1) the development of longer lateral length well bores with higher working interests in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position, and 2) the acquisitions of properties in the Delaware Basin.

Our Strengths

• Multi-year project inventory in premier crude oil, natural gas, and NGLs plays. We have a significant operational presence in two premier U.S. onshore basins providing us with approximately 2,600 potential horizontal drilling locations from our total proved and unproved leasehold. The primary focus for development is currently in the Wattenberg Field and the Delaware Basin. We believe that our inventory of drilling locations, the majority of which reflect 4,000 to 10,000 foot horizontal laterals, will allow us to continue to grow our proved reserves and production at attractive rates of return utilizing our current internal long-term commodity price projections and our current expected cost structure. Our 2017 drilling and completion operations are expected to specifically focus on the middle core of the Wattenberg Field and our newly acquired Delaware Basin assets. In the Wattenberg Field, we have identified a substantial inventory consisting of approximately 700 proved undeveloped horizontal drilling locations and an additional approximately 1,100 probable horizontal drilling locations. Through our acquisitions in the Delaware Basin, we added approximately 20 proved undeveloped horizontal drilling locations, which were included in the 785 gross potential drilling locations that were identified on our 62,500net acres of leasehold. At the time of the initial acquisition, our undeveloped location count was based on wells expected to be drilled with horizontal lateral lengths ranging from 4,000 to 10,000 horizontal feet. We believe that with additional development and exploration activity, together with advances in technology, we may be able to access additional productive zones in the Delaware Basin, which could significantly increase our inventory of undeveloped locations.

• Strong liquidity position. As of December 31, 2016, we had a total liquidity position of $932.4 million, comprised of $244.1 million of cash and cash equivalents and $688.3 million available for borrowing under our revolving credit facility. During 2016, we raised in excess of $1.4 billion of new capital, net of issuance costs.

• In March 2016, we raised $296.6 million, net of issuance costs, from the sale of 5.9 million shares of common stock.

• In September 2016, we issued 9.1 million shares of common stock for net proceeds of $558.5 million, $400.0 million of 6.125% senior unsecured notes due in 2024 ("2024 Senior Notes") for net proceeds of $392.2 million, and $200.0 million of 1.125% convertible senior notes due in 2021 for net proceeds of $193.9 million.

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• We also issued 9.4 million shares of common stock valued at $690.7 million in December 2016 as partial consideration to the sellers for the initial Delaware Basin acquisition.

• In December 2016, we increased the aggregate commitment under our revolving credit facility to $700 million.         

We intend to continue to manage our liquidity position through 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 program, and access to capital markets from time to time.

• Balanced and diversified portfolio across two premier U.S. onshore basins. We believe we have multiple years of attractive drilling opportunities in both the Wattenberg Field and the Delaware Basin. The completion of the acquisitions of Delaware Basin properties provides us the ability to allocate capital between the two basins to diversify our risk. We expect that this will improve overall economic results and drive our future production and reserve growth. We believe that we will be able to transfer much of our management expertise gained over the years in the Wattenberg Field to the newly acquired Delaware Basin assets. The successful development and exploitation of the acquired leasehold in the Delaware Basin will include execution of our asset integration plan, which consists of transferring our technological expertise to the Delaware Basin, beginning down spacing initiatives, testing various completion designs, successfully developing multiple benches, maintaining an intense focus on cost structure, and utilizing existing personnel and retaining experienced staff. Additionally, we expect the increased geographical diversity of our portfolio to mitigate risks associated with a single dominant producing area, as each basin will have its own operating and competitive dynamic in terms of commodity price markets, service cost areas, takeaway capacity, and regulatory and political considerations.

• Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately 88 percent of all wells in which we have an interest across all of our operating basins. Our control allows us to manage our drilling, production, operating and administrative costs, and to leverage our technical expertise in our core operating areas. Our leaseholds that are held-by-production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria.

In the Wattenberg Field, our operational control is attributable to our high working interest leasehold and large contiguous acreage blocks, which have been enhanced as a result of a 2016 acreage trade, and because substantially all of our Wattenberg Field acreage is held-by-production. We remain flexible in terms of rig activity and capital deployment due to short-term rig contracts and we are confident in our ability to manage held-by-production acreage in the Wattenberg Field in order to maintain our current level of operational control. As a result, we can adjust our drilling plans if commodity prices deteriorate in order to manage cash flows from operations relative to cash flows from investing activities.

In the Delaware Basin, our average working interest in our properties is approximately 92 percent and we operate nearly 100 percent of those properties. Additionally, we own and operate certain midstream assets in the Delaware Basin and believe this will allow for timely system expansion, well connections, water supply for completion operations, and water disposal. Approximately 30 percent of the properties acquired in the Delaware Basin were held-by-production as of December 31, 2016. The leaseholds in the Delaware Basin require a more active drilling program than in the Wattenberg Field, and in certain cases, continuous operations to maintain the underlying leaseholds. With our high percentage of operated leaseholds in the Delaware Basin, we expect to have adequate control over the location and pace of our development to manage lease expiration issues. While we believe that our current Delaware Basin drilling plan should meet these obligations for the next few years, in the event that we do not meet the obligations for certain leases, we anticipate that we will make any necessary bonus extension payments, or we will seek to renew or, re-lease in order to retain the leases. However, the payments required to do so may be significant and we may not be successful in such efforts.

• Utilizing technology to focus on efficiency. In the Wattenberg Field, we have a proven track record of continuing improvement in both costs and productivity of our existing well operations. Our efficiencies are driven by a focus on the use of multi-well pad drilling, extended reach lateral well development, increased fracture stimulation stage density, enhanced fracture stimulation completion design, and improved drilling efficiencies. In 2016, approximately 65 percent of our Wattenberg Field horizontal well spuds were mid- or extended-reach laterals that ranged from approximately 7,000 to 9,500 horizontal feet in length. We have implemented plug-and-perforation completion techniques on all new wells, and increased the number of completion stages to provide a potential uplift to our new well production. We also began using a mono-bore drilling design to reduce drill times and well costs. Through the combination of these techniques, our drilling team has improved our drilling efficiencies with average drill results increasing to approximately 2,200 feet drilled per day in 2016 from approximately 1,800 feet drilled per day in 2015. We believe that we can generate substantial value by leveraging and applying our operating experience in the Wattenberg Field and the Utica Shale to our Delaware Basin properties.

• Commodity derivative program. Our active use of commodity derivative instruments to protect our investment returns and cash flows was particularly important through the severe commodity price downturn in 2015 and 2016. We have continued this program and have entered into commodity derivative instruments to mitigate a portion of our short-term future exposure to commodity price fluctuations, including crude oil and natural gas collars, fixed-price swaps, and basis swaps. While our commodity derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect a portion of our cash flows, borrowing base, and liquidity during periods of depressed commodity prices. We strive to scale our

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overall hedging position to be appropriate relative to our current and expected level of indebtedness and consistent with our goals of preserving balance sheet strength and substantial liquidity, as well as our internal price view. In 2016 and 2015, net settled derivatives contributed a significant portion of our cash flows from operating activities, thereby mitigating the effect of the depressed commodity prices. Based upon our hedge position at forward strip pricing at year-end 2016, our derivatives are now in a net liability position of $70.0 million. Therefore, because of the normal settlement of our higher value derivatives that occurred in 2015 and 2016, and because our remaining unsettled derivative contracts have future settlement prices closer to the current forward price curve, the settlement of these instruments are not expected to be a significant source of cash flow, and may result in cash outflows in 2017 and 2018.

As of December 31, 2016, we had commodity derivatives positions covering approximately 8.5 MMBbls and 4.9 MMBbls of crude oil production for 2017 and 2018, respectively. As of the same date, we had hedged approximately 35.2 Bcf and 46.5 Bcf of natural gas production for 2017 and 2018, respectively.  The details of these transactions are described in the footnotes to our consolidated financial statements included elsewhere in this report. We do not currently have any commodity derivatives for any of our NGL production.

• Strong environmental, health and safety compliance programs, and community outreach. We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies, and public officials. We believe this is an important part of our strategy in competing in today’s intensive regulatory and public debate climate. We are also dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships.

• Strong management team and operational capabilities. We have strong and stable management, led by our executive management team. Each member of the team has between 10 and 30 years of experience in the energy and natural resource industry. This experience collectively spans expertise in land, reservoir analysis, operations, accounting, finance, strategy, and general operations, and has helped us continue our growth through periods of commodity price pressure, cost inflation, and challenging operating environments.

Business Strategy

Our long-term business strategy focuses on generating stockholder value through the acquisition, exploration, and development of crude oil and natural gas properties. We are focused on the growth of our reserves, production, and cash flows through organic exploration and development of our existing and acquired leasehold in our horizontal drilling programs. Our operational focus is concentrated with a substantial presence in two basins. We pursue various midstream, marketing, and cost reduction initiatives designed to increase our per unit operating margins while maintaining a disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy.

We focus on horizontal development drilling programs in resource plays that offer repeatable results and the potential for attractive returns on investment in a range of commodity price environments. Our inventory of drilling locations supports our planned organic growth over the next several years. We expect our drilling and completion activity to drive increases in proved reserves, production, and cash flows. In addition to development drilling, we routinely review acquisition and acreage swap opportunities in our core areas of operations. We believe we can extract additional value from such transactions through production optimization opportunities and increases in our working interests in our development drilling locations afforded by more concentrated acreage positions. As a result, once we have established a significant presence in an area, the use of bolt-on acquisitions and acreage trades can potentially provide synergies that result in additional economies of scale. We also pursue a limited and disciplined exploration program with the goal of replenishing our portfolio with new exploration projects capable of positioning us for significant production and reserve growth in future years.

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Development drilling

The following map presents the general locations of our development and production activities as of December 31, 2016:

Our leasehold interests covers properties with developed and undeveloped crude oil, natural gas, and NGLs resources. We own approximately 2,900 gross (2,400 net) wells in our three operating basins. Our previously-announced 2017 capital investment program contemplates expenditures of between $725 million and $775 million. Due to recent cost escalation for services in our core areas and the modification of our drilling schedule in the Delaware Basin, where we have accelerated the deployment of an additional drilling rig, we currently expect that our 2017 capital investment will be at or near the high end of the range. These changes to our capital investment outlook are not expected to impact our 2017 production estimate, as the incremental well drills are contemplated to be turned-in-line to sales late in the year.

We have allocated substantially all of our 2017 capital investment program to our higher-return projects in the Wattenberg Field and Delaware Basin, and have elected to defer drilling operations in the Utica Shale. Based on our current production and commodity price outlook for 2017, we continue to expect capital investments to exceed cash flows from operations by approximately $200 million. Our debt to EBITDAX ratio, as defined in our revolving credit facility agreement, is expected to decrease in 2017 based on production and operational cash flow growth. A deterioration of commodity prices could negatively impact our results of operations, financial condition, and future development plans. We may increase or decrease our 2017 capital investment program during the year as a result of, among other things, changes in commodity prices or our current internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. If such changes result in our election to deploy additional capital investment, amounts may further exceed our cash flow from operations.

Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays. Based on our current drilling program, we have an inventory of 700 gross proved undeveloped horizontal drilling locations and approximately 1,100 gross probable horizontal drilling locations. These locations are in the core Wattenberg Field, which is further delineated between the inner, middle, and outer core. In 2017, we expect to continue to realize additional capital efficiencies through drilling extended length laterals, an increased number of fracturing stages, plug-and-perforation completions, enhanced well orientation, and mono-bore drilling. We plan to drill standard reach lateral (“SRL”), mid-length lateral (“MRL”), and extended reach lateral (“XRL”) wells in 2017, the majority of which will be in the middle core area of the field. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface. In 2017, to help balance our priorities, we now anticipate spudding 137 operated wells and turning-in-line to sales, approximately 139 horizontal operated wells as outlined below.

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	SRL	MRL	XRL
Estimated average lateral length (in feet)	4,200	6,900	9,500
Expected drilling days (spud-to-spud)	7	10	12
Estimated percentage of 2017 wells spud	31%	33%	36%
Estimated percentage of 2017 wells turned-in-line	35%	30%	35%
Estimated cost per well (in millions)	$2.5	$3.5	$4.5

The 2017 capital investment outlook is now approximately $470 million in the Wattenberg Field and anticipates a three to four-rig drilling program based on our current commodity price outlook. Approximately $460 million of our 2017 capital investment program is expected to be invested in development activities in the Wattenberg Field, comprised of approximately $440 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder of the Wattenberg Field capital investment program is expected to be used for miscellaneous workover and capital projects.

Delaware Basin. In December 2016, we closed a series of acquisitions providing us a total of approximately 62,500 net acres in Reeves and Culberson Counties, Texas (see “Business Strategy-Strategic acquisitions” below).  In 2017, our investment outlook now contemplates operating a two-rig to four-rig program at various times throughout the year and deploying the third rig in late Februay 2017. Total capital investment in the Delaware Basin is estimated to be $300 million, of which approximately $235 million is allocated to spud 31 wells and turn-in-line an estimated 26 wells.  Based on the timing of our operations and the requirements to hold acreage, we may adapt our capital investment program to drill wells in addition to those currently anticipated, as we are continuing to analyze the terms of the leaseholds related to our recent acquisitions of properties in the basin. We plan to drill 20 wells in our eastern acreage block, nine wells in our central acreage block, and two wells in our western acreage block, with the majority of wells targeting the Wolfcamp A and B zones. Of the 26 planned turn-in-lines, 14 are expected to have laterals of approximately 10,000 horizontal feet with completion stages currently expected to range from approximately 100 to 125 feet. Similarly spaced completions are anticipated for the remaining 12 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at depths of approximately 9,000 to 11,000 feet below the surface. Estimated well costs for SRL, MRL, and XRL wells are approximately $7.1 million, $8.8 million and $10.5 million, respectively. We plan to invest approximately $35 million for leasing, seismic, and technical studies with an additional $30 million for midstream related projects including gas connections, salt water disposal wells, and surface location infrastructure.

Utica Shale.  At this time, we are currently evaluating all of our strategic alternatives with respect to our Utica Shale position. As a result of such evaluation, we are deferring our 2017 planned expenditure of $18 million to drill, complete, and turn-in-line two wells in Guernsey County.  In 2017, our capital investment program for the Utica Shale is expected to include between $2 million to $3 million for additional leasing. Such leasing may be necessary to complete certain drilling operations if we decide to continue development of our existing position in the northern portion of our acreage.

Strategic acquisitions

As part of our overall growth strategy, we examine and evaluate acquisition opportunities as they present themselves and pursue those that meet our strategic plan and that we believe will increase stockholder value. We seek properties with large undeveloped drilling upside where we believe we can utilize our operational expertise to grow production and proved reserves. In addition, we may pursue opportunities to trade acreage with other producers or complete small bolt-on acquisitions in order to optimize our portfolio by consolidating and concentrating our core assets. The creation of large, contiguous acreage blocks through the trading of properties or bolt-on acquisitions provides the opportunity to optimize drilling activities and add more extended-reach lateral wells to our drilling program, while increasing our working interests in the related wells. We have an experienced team of management, engineering, geosciences, and commercial professionals who identify and evaluate acquisition opportunities. Our acquisition activity in 2017 is expected to be focused on our two most significant assets, the Wattenberg Field and Delaware Basin.

Delaware Basin. We recently engaged in the process of searching for and evaluating a large-scale acquisition in a new U.S. onshore basin capable of creating material long-term value-added growth, focusing on four key criteria: top-tier acreage in core geologic positions, significant drilling inventory with additional expansion through down spacing, portfolio optionality for capital allocation and diversification, and the ability to deliver long-term increases in net asset value per share. Having determined that they met these criteria, in December 2016, we closed the purchases of an aggregate of approximately 62,500 net acres, in Reeves and Culberson Counties, Texas, through two transactions, for an aggregate consideration to the sellers of approximately $1.76 billion.

• The first transaction consisted of the acquisition of certain producing properties and approximately 57,900 acres for approximately $952.1 million in cash and the issuance of 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed, for total consideration of approximately $1.64 billion.

• The second transaction occurred shortly thereafter and included certain developed assets and 4,600 net acres of undeveloped leasehold that is complementary to the initial transaction. This transaction was paid for in cash of $120.6 million.

The the purchase prices for the acquisitions remain subject to certain post-closing adjustments as of the date of this report. We expect that it may take into mid-2017 until all post-closing adjustments are settled. See footnotes titled Properties and Equipment - Delaware

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Basin Acreage Acquisition and Business Combination to our consolidated financial statements included elsewhere in this reportfor further information regarding these two acquisitions.

Selective exploration

Historically, we have pursued a disciplined exploration program intended to replenish our portfolio and to position us for production and reserve growth in future years. When doing so, we attempt to identify potential plays in their early stages in order to accumulate significant leasehold positions prior to competitive forces driving up the cost of entry and to invest in leasehold positions that are near existing or emerging midstream infrastructure. Our contemplated near-term exploration activity will be occurring in the Delaware Basin as there are multiple zones that have not seen development activity sufficient to record proved reserves. Such zones could provide additional potential drilling locations and/or proved reserves.

Business Segments

We divide our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing.

Oil and Gas Exploration and Production

The results of our Oil and Gas Exploration and Production segment primarily reflect revenues and expenses from the production and sale of crude oil, natural gas, and NGLs, commodity price risk management, and well operations. The exploration for and production of crude oil, natural gas, and NGLs involves the acquisition or leasing of mineral rights and related surface rights. Prior to development of these properties, we assess the economic viability of potential well development opportunities. We then develop the reserves through the permitting, drilling and completion of oil and gas wells, which are then turned-in-line to sales and production. Following completion, we operate and maintain the producing wells while managing associated production, operating, and transportation costs. At the end of a well's economic life, the well is plugged and surface disturbances surrounding the well and producing facilities are remediated. The Oil and Gas Exploration and Production segment's most significant customers are Suncor Energy Marketing, Inc., DCP Midstream, LP ("DCP"), Aka Energy Group, LLC ("Aka"), Concord Energy, LLC, and Bridger Energy, LLC. Sales to each of these parties constitute more than 10 percent of our revenues in 2016. We believe that the loss of any purchaser or the aggregate loss of several customers could be managed by selling to alternative purchasers given the liquidity in the market for the sale of hydrocarbons.

Within the Oil and Gas Exploration and Production Segment, our crude oil, natural gas, and NGLs production is gathered, marketed and sold as follows:

• Crude oil. In the Wattenberg Field, our crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on New York Mercantile Exchange ("NYMEX") pricing, adjusted for differentials. Since we do not refine any of our crude oil production, we sell to companies that either transport or resell the commodity, or process the crude oil in their own facilities. Title to the crude oil transfers at the time the crude oil leaves our lease site and is either placed in a truck or enters a pipeline. We have entered into commitments ranging in term from one month to over three years to deliver crude oil to competitive markets, resulting in improved average overall deductions of $4.39 for 2016 compared to $9.95 for 2015. During 2016, there was sufficient take away capacity in the Wattenberg Field for crude oil. This was a function of decreases in drilling activity and corresponding decreases in production from other producers, and the completion of additional crude oil pipelines to the Cushing, Oklahoma market. We believe that there will continue to be adequate take away capacity for crude oil through either pipeline or trucking options in the Wattenberg Field in the near- and mid-term. We continue to pursue various alternatives with respect to crude oil transportation, with a view toward further improving pricing and increasing the amount of crude oil transported by pipeline and limiting our use of trucking. For example, in mid-2015, we began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline. Our volume of crude oil sales going through the White Cliffs pipeline in 2016 was 16 percent of our Wattenberg Field crude oil production compared to 23 percent during the second half of 2015. By having a variety of off-take arrangements, we seek to optimize our marketing to result in the best possible net realized price per barrel. The White Cliffs agreement is one of several we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition to the White Cliffs agreement, we have signed a long-term agreement with Saddle Butte Rockies Midstream, LLC for gathering of crude oil at the wellhead by pipeline from several of our producing pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability, reducing the overall physical footprint of our well pads, and reducing emissions. We began delivering crude oil into this pipeline during the fourth quarter of 2015. The system became fully operational in 2016 and we did not experience any subsequent curtailment of operations due to lack of takeaway capacity for crude oil in the basin. We do not expect to experience any curtailments in 2017.

In the Delaware Basin, our crude oil production is sold at the wellhead and transported via trucks to pipelines that deliver the oil to the Midland, Texas, crude oil market. Given the increased level of activity in the form of acquisitions, leasing, and the increases in rig count in the Delaware Basin over the last six months, we expect the balance between production and pipeline takeaway capacity to tighten during 2017. At the current time, there are pipeline, truck and rail pathways out of the basin, all of which are available to us. We are evaluating near-term and longer-term solutions that contemplate the increased activity levels we expect, as well as our anticipated future production. These may include longer-term sales agreements.

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In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities, or barge loading terminals on the Ohio River. To date, we have not experienced any significant issues with take away capacity in this region for our crude oil.

• Natural gas. We sell substantially all of our natural gas to midstream service providers and marketers. We have entered into firm gathering and processing agreements for all of our natural gas production in the Wattenberg Field to ensure there is infrastructure available to process the gas and deliver our product to market. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP, which gathers and processes natural gas produced in the basin and sells our residue gas to various markets. We also sell natural gas into a system owned and operated by Aka, and have committed production from dedicated acreage and a drilling program with a specific number of wells to be drilled and completed by the end of 2017. Pursuant to the agreement, Aka is required to install and operate, or contract for the use of, facilities necessary to receive and purchase the production volumes committed under the agreement.

     In the Wattenberg Field, title to the natural gas transfers at the custody transfer meter located at our wellheads, except when we have multiple wells being gathering to a common pad, in which case the natural gas is sold as it passes through the custody transfer meter located on our well pads after water and crude oil have been separated from the natural gas stream. Our Wattenberg Field natural gas is transported through third-party gathering systems and pipelines where we incur gathering, processing, and transportation expenses via percent-of-proceeds ("POP") contracts whereby the gatherer/processor markets the natural gas and NGLs on a best efforts basis and then retains a portion of the revenue attributable to the residue gas and NGL sales. Substantially all of the natural gas that we produce in the Wattenberg Field is sold by the midstream service providers and is priced based on Colorado Interstate Gas ("CIG") or local distribution company monthly/daily pricing provisions. There have been periods in the past where transportation of natural gas was a significant issue, however, such has not been the case recently based on pipeline and development activity by midstream providers, as well as relatively decreased activity levels by other operators in the other areas of the Wattenberg Field. We anticipate gathering system pressures to vary throughout the year, with increases coinciding with the warmer summer months.  We plan for these increases and work with our mid-stream providers to manage production during these times. There was a new processing plant built in the portion of the Wattenberg Field in mid-2015 that provided significant relief and when coupled with the overall decrease in activity in the field near our operations, we did not experience any curtailments in 2016. We recently signed a contract to support a midstream provider's construction of an additional processing plant in the area. This midstream provider expects the plant to be placed into service towards the end of 2018. If the midstream provider is delayed in its expansion efforts, we could experience higher line pressures which could impact our production volumes. In 2016, approximately 90 percent of our production in the Wattenberg Field was delivered from horizontal wells, with the remaining 10 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 from periodic gas system pressure issues. Based on the expected activity levels and production in the region coupled with the current and committed construction activities in the area, we anticipate that we will have adequate takeaway capacity in the region for the next few years.

In the Delaware Basin, title to the natural gas transfers at the delivery point off of our gathering systems. In certain cases, we are paid the total value of the natural gas and the value of the NGLs processed by the purchasers, and we pay specific processing costs or fees. In other cases, we incur gathering, processing, and transportation expenses via POP contracts whereby the gatherer/processor retains a portion of the revenue attributable to the residue gas and NGL sales. Our Delaware Basin midstream service providers sell the residue gas at prices based on indexed prices per MMBtu using either the Waha or El Paso Permian monthly and daily price provisions. These index prices are established monthly and daily in the gas trading market, and represent the value of the natural gas delivered to the NYMEX Henry Hub delivery point, net of the transportation and margin embedded in the basis differential.

In the Utica Shale, natural gas produced in our northern acreage is gathered and processed pursuant to a firm gathering and processing agreement with MarkWest Utica EMG ("MarkWest") under a fee based contract, while natural gas produced in our southern acreage is gathered and processed by Blue Racer Midstream LLC ("Blue Racer"), also under a fee based contract. As a result, we receive the full revenue stream attributable to the residue gas and NGL sales, less the applicable gathering and processing fees. The natural gas sales from both the Blue Racer plant and the MarkWest plant are based on TETCO M-2 index pricing per MMbtu delivered to the plant. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas, which make economics challenging, will continue to be highly volatile into 2017.

• NGLs. Our NGL sales are priced based upon the components of the product and are correlated to the price of crude oil. In the Wattenberg Field, all of our NGLs are sold by the midstream service provider at the tailgate of the processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where the NGLs are marketed.

As noted above, the value of the NGLs extracted from the natural gas by our midstream providers in the Delaware Basin is based on processing contracts. Based on the percentage of NGLs in the natural gas stream, we receive the net proceeds of the NGLs processed by the midstream providers as sold into the Mt. Belvieu market.

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In the Utica Shale, our NGLs are fractionated and marketed by MarkWest and Blue Racer and sold based on month-to-month pricing in various markets. Our NGL production is sold by our midstream service providers under both short- and long-term contracts.

Gas Marketing

Our Gas Marketing segment is comprised solely of the operating activities of our wholly-owned subsidiary Riley Natural Gas ("RNG"). RNG specializes in the purchase, aggregation, and sale of natural gas production in the Appalachian Basin. The natural gas is marketed to third-party marketers, natural gas utilities, and industrial and commercial customers through transportation services provided by regulated interstate/intrastate pipeline companies. RNG is party to long-term firm transportation, sales, and processing agreements for pipeline capacity through August 2022. RNG acquired these firm transportation rights and associated agreements at a time when PDC owned operating interests in oil and natural gas wells through a joint venture in the Appalachian Basin referred to as PDCM. Although PDC sold its interest in PDCM in 2014, RNG retained the majority of its firm natural gas transportation commitment. Financial results from our gas marketing segment have resulted in an operating loss contribution of $1.5 million, $0.8 million, and $0.4 million, for 2016, 2015, and 2014, respectively. As of December 31, 2016, the amount owed for this long-term firm transportation, sales and processing agreement was approximately $19.1 million. This long-term pipeline capacity commitment was made on behalf of our third-party producers, and also includes an unutilized portion; however, we remain obligated to fulfill this commitment regardless of whether or not our third-party producers meet their commitments. As natural gas prices remain depressed, certain third-party producers under our Gas Marketing segment have continued to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, no counterparty default losses have been material to us. As of December 31, 2016, we recorded an allowance for doubtful accounts of approximately $1.3 million associated with such activity. We have initiated several legal actions for breach of contract, collection, and related claims against certain third-party producers, which have to date resulted in two default judgments. We expect RNG's expenses to exceed its revenues by approximately $1 million to $2 million per year through 2022, assuming a continuation of current economic conditions. After the long-term firm transportation agreements expire, we expect to discontinue this segment.

For additional information regarding our business segments, see the footnote titled Business Segments to our consolidated financial statements included elsewhere in this report.

Properties

Productive Wells

The following table presents our productive wells:

	Productive Wells
	As of December 31, 2016
	Crude Oil		Natural Gas		Total
Operating Region/Area	Gross	Net	Gross	Net	Gross	Net
Wattenberg Field	669	436.8	2,193	1,908.0	2,862	2,344.8
Delaware Basin	33	31.5	—	—	33	31.5
Utica Shale	27	22.2	3	3.0	30	25.2
Total productive wells	729	490.5	2,196	1,911.0	2,925	2,401.5

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Proved Reserves

The following table presents our proved reserve estimates as of December 31, 2016, based on reserve reports prepared by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. ("Ryder Scott"), and Netherland, Sewell & Associates, Inc. ("NSAI"), and related information:

	Proved Reserves at December 31, 2016
	Proved Reserves (MMBoe)	% of Total Proved Reserves		% Proved Developed		% Liquids		Proved Reserves to Production Ratio (in years)(1)	2016 Production (MBoe)
Wattenberg Field	305.3	89	%	29	%	58	%	14.6	20,945
Delaware Basin	32.5	10	%	22	%	68	%	15.2	178
Utica Shale	3.6	1	%	100	%	56	%	3.4	1,053
Total proved reserves	341.4	100	%	29	%	59	%	16.2	22,176

(1) As the Delaware Basin properties were purchased in December 2016, we annualized the calculation for the Delaware Basin ratio -

based on December production.

Our proved reserves are sensitive to future crude oil, natural gas, and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in recognition of more economically viable proved undeveloped reserves, while decreases in commodity prices may result in negative impacts of this nature.

All of our proved reserves are located onshore in the U.S. Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. As of December 31, 2016, our proved reserves, including our proportionate share of our affiliated partnerships' reserves, in the Wattenberg Field and Utica Shale have been estimated by Ryder Scott and our reserves in the Delaware Basin were estimated by NSAI. Both Ryder Scott and NSAI are independent professional engineering firms.

We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land and accounting personnel for adherence to SEC guidelines through a detailed review of land and account records, available geological and reservoir data, and production performance data. The process includes a review of applicable historical costing, working and net revenue interests, and performance data. The internal team compiles the reviewed data and forwards the data to Ryder Scott and NSAI.

When preparing our reserve estimates, neither Ryder Scott nor NSAI independently verifies the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties, and sales of production. Ryder Scott and NSAI prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve reports are those as prepared by Ryder Scott and NSAI and are reviewed by our engineering staff and management prior to issuance by the independent professional reserve engineering firms.

The professional qualifications of our internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 40 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and is a registered Professional Engineer in the State of Colorado.

The SEC's reserve rules allow the use of techniques that have been proved effective by evaluation of actual production from projects in the same reservoir or an analogous reservoir or by other observational evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. We used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies, and seismic data and interpretation to calculate our reserve estimates. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of each location’s initial booking date. The SEC has also established that pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted by the required adjustments related to energy content, location and basis differentials, and other marketing deductions to arrive at the net realized price. The SEC NYMEX prices used in the preparation of reserves are as follows:

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	As of December 31,
	2016		2015		2014
Crude oil (SEC NYMEX - $/Bbl)	$	42.75	$	50.28	$	94.99
Natural gas (SEC NYMEX - $/MMBtu)	$	2.48	$	2.59	$	4.35

Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data, and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the Supplemental Information Unaudited - Crude Oil and Natural Gas Information - Unaudited provided with our consolidated financial statements included elsewhere in this report. The following tables provide information regarding our estimated proved reserves:

	As of December 31,
	2016		2015		2014
Proved reserves
Crude oil and condensate (MMBbls)	118		99		101
Natural gas (Bcf)	834		661		537
NGLs (MMBbls)	84		64		60
Total proved reserves (MMBoe)	341		273		250
Proved developed reserves (MMBoe)	98		70		75
Estimated undiscounted future net cash flows (in millions) (1)	$	2,681	$	2,259	$	4,938
Standardized measure (in millions)	$	1,421	$	1,097	$	2,306
PV-10 (in millions) (2)	$	1,675	$	1,338	$	3,450

___________

(1) Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI of approximately $3.3 billion, $2.8 billion, and $7.3 billion as of December 31, 2016, 2015, and 2014, respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.6 billion, $0.5 billion, and $2.3 billion, respectively.

(2) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure.

The following table presents our estimated proved developed and undeveloped reserves by category and area:

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	As of December 31, 2016
Operating Region/Area	Crude Oil and Condensate (MMBbls)	Natural Gas (Bcf)	NGLs (MMBbls)	Crude Oil Equivalent (MMBoe)	Percent
Proved developed
Wattenberg Field	25.5	240.6	21.7	87.4	26	%
Delaware Basin	3.4	13.9	1.6	7.2	2	%
Utica Shale	1.1	9.9	0.9	3.6	1	%
Total proved developed	30.0	264.4	24.2	98.2	29	%
Proved undeveloped
Wattenberg Field	76.6	520.6	54.5	217.9	64	%
Delaware Basin	11.6	48.7	5.6	25.3	7	%
Utica Shale	—	—	—	—	—	%
Total proved undeveloped	88.2	569.3	60.1	243.2	71	%
Total proved reserves
Wattenberg Field	102.1	761.2	76.2	305.3	89	%
Delaware Basin	15.0	62.6	7.2	32.5	10	%
Utica Shale	1.1	9.9	0.9	3.6	1	%
Total proved reserves	118.2	833.7	84.3	341.4	100	%

We are showing two different alternative price scenarios for crude oil as its value currently influences our proved reserves and PV-10 value most significantly. We have performed a sensitivity analysis of our proved reserve estimates as of December 31, 2016, to present sensitivities associated with both lower and higher crude oil prices. Replacing the 2016 NYMEX commodity prices used in estimating our reported proved reserves with those shown on the table below, and leaving all other parameters unchanged, results in a changes to our estimated proved reserves as shown below.

	Pricing Scenario - NYMEX
	Crude Oil (per Bbl) (1)		Natural Gas (per MMBtu) (1)		Proved Reserves (MMBoe)	% Change from December 31, 2016 Estimated Reserves		PV-10 (in Millions)		PV-10 % Change from December 31, 2016 Estimate Reserves
2016 SEC Reserve Report	$	42.75	$	2.48	341.4	—		$	1,675.0	—
Alternate Price Scenarios:
Lower Price Scenario	$	30.00	$	2.48	326.5	(4	)%	$	705.7	(58	)%
Higher Price Scenario	$	50.00	$	2.48	345.7	1	%	$	2,247.0	34	%

__________

(1) These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently across each pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.

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Developed and Undeveloped Acreage

The following table presents our developed and undeveloped lease acreage:

	As of December 31, 2016
	Developed		Undeveloped		Total
Operating Region/Area	Gross	Net	Gross	Net	Gross	Net
Wattenberg Field	96,700	89,200	7,700	6,300	104,400	95,500
Delaware Basin	19,586	18,664	49,645	43,837	69,231	62,501
Utica Shale	5,454	4,291	61,862	58,162	67,316	62,453
Total acreage	121,740	112,155	119,207	108,299	240,947	220,454

Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held-by-production. In the Wattenberg Field, approximately 1 percent, 2 percent, and 1 percent of our undeveloped leaseholds are scheduled to expire during 2017, 2018 and 2019, respectively. In the Delaware Basin, there are drilling obligations or continuous drilling clauses associated with the majority of our acreage. While we believe that our current Delaware Basin drilling plan should provide sufficient drilling to meet these obligations for the next few years, in the event that we do not meet the obligations for certain leases, we anticipate that we will make any necessary bonus extension payments, or we will seek to renew or, re-lease in order to retain the leases. However, the payments required to do so may be significant and we may not be successful in such efforts. In the Utica Shale, approximately 30 percent, 7 percent, and 11 percent of our undeveloped leaseholds are scheduled to expire during 2017, 2018 and 2019, respectively.

Drilling Activity

The following tables set forth a summary of our developmental and exploratory well drilling activity for the periods presented. There is no necessary correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells that were turned-in-line to sales and commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. The in-process wells are a normal part of our activity. The Wattenberg Field activity is comprised of pad drilling operations where multiple wells are developed from the same well pad and because we operate multiple drilling rigs in the area, we expect to have in-process wells at any given time. Wells may be in-process for anywhere from days to several months. We expect that normal in-process inventory will also exist in the development of our Delaware Basin leasehold. No wells were classified as exploratory in any of the periods presented.

	Gross Development Well Drilling Activity
	Year Ended December 31,
	2016			2015			2014
Operating Region/Area	Productive	In-Process	Non-Productive (1)	Productive	In-Process	Non-Productive (1)	Productive	In-Process	Non-Productive (1)
Wattenberg Field, operated wells	140	64	2	136	78	4	86	44	2
Wattenberg Field, non-operated wells	24	12	—	58	19	—	70	25	—
Delaware Basin	1	5	—	—	—	—	—	—	—
Utica Shale	5	—	—	4	5	—	8	4	1
Other (2)	—	—	—	—	—	—	4	—	—
Total gross development wells	170	81	2	198	102	4	168	73	3

__________

(1) Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.

(2) Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.

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	Net Development Well Drilling Activity
	Year Ended December 31,
	2016			2015			2014
Operating Region/Area	Productive	In-Process	Non-Productive (1)	Productive	In-Process	Non-Productive (1)	Productive	In-Process	Non-Productive (1)
Wattenberg Field, operated wells	109.7	52.7	1.7	110.8	54.6	2.7	75.8	36.5	1.7
Wattenberg Field, non-operated wells	5.0	2.8	—	9.3	4.3	—	14.9	6.3	—
Delaware Basin	1.0	4.8	—	—	—	—	—	—	—
Utica Shale	4.5	—	—	3.0	4.5	—	7.0	3.0	1.0
Other (2)	—	—	—	—	—	—	2.0	—	—
Total net development wells	120.2	60.3	1.7	123.1	63.4	2.7	99.7	45.8	2.7

__________

(1) Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.

(2) Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.

Title to Properties

We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties.

The properties we own are subject to royalty, overriding royalty, and other outstanding interests. The properties may also be subject to additional burdens, liens, or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements, and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties.

Substantially all of our crude oil and natural gas properties, excluding our share of properties held by the limited partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. See the footnote titled Long-Term Debt to our consolidated financial statements included elsewhere in this report.

Facilities

We lease 73,000 square feet of office space in Denver, Colorado, which serves as our corporate office, through February 2023 and 47,000 square feet of office space in Evans, Colorado through November 2025. We own a 32,000 square foot administrative office building located in Bridgeport, West Virginia, and a 60,000 square foot field operating facility in Greeley, Colorado.

We own or lease field operating facilities in or near Evans, Colorado, Midland, Texas, and Marietta, Ohio.

Governmental Regulation

While the prices of crude oil and natural gas are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for crude oil and natural gas production depends on several factors that are beyond our control. These factors include, but are not limited to, regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of crude oil and natural gas available for sale, the availability of adequate pipeline and other transportation, and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and undue control, reduce environmental and health risks from the development and transportation of crude oil and natural gas, prevent misuse of crude oil and natural gas, and protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state, and local agencies. We believe that we are in compliance with such statutes, rules, regulations, and governmental orders in all material respects, although there can be no assurance that this is or will remain the case. The following summary discussion of the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations, and environmental directives to which our operations may be subject.

Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production business is subject to various federal, state, and local laws and regulations relating to the taxation of crude oil and natural gas, the development, production, and marketing of crude oil, and natural gas and environmental and safety matters. State and local laws and regulations require drilling permits and govern the spacing and density of wells, rates of production, water discharge, prevention of waste, and other matters. Prior to

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commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies where the well being drilled is located. Additionally, other regulated matters include:

• bond requirements in order to drill or operate wells;

• well locations;

• drilling and casing methods;

• surface use and restoration of well properties;

• well plugging and abandoning;

• fluid disposal; and

• air emissions.

In addition, our drilling activities involve hydraulic fracturing, which may be subject to additional federal and state disclosure and regulatory requirements discussed in "Environmental Matters" below and in Item 1A, Risk Factors.

Our operations also are subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of lands and leases. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units, and therefore, more difficult to drill and develop our leases where we own less than 100 percent of the leases located within the proposed unit. State laws may establish maximum rates of production from crude oil and natural gas wells, may prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability of production. Leases covering state or federal lands often include additional regulations and conditions. The effect of these conservation laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating, and abandoning our crude oil and natural gas wells and other facilities. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations.

Regulation of Transportation of Natural Gas. We move natural gas through pipelines owned by other companies and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates.

Each interstate natural gas pipeline company establishes its rates primarily through FERC's rate-making process. Key determinants in the ratemaking process are:

• costs of providing service, including depreciation expense;

• allowed rate of return, including the equity component of the capital structure, and related income taxes; and

• volume throughput assumptions.

The availability, terms, and cost of transportation affect our natural gas sales. Competition among suppliers has greatly increased. Furthermore, gathering is exempt from regulation under the Natural Gas Act, thus allowing gatherers to charge unregulated rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area.

Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated and there is no assurance that the current regulatory approach recently taken by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.

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Environmental Matters

Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public demand for the protection of the environment has increased dramatically in recent years. The trend towards more expansive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken which restrict drilling or impose environmental protection requirements resulting in increased costs, our business and prospects may be adversely affected. In addition, the change in the administration under the Executive Branch of our federal government may result in change or uncertainty with respect to the future regulatory environment affecting the oil and natural gas industry. This uncertainty may affect how our industry is regulated as well as the level of public interest in environmental protection and may result in new or different pressures being exerted. For example, public interest groups may increase their use of litigation as a means to continue to exert pressure on the oil and natural gas industry. Accordingly, while we expect regulatory and enforcement pressures on our business to continue at federal, state, and local levels, the nature, level, and source of such pressures may change.

We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore may subject us to more rigorous and costly operating and disposal requirements.

Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We routinely apply hydraulic fracturing in our crude oil and natural gas production programs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA") and issued draft guidance related to this asserted regulatory authority in February 2014. The guidance explains the EPA’s interpretation of the term “diesel fuel” for permitting purposes, describes existing Underground Injection Control Class II program requirements for permitting underground injection of diesel fuels in hydraulic fracturing and also provides recommendations for EPA permit writers in implementing these requirements. From time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic fracturing and disclosure of the chemicals used in the hydraulic fracturing process.

The White House Council on Environmental Quality continues to coordinate an administration-wide review of hydraulic fracturing. The EPA released the final report "Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources" on December 12, 2016. The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances - including surface spills, injection of fluids into wells with inadequate integrity, discharge of untreated or inadequately treated wastewater, and disposal or storage in unlined pits. In addition, the U.S. Department of Energy has investigated practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These ongoing studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), also finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures, and imposing other requirements relating to hydraulic fracturing on federal lands. The rule is currently stayed and not effective pending ongoing litigation.

The states in which we operate, Colorado, Texas, and Ohio, have adopted regulations regarding permitting, transparency, and well construction requirements with respect to hydraulic fracturing operations, and disposal well rules focused on potential seismicity concerns and may in the future adopt additional regulations or otherwise seek to ban fracturing or disposal activities altogether. Colorado and Texas require that all chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission ("Frac Focus"). The Colorado rules also require operators seeking new location approvals to provide certain information to surface owners and adjacent property owners within 500 feet of a new well. Similarly, Colorado has implemented a baseline groundwater sampling rule, a rule governing setback distances of oil and gas wells located near population centers, and recently adopted new rules governing the development of large-scale facilities in urban mitigation areas and additional municipality notice requirements. In December 2013, the Colorado Oil and Gas Conservation Commission ("COGCC") issued new, more restrictive rules regarding spill reporting and remediation. In addition, during 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits.

In November 2013, the Ohio Department of Natural Resources ("ODNR") proposed draft regulations pertaining to well pad construction requirements and increased bonding for construction, and these regulations were finalized in 2014. In October 2015, the ODNR proposed draft regulations pertaining to incident notification. A final hearing on these rules was held October 18, 2016 and the final draft rule was published on October 28, 2016. The effective date is not yet known. Additionally, in November 2015, the ODNR Assistant Chief announced draft rules in progress that address waste management, waste classification, secondary containment, emergency reporting, site remediation standards, well spacing, and simultaneous operations. We continue to be an active participant in the rule making process in Ohio.

In Colorado and Texas, local governing bodies have issued drilling moratoriums, develop jurisdictional siting, permitting and operating requirements, and conduct air quality studies to identify potential public health impacts. For instance, in 2013, the City of Fort Collins, Colorado, adopted a ban on drilling and fracturing of new wells within city limits. In the November 2013 election, voters in the Colorado cities of Boulder, Lafayette, Fort Collins and Brighton passed hydraulic fracturing bans, and in November 2014, Denton, Texas

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passed a hydraulic fracturing ban. See Item 1A, Risk Factors, for a more detailed discussion of these bans and relevant court decisions. If new laws or regulations that significantly restrict hydraulic fracturing or well locations continue to be adopted at local levels or are adopted at the state level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of hydrocarbons, may preclude our ability to drill wells. If hydraulic fracturing becomes more heavily regulated as a result of federal or state legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and permitting delays, as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that we are ultimately able to produce from our reserves. We continue to be active in stakeholder and interest groups and to engage with regulatory agencies in an open, proactive dialogue regarding these matters.

We currently own or lease numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although we believe that we have generally utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. Under such laws, we may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), remediate property contamination (including surface and groundwater contamination), or perform remedial plugging operations to prevent future contamination.

CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported, or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. As an owner and operator of crude oil and natural gas wells, we may be liable pursuant to CERCLA and similar state laws.

Our operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue to develop regulations to implement these requirements. We may be required to incur certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. Federal New Source Performance Standards regarding oil and gas operations and amendments to such standards ("NSPS OOOO” and “NSPS OOOOa”) became effective between 2012 and 2016, and have added administrative and operational costs. In addition, Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to crude oil and natural gas operations that are equally or more stringent than NSPS OOOO / NPS OOOOa and directly regulate methane emissions from affected facilities. In April 2014, the Ohio Environmental Protection Agency Division of Air Pollution Control adopted new General Permit requirements for High Volume Horizontal Hydraulic Fracturing, Oil and Gas Well Site Production Operations. In October 2015, the EPA reduced the ozone compliance levels under the National Ambient Air Quality Standards (“NAAQS”) for ground level ozone to 70 parts per billion (“ppb”) from 75 ppb. In addition, the EPA extended the ozone monitoring season for 32 states, including Colorado, Texas, and Ohio. In October 2016, Colorado submitted revisions to its ozone SIP to meet requirements caused by an increase in ozone non-attainment status to “moderate” from “marginal.”

The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment load out controls, piping controls, berms, and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture, or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013 which determined that the vast majority of tributary streams, wetlands, open water in floodplains, and riparian areas are connected. This report supported the final rule issued in June 2015 clarifying the scope of jurisdictional Waters of the U.S. This final rule has been stayed pending the resolution of ongoing litigation.

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species. The U.S. Fish and Wildlife Service in 2016 finalized a rule to alter how it identifies critical habitat for endangered and threatened species.

Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any

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significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil increases our risks related to soil and water contamination from any future oil spills.

Our costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2017 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report.

Operating Hazards and Insurance

Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures, and discharges of crude oil and natural gas. The occurrence of any of these events could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation, and penalties and suspension of operations. Our pipeline, gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution, and suspension of operations. In 2013, we experienced a significant rainfall event that created widespread flooding in our Wattenberg Field operations in Weld County, Colorado, which resulted in a shut-in of approximately 200 vertical wells. We incurred significant costs to replace damaged well equipment and to bring these vertical wells back on-line. In 2014 and 2015, we experienced three mechanical failures during drilling that resulted in the discharge of oil and related material, the effects from which have been remediated. The impact from the mechanical failures did not have a material adverse effect on our financial condition or results of operations.

Among the regulatory developments involving operating hazards that could impact us going forward are recent investigations by the U.S. Occupational Health and Safety Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain petroleum transfer and related tasks. While we have not experienced such an event, several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward.

Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third-party property, such as transportation pipelines, crude oil refineries, or natural gas processing facilities. Such an event could result in significantly lower regional prices or our inability to deliver our production.

Competition and Technological Changes

We believe that our production, exploration and drilling capabilities, and the experience of our management and professional staff, enable us to compete effectively in our industry. We encounter competition from numerous other crude oil and natural gas companies, drilling and income programs, and partnerships in all areas of operations, including drilling and marketing crude oil and natural gas, obtaining desirable crude oil and natural gas leases on producing properties, obtaining drilling, pumping and other services, attracting and retaining qualified employees, and obtaining capital. International developments may influence other companies to increase their domestic crude oil and natural gas exploration. Competition among companies for favorable prospects can be expected to continue and it is anticipated that the cost of acquiring properties will increase in the future. Many of our competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to acquire additional properties and to explore for crude oil and natural gas prospects in the future depends upon our ability to conduct our operations, evaluate and select suitable properties, and consummate transactions in this highly competitive environment. We also face intense competition in other aspects of our business, including the marketing of natural gas from competitors including other producers and marketing companies.

The oil and gas industry is characterized by rapid and significant technological advancements and introduction of new products and services using new technologies. If one or more of the technologies we use now or in the future become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations, and cash flows could be materially adversely affected.

Employees

As of December 31, 2016, we had 395 full-time employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be good.

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WHERE YOU CAN FIND ADDITIONAL INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy, Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821.

We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures, and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference.

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ITEM 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results, and financial condition, as well as adversely affect the value of an investment in our common stock or other securities.

Risks Relating to Our Business and the Industry

Crude oil, natural gas, and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and impede our growth.

Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas, and NGLs. Changes in prices affect many aspects of our business, including:

• our revenue, profitability and cash flows;

• our liquidity;

• the quantity and present value of our reserves;

• the borrowing base under our revolving credit facility and access to other sources of capital; and

• the nature and scale of our operations.

The markets for crude oil, natural gas, and NGLs are often volatile, and prices may fluctuate in response to, among other things:

• relatively minor changes in regional, national, or global supply and demand;

• regional, national, or global economic conditions, and perceived trends in those conditions;

• geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or OPEC; and

• regulatory changes.

The price of oil has been volatile since mid-2014, with a high over $100 per barrel in June 2014 to lows below $30 per barrel in 2016, in each case based on WTI prices, due to a combination of factors including increased U.S. supply, global economic concerns, and the resumption of oil exports from Iran. Prices for natural gas and NGLs have experienced similar volatility. Declines in prices adversely affect, among other things, our revenue and reserves, and have contributed to the recognition of impairment charges, including charges of $158.3 million and $150.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in 2014 and 2015, respectively. Any future extended period of lower oil prices, or additional price declines, will have further adverse effects on us. For example, if we reduce our capital expenditures due to low prices, natural declines in production from our wells will likely result in reduced production and therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production.

In addition to factors affecting the price of crude oil, natural gas, and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants, and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally may result in widening differentials, particularly for production from some basins. We may be materially and adversely impacted by widening differentials on our production.

The Delaware Basin acquisitions may not achieve their intended results and may result in us assuming unanticipated liabilities.

The Delaware Basin acquisitions subject us to many of the risks described below in “Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties.” For example, we may discover title defects or adverse environmental or other conditions relating to the properties acquired in the transactions of which we are currently unaware. Environmental, title, and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We have assumed substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances, for limited periods and in limited amounts. We cannot provide assurance that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant. Also, it is uncertain whether our existing operations and the acquired properties and assets can be integrated in an efficient and effective manner. In addition, the success of the Delaware Basin acquisitions depend on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGL and natural gas prices and operating costs, and various other factors. The majority of the value was attributed to unproved leaseholds, which inherently have a higher risk of uncertainty than the acquisition of proved developed reserves. These assessments were based to a significant degree on information provided by the sellers and we cannot guarantee their accuracy. Although the acquired properties are subject to many of the risks and uncertainties to which acquisitions we pursue are subject generally, risks associated with the Delaware Basin acquisitions in particular include those associated with our ability to operate efficiently in a new area, the significant size of the transactions in the aggregate, the fact that a substantial majority of the acquired properties are undeveloped, and the additional indebtedness and transaction costs we incurred in connection with the acquisitions. Many of these risks also apply to acquisitions of additional Delaware Basin properties

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we have pursued or may pursue in the future. In addition, we expect that pursuing our future development plans for the properties will require capital in excess of our projected cash flow from operations for some period of time beginning in 2017, which may increase our need for external financing.

Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, approvals of the Texas General Land Office for our Delaware Basin properties, and other factors. These risks are currently greater for us in the Delaware Basin area than in our other operating areas. As of December 31, 2016, approximately 30 percent of our total net acreage in the Delaware Basin was held-by-production or drilling operations. In addition, a substantial portion of our Utica Shale acreage is held-by-production by a third party operator’s shallow vertical wells. Our relative lack of control over this acreage increases the risk that some of our leases will expire.

Ballot initiatives have been proposed in Colorado from time to time that could vastly expand the right of local governments to limit or prohibit oil and natural gas production and development in their jurisdictions and could impose additional regulations on production and development activities. If any initiative or legislation of this nature is implemented and survives legal challenge, additional limitations or prohibitions could be placed on crude oil, natural gas and NGL production and development within certain areas of Colorado or the state as a whole. Similar initiatives could be proposed in other states.

During 2016, certain interest groups in Colorado opposed to oil and natural gas development generally, or hydraulic fracturing in particular, advanced various options for ballot initiatives aimed at significantly limiting or effectively preventing oil and natural gas development in the state of Colorado. Proponents of two such initiatives attempted to qualify the initiatives to appear on the ballot for the November 2016 election. On August 29, 2016, the Colorado Secretary of State issued a press release and statements of insufficiency of signatures, stating that the proponents of the proposals had failed to collect enough valid signatures to have the proposals included on the ballot.

One of the initiatives, which we refer to as the “local control” initiative, would have amended the state constitution to give city, town, and county governments the right to regulate, or to ban, oil and gas development and production within their boundaries, notwithstanding rules and approvals to the contrary at the state level. This proposal was motivated in part by a decision of the Colorado Supreme Court holding that local government restrictions on oil and gas activities are subject to preemption by state rules.

A second initiative, which we refer to as the “setback” initiative, would have amended the state constitution to require all new oil and gas development facilities to be located at least 2,500 feet away from any occupied structure or broadly defined “area of special concern,” including public and community drinking water sources, lakes, rivers, perennial or intermittent streams, creeks, irrigation canals, riparian areas, playgrounds, permanent sports fields, amphitheaters, public parks, and public open space.

If implemented, the setback initiative would have effectively prohibited the vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. The local control proposal would potentially have had a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities. Pursuant to the determination of the Colorado Secretary of State, these proposals did not appear on the November 2016 ballot. However, future proposals of this nature are possible.

Because a substantial portion of our operations and reserves are located in Colorado, the risks we face with respect to such future proposals are greater than those of our competitors with more geographically diverse operations. Although we cannot predict the outcome of future ballot initiatives, statutes, or regulatory developments, such developments could materially impact our results of operations, production, and reserves.

A substantial part of our crude oil, natural gas, and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.

Although we have significant non-producing leasehold positions in the Delaware Basin in Texas and the Utica Shale in Ohio, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including:

• fluctuations in prices of crude oil, natural gas, and NGLs produced from the wells in the area;

• natural disasters such as the flooding that occurred in Northern Colorado in September 2013;

• restrictive governmental regulations; and

• curtailment of production or interruption in the availability of gathering, processing, or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells.

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For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations.

Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business.  Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general.  The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Utica Shale area are particularly vulnerable to title deficiencies due the long history of land ownership in the area and correspondingly extensive and complex chains of title. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability.

Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of crude oil, natural gas, and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including:

• our proved reserves;

• the amount of crude oil, natural gas, and NGLs we are able to produce from existing wells;

• the prices at which crude oil, natural gas, and NGLs are sold;

• the costs to produce crude oil, natural gas, and NGLs; and

• our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability.

Our ability to produce crude oil, natural gas, and NGLs could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.

Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). In addition, both eastern Colorado and western Texas have relatively arid climates and experience drought conditions from time to time. As a result, future availability of water from certain sources used in the past may become limited.

The imposition of new environmental initiatives relating to wastewater could restrict our ability to conduct certain operations such as hydraulic fracturing. This includes potential restrictions on waste disposal, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of hydrocarbons. For example, in 2010 a petition was filed by the Natural Resources Defense Council with the EPA requesting that the agency reassess its prior and long-standing determination that certain oil and natural gas exploration and production wastes would not be regulated as hazardous waste under Subtitle C of the RCRA. The EPA has not yet acted on the petition and it remains pending. In a separate but related matter, a proposed consent decree filed in December 2016 between the EPA and several environmental groups commits the EPA to decide whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector by March 2019. If the EPA began treating some or all of these wastes as “hazardous”

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under Subtitle C in response to the petition or as a result of the proposed consent decree, the consequences for our operations would be serious, and would include a significant increase in costs associated with waste treatment and disposal and a potential inability to conduct operations in some instances.

The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated federal and state waters. Permits or other approvals must be obtained to discharge fill and pollutants into regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. In June 2015, the EPA and the U.S. Army Corps of Engineers issued a final rule that clarifies the scope of the agencies’ jurisdiction under section 404 of the CWA to regulate certain activities occurring in waters of the United States. This rule, known as the Clean Water Rule, has been challenged by various parties in multiple federal courts, and as a result of this litigation is currently stayed and not yet effective. An expansive definition of such jurisdictional waters could affect our ability to operate in certain areas, increase costs of operations, and cause significant scrutiny and delays in permitting. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. These permits, in turn, impose far-ranging monitoring, flow control, and other obligations that have generated, and will continue to generate, increased costs for our operations.

In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. Some states, including Pennsylvania, have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There also has been recent nationwide concern, particularly in Ohio and Oklahoma, over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. As seen in Ohio, it is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others.

Finally, the EPA study on hydraulic fracturing noted above focused on various stages of water use in hydraulic fracturing operations. It is possible that the EPA will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. In addition, an inability to meet our water supply needs to conduct our completion operations may adversely impact our business.

The marketability of our production is dependent upon transportation and processing facilities the capacity and operation of which we do not control. Market conditions or operational impediments, including high line pressures, particularly in the Wattenberg Field, and other impediments affecting midstream facilities and services, could hinder our access to crude oil, natural gas, and NGL markets, increase our costs or delay production, and thereby adversely affect our profitability.

Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, in some recent periods, due to ongoing drilling activities by us and third parties and hot temperatures during the summer months, the principal third-party provider we use in the Wattenberg Field area for midstream facilities and services experienced increased gathering system pressures during those warmer months. The resulting capacity constraints reduced the productivity of some of our older vertical wells and limited incremental production from some of our newer horizontal wells. This constrained our production and reduced our revenue from the affected wells. Capacity constraints affecting natural gas production also impacted the associated NGLs. Some operators in the Delaware Basin have experienced similar issues from time to time, in part due to significant increases in production in the area. Our operations in Texas and elsewhere may be adversely affected by those issues. The use of alternative forms of transportation for oil production such as trucks or rail involve risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or railcars.

In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas, and NGLs we produce.

We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example:

• Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties;

• Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; and

• Some upstream energy companies have in the recent past sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure.

Like other producers we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If we reduce the pace of our drilling activities significantly after entering into such commitments for any reason, it may be difficult or impossible for us to satisfy those commitments.

Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves.

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Crude oil prices fell dramatically in the second half of 2014, with further declines in 2015 and into 2016, and the domestic natural gas market remains weak. Low commodity prices could result in, among other adverse effects, significant impairment charges. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges of $150.3 million and $158.3 million relating to our Utica Shale properties in 2015 and 2014, respectively. Similar charges could occur in the future. In addition, low commodity prices could result in significant downward revisions to the estimated quantity and value of our proved reserves.

Our estimated crude oil and natural gas reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

Calculating reserves for crude oil, natural gas, and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas, and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding commodity prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual results could greatly affect:

• the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties;

• future depreciation, depletion, and amortization (“DD&A”) rates and amounts;

• impairments in the value of our assets;

• the classifications of reserves based on risk of recovery;

• estimates of future net cash flows;

• timing of our capital expenditures; and

• the amount of funds available for us to borrow under our revolving credit facility.

Some of our reserve estimates must be made with limited production histories, which renders these reserve estimates less reliable than estimates based on longer production histories. Horizontal drilling in the Wattenberg Field is a relatively recent development, whereas vertical drilling has been used by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small, and future reserve estimates will be affected by additional production data as it becomes available. Horizontal drilling in the Utica Shale and the Delaware Basin has an even more limited history. Further, reserve estimates are based on the volumes of crude oil, natural gas, and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas, and NGLs recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons.

At December 31, 2016, approximately 71.2 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.1 billion during the five years ending December 31, 2021, as estimated in the calculation of the standardized measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame.

The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, were based on the prior year’s first day of the month 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas, and NGLs, and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general.

Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned.

Producing crude oil, natural gas, and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover, or acquire additional

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reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations.

     We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including:

• crude oil, natural gas, and NGL prices;

• the availability and cost of capital;

• drilling and production costs;

• availability of drilling services and equipment;

• drilling results;

• lease expirations;

• midstream constraints;

• access to and availability of water sourcing and distribution systems;

• regulatory approvals; and

• other factors.

Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas, or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances in order to facilitate exploration.  Other states, including Texas, restrict involuntary pooling to a narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and leases.  In states where pooling is accomplished primarily on a voluntary basis, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than 100 percent of the leasehold or one or more of our leases does not provide the necessary pooling authority. If third parties are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, and this would limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified. Further, our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable, and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related inventory of drilling locations.

The wells we drill may not yield crude oil, natural gas, or NGLs in commercially viable quantities and productive wells may be less successful than we expect.

A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas, or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to whether hydrocarbons are, in fact, present in those structures or the quantity of the hydrocarbons. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas, or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas, and NGLs to be profitable, or they may be less productive and/or profitable than we expected. In recent years we have been able to achieve reductions in drilling and completion costs in connection with lower commodity prices. However, as commodity prices have stabilized or increased since mid-2016, many of these costs have begun to increase, and further increases are expected. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase, the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period.

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Drilling for and producing crude oil, natural gas, and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays, or cancellations as a result of other factors, including:

• unusual or unexpected geological formations;

• pressures;

• fires;

• floods;

• loss of well control;

• loss of drilling fluid circulation;

• title problems;

• facility or equipment malfunctions;

• unexpected operational events;

• shortages or delays in the delivery of equipment and services;

• unanticipated environmental liabilities;

• compliance with environmental and other governmental requirements; and

• adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells, and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites.

Our business strategy focuses on production in our liquid-rich shale plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. Prior to 2012, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of our capital budget to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells - including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - and the risk of failure is therefore greater than the risk involved in drilling vertical wells. Additionally, drilling a horizontal well is typically far costlier than drilling a vertical well. This means that the risks of our drilling program will be spread over a smaller number of wells, and that, in order to be economic, each horizontal well will need to produce at a higher level in order to cover the higher drilling costs. Similarly, the average lateral length of the horizontal wells we drill has generally been increasing. Longer-lateral wells are typically more expensive and require more time for preparation and permitting. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program.

Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability.

We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed.

We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt.

We have a substantial amount of indebtedness. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. We incurred a substantial amount of additional debt in order

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to finance part of the purchase price for the Delaware Basin acquisitions, and the properties acquired currently produce only modest amounts of cash flow from operations.

Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flows from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions, including possibly depressed commodity pricing, and financial, business and other factors, many of which are beyond our control. We expect that some commercial lenders may look to reduce their exposure to exploration and production companies due to regulatory pressures they face and/or independent business considerations. This could adversely affect our liquidity and our ability to refinance our debt.

A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt, or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our existing debt agreements do, restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. Because the cash required to service our indebtedness is not available to finance our operations and other business activities, our indebtedness limits our flexibility in planning for or reacting to changes in our business and the industry in which we operate and increases our vulnerability to economic downturns and sustained declines in commodity prices.

Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions.

The indentures governing our senior notes and our revolving credit facility contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and certain of our subsidiaries’ ability to:

• incur additional debt;

• pay dividends on, redeem, or repurchase stock;

• create liens;

• make specified types of investments;

• apply net proceeds from certain asset sales;

• engage in transactions with our affiliates;

• engage in sale and leaseback transactions;

• merge or consolidate;

• restrict dividends or other payments from restricted subsidiaries;

• sell equity interests of restricted subsidiaries; and

• sell, assign, transfer, lease, convey or dispose of assets.

Our revolving credit facility is secured by substantially all of our crude oil and natural gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility.

Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices.

We depend in large part on our revolving credit facility for future capital needs. The terms of the credit agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable.

The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas, or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results.

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If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations.

Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease.

Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above.

We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility, and may do so in 2017. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we now face.

Seasonal weather conditions and lease stipulations can adversely affect our operations.

Seasonal weather conditions and lease stipulations designed to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, oil field equipment, services, supplies, and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows.

We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.

We operate approximately 88 percent of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks are heightened in some respects in periods of depressed commodity prices as operators may propose operations that we believe to be economically unattractive, leading us to incur non-consent penalties. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters.

Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income.

We use commodity derivatives for a portion of the production from our own wells and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss.

Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity, and they may require the use of our resources to meet cash margin requirements.

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In addition, at December 31, 2016, we had hedged a total of 13,342 MBbls of crude oil and 128,036 BBtu of natural gas for 2017 and 2018. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices, and our current hedge position is smaller than it has been in recent years.

The estimated fair value of our aggregate commodity derivative position as of December 31, 2015, was an asset balance of approximately $263.8 million.  As a result of factors including the settlement of commodity derivative positions over the course of 2016 and changes in commodity prices, the estimated fair value of our aggregate commodity derivative position as of December 31, 2016 was a liability balance of approximately $70.0 million.  Accordingly, based on our current commodity derivative positions and current commodity prices, we expect that cash flow from our commodity derivative activities will be substantially lower in 2017 than it was in 2016, and may be negative.

Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income.

The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from our crude oil, natural gas, and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives as well as the commodity derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

We frequently own less than 100 percent of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas, and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.

The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We also do not carry contingent business interruption insurance related to the purchasers of our production. In addition, pollution and environmental risks are generally not fully insurable.

We may not be able to keep pace with technological developments in our industry.

Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Competition in our industry is intense, which may adversely affect our ability to succeed.

Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas, and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local, and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our operations and our profitability.

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

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Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.

A failure to complete successful acquisitions would limit our growth.

Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes, and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete land trades or exchanges and other acquisitions that allow us to increase our working interests in particular properties. Acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations.

Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties.

Acquisitions of producing properties and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological, and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface, and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor.

When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire.

Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges.

Some of our acquisitions are structured as land trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange. Such an undervaluation would result in the transaction being less favorable to us than we expected.

The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. In addition in August 2015 we received a Clean Air Act Section 114 Information Request (the "Information Request")from the EPA, and this request could result in penalties or other liabilities. The outcome of pending legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees, or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.

The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger declines in the price of our common stock, including, among others:

• changes in production volumes, worldwide demand and prices for crude oil and natural gas;

• changes in market prices of crude oil and natural gas;

• inability to hedge future production at the same pricing level as our current hedges;

• changes in securities analysts’ estimates of our financial performance;

• fluctuations in stock market prices and volumes, particularly among securities of energy companies;

• changes in market valuations and valuation multiples of similar companies;

• changes in interest rates;

• announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing crude oil and natural gas resources;

• announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;

• decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate;

• operating results that fall below market expectations or variations in our quarterly operating results;

• loss of a major customer;

• loss of a relationship with a partner;

• the identification of and severity of environmental events and governmental and other third-party responses to the events; or

• additions or departures of key personnel.

External events, such as news concerning economic conditions, counterparties to our natural gas or oil derivatives arrangements, changes in government regulations impacting the oil and natural gas exploration and production industries or the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. Similarly, our stock price could be adversely affected by changes in the way that analysts and investors assess the geological and economic characteristics of the basins in which we operate. For example, general market perceptions of the Permian Basin region have recently become highly favorable, and adverse changes in those perceptions could have a corresponding effect on the price of our stock. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. Recently, the stock markets have experienced price and volume volatility that has affected many companies’ stock prices. Stock prices for many companies have experienced wide fluctuations that have often been unrelated to the operating performance of those companies. These fluctuations may affect the market price of our common stock.

In addition, a portion of the consideration we paid to the sellers in the Delaware Basin acquisitions was in the form our common stock. Those shares are currently subject to lock-up periods set forth in the applicable Investment Agreement. Upon the expiration of the lock-up period, the sellers will be entitled to sell their shares into the public markets, which could cause the market price of our common stock to decline.

Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.

We face various security threats, including attempts by third parties to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows.

In particular, the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling activities, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data.

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to store, transmit, process, and record sensitive information (including trade secrets, employee information, and financial and operating data), communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexity of the technologies needed to explore for and develop oil, natural gas, and NGLs make certain information more attractive to thieves.

Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. Some of these business partners may be provided limited access to our sensitive information or our information systems and related infrastructure. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. “Phishing” and other types of attempts to obtain unauthorized

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information or access are often sophisticated and difficult to detect or defeat. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies.

Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Given the politically sensitive nature of hydraulic fracturing and the controversy generated by its opponents, our technologies, systems and networks may be of particular interest to certain groups with political agendas, which may seek to launch cyber-attacks as a method of promoting their message. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber-attacks, there can be no assurance that we will not be the target of such attacks in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any security vulnerabilities.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil, natural gas, and NGLs that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such GHGs are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. It was widely expected that facilities required to obtain PSD permits for their GHG emissions would be required to also reduce those emissions according to “best available control technology” (“BACT”) standards. In its permitting guidance for GHGs, issued in November 2010, the EPA recommended options for BACT from the largest sources, which include improved energy efficiency, among others. The EPA also issued a final rule in July 2013 retaining the “tailored” permitting thresholds, opting not to extend GHG permitting requirements to smaller stationary sources at that time.

In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency, upholding the EPA’s GHG-related rules against challenges from various state and industry group petitioners. In October 2013, the United States Supreme Court in Utility Air Regulatory Group v. EPA, accepted a petition for certiorari to decide whether the EPA correctly determined that its regulation of GHGs from mobile sources triggered permitting requirements under the CAA for stationary sources that emit GHGs. In June 2014, the Supreme Court upheld a portion of the EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG BACT requirements, but ruled that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, the EPA issued a proposed rule to revise its PSD and Title V regulations applicable to GHGs in accordance with the decisions noted above, including proposing a de minimis level of GHG emissions below which BACT is not required. Depending on what the EPA does in a final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations and also adversely affect demand for the crude oil and natural gas that we produce.

In the past, Congress has considered various pieces of legislation to reduce emissions of GHGs. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such measures could include a carbon tax, which could result in additional direct costs to our operations. In the absence of such national legislation, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. For example, in February 2014, Colorado adopted rules directly regulating methane emissions from the oil and gas sector.

President Obama indicated that climate change and GHG regulation was a significant priority for his second term. The President issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector. In November 2013, the President released an Executive Order charging various federal agencies, including the EPA, with devising and pursuing strategies to improve the country’s preparedness and resilience to climate change. In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus as reflected in both the EPA’s OOOOa and BLM’s venting and flaring regulations both finalized in 2016 as noted above. In addition, a lawsuit has been filed by several northeastern states that would require the EPA to more stringently regulate methane emissions from the oil and gas sector. Finally, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the United States initially pledged to make a 26-28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020. The passage of legislation or executive and other initiatives, including those made to implement the pledges made in Paris, that limit emissions of GHGs from our equipment and operations could require us to incur costs to reduce GHG emissions, and it could also adversely affect demand for the crude oil, natural gas, and NGLs that we produce.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our

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operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance.

Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Federal, state and local laws and regulations relating to hydraulic fracturing could result in increased costs, additional drilling and operating restrictions or delays in the production of crude oil, natural gas, and NGLs, and could prohibit hydraulic fracturing activities.

Substantially all of our drilling uses hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale, coalbed, and tight sand formations. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the crude oil and natural gas industry in fracturing fluids under the SDWA, and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, including in the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. In March 2011, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. In June 2015, the EPA released a draft assessment of the potential impacts to drinking water resources from hydraulic fracturing for public comment and peer review. The assessment concluded that while there are mechanisms by which hydraulic fracturing can impact drinking water resources, there was no evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States. The EPA’s science advisory board subsequently questioned several elements and conclusions in the EPA’s draft assessment. In December 2016, the EPA released the final report on impacts from hydraulic fracturing activities on drinking water, concluding that hydraulic fracturing activities can impact drinking water resources under some circumstances and identified some factors that could influence these impacts. In addition, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.

The EPA has begun a Toxic Substances Control Act rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. The EPA has not indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the rulemaking. In October 2015, the EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Toxics Release Inventory (“TRI”) program under EPCRA. The EPA determined that natural gas processing facilities may be appropriate for addition to the scope of TRI and will conduct a rulemaking process to propose such action. On January 6, 2017, the EPA issued a proposed rule to include natural gas processing facilities in the TRI program.

The EPA also finalized major new CAA standards (New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels in August 2012. The standards require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators. Following administrative reconsideration of a portion of the 2012 rules, the EPA issued one set of final amendments to the rule in September 2013 related to storage tanks, and a second set of final amendments largely related to reduced emissions completion requirements in December 2014. Most key provisions in the new CAA standards became effective in 2015.

In January 2015, President Obama announced a comprehensive strategy to further reduce methane emissions from the oil and gas sector. As part of this strategy, in June 2016, the EPA finalized amendments to the 2012 NSPS Quad OOOO rules as well as new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. Known as NSPS OOOOa, the new rules impose, among other things, new requirements for leak detection and repair, control requirements at oil well completions, replacement of certain pneumatic pumps and controllers, and additional control requirements for gathering, boosting, and compressor stations. These additional methane reduction requirements are substantial and could increase future costs of our operations and require us to make modifications to our operations and install new equipment. In December 2016, the EPA began a process to regulate existing oil and natural gas facilities through a nationwide Information Collection Request (ICR). The ICR has two parts. First, the EPA is requesting general information about equipment at existing facilities from every operator throughout the country. Second, the EPA issued ICRs to a more targeted set of facilities, requesting more detailed information about these operations. During the fall of 2016, the EPA also issued final Control Techniques Guidelines (CTGs) for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Front Range 8-hour ozone non-attainment area. The ICR and CTG processes could culminate in additional controls being required for our existing sources, which may increase the future costs of operations and require modifications or the installation of new equipment.

On the same day the EPA finalized the NSPS OOOOa rules, it also finalized a rule regarding source determination and permitting requirements for the onshore oil and gas industry under the CAA. The final rule defines the term “adjacent,” which is one of three factors used to determine whether stationary sources (including oil and gas equipment and activities) are considered part of a source that is subject to major source permitting requirements under the CAA. Under this final rule, the oil and gas industry and our operations could be subject to increased permitting costs and more stringent control requirements.

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The EPA has also issued permitting guidance under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by the EPA and may therefore adversely affect even companies, such as PDC, that do not use diesel fuel in hydraulic fracturing activities.

Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. Most notably, in 2015 the U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing on federal and tribal lands. Due to pending litigation, however, the effective date of the rule has been postponed. In November 2016, BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules require additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drain federal minerals. In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. In May 2015, the U.S. Department of Transportation also issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing, and certification requirements.

In addition, the governments of certain states, including Colorado, Texas, and Ohio, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, seismic monitoring, well construction and well location requirements on hydraulic fracturing operations, more stringent notification or consultation processes, or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. For example, in January 2012, the Ohio Department of Natural Resources (“ODNR”) issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio in order to study the relationship between these wells and earthquakes reported in the area. As a result, ODNR promulgated new and more stringent regulations for certain underground injection wells, including requirements for a complete suite of geophysical logs, analytical interpretation of the logs, and enhanced monitoring and recording. More recently, in April 2014, ODNR shut down a number of well sites after a series of small earthquakes in northeast Ohio. After investigating the earthquakes and determining that the connection to hydraulic fracturing was “probable,” ODNR implemented new permit conditions, requiring that operators of well sites within three miles of a known fault must install sensitive seismic-monitoring equipment. Operators must also halt drilling if a seismic event exceeds 1.0 magnitude. In January 2014, the Railroad Commission of Texas finalized a “well integrity rule,” which updates the requirements for drilling and cementing wells, and includes new testing and reporting requirements. In October 2014, the Railroad Commission published a new rule governing the permitting of disposal wells that requires the submission of detailed information related to seismicity. This rule grants the Railroad Commission the ability to deny, modify, suspend or terminate the permit application or existing operating permit. Similar initiatives could spread to other states in which we operate. In addition, oil and gas producers may be subject to lawsuits brought by landowners for earthquake-related damages.

At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing. Beginning in 2012, voters in the cities of Fort Collins, Boulder, Longmont, Broomfield and Lafayette, Colorado approved bans of varying length on hydraulic fracturing within their respective city limits. In 2014, Boulder and Larimer county lower courts overturned the bans. The cities of Longmont and Fort Collins appealed the decisions. In August 2015, the Court of Appeals requested that the Colorado Supreme Court rule on the issue. The Colorado Supreme Court struck down the Fort Collins and Longmont bans in May 2016. Nonetheless, extended moratoria, like that put in place by Boulder County in December 2016, remain a threat to oil and gas operations in Colorado.

In Texas, voters in the City of Denton approved a local ordinance banning hydraulic fracturing in November 2014. In May 2015, the Texas legislature responded by enacting a statute preempting local government regulation of oil and gas activities.

In Ohio, several municipalities have passed hydraulic fracturing bans. In February 2015, the Ohio Supreme Court ruled that local governments cannot regulate hydraulic fracturing, finding that the State of Ohio has exclusive authority over regulating this activity under the State’s oil and gas preemption law, passed in 2004. In light of the recent Ohio Supreme Court decision, activists in Ohio are calling for the repeal of the oil and gas preemption law.

     In addition, lawsuits have been filed against unrelated third parties in several states, including Colorado and Ohio, alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil, natural gas, and NGL production activities using hydraulic fracturing techniques. Additional legislation, regulation, litigation, or moratoria could also lead to operational delays or lead us to incur increased operating or capital costs in the production of crude oil, natural gas, and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, litigation, and other initiatives cause a material decrease in the drilling of new wells or an increase in drilling costs, our profitability could be materially impacted.

Environmental and overall public scrutiny focused on the oil and gas industry is increasing. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local, and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our exploration, development, production, and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage, and natural resource or other damages. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger

34

companies in the industry which can more easily capture economies of scale with respect to compliance. Failure to comply with these laws and regulations may result in various sanctions, including the suspension or termination of our operations or other operational impediments, and could subject us to administrative, civil, and criminal penalties. Moreover, public interest in environmental protection has increased in recent years-particularly with respect to hydraulic fracturing-and environmental organizations have opposed, with some success, certain drilling projects. These regulations also affect our operations, increase our costs of exploration and production, and limit the quantity of crude oil, natural gas, and NGLs that we can produce and market.

A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our properties. Additionally, the crude oil and natural gas regulatory environment could change in ways that substantially increase our financial and managerial compliance costs, increase our exposure to potential damages or limit our activities.

The election of President Trump has resulted in uncertainty with respect to the future regulatory environment affecting the oil and natural gas industry. This uncertainty may affect how our industry is regulated as well as the level of public interest in environmental protection and may result in new or different pressures being exerted. For example, public interest groups may increase their use of litigation as a means to continue to exert pressure on the oil and natural gas industry. Accordingly, while we expect regulatory and enforcement pressures on our business to continue at federal, state, and local levels, the nature, level, and source of such pressures may change.

In August 2015, we received the Information Request from the EPA. The Information Request seeks, among other things, information related to the design, operation, and maintenance of our production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses primarily on 46 of our production facilities and asks that we conduct certain sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016. We cannot predict the outcome of this matter at this time. Certain other operators in the area have been assessed penalties following similar information requests.

In a related Clean Air Act development, on October 1, 2015, the EPA announced its final rule lowering the existing 75 part per billion (“ppb”) NAAQS for ozone under the CAA to 70 ppb. The lower ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs. In addition, the state of Colorado’s non-attainment status was bumped up from “marginal” to “moderate” for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area. This increase in non-attainment status triggers significant additional obligations for the State under the CAA. In 2016, the state undertook rulemaking to address the new “moderate” status, culminating in, among others, the incorporation of two existing state-only requirements for oil and natural gas operations into the federally-enforceable State Implementation Plan ("SIP"). In 2017, as part of the federal Control Techniques Guideline (“CTG”) process for oil and natural gas, Colorado will begin a stakeholder and rulemaking effort to compare the CTGs to existing Colorado requirements to ensure they meet applicable federal requirements. This process could result in new or more stringent air quality control requirements applicable to our operations.

In addition, our activities are subject to regulations governing conservation practices, protection of wildlife and habitat, and protection of correlative rights by state governments. For example, the federal Endangered Species Act (“ESA”) and analogous state laws restrict activities that may adversely affect endangered and threatened species or their habitat. The designation of previously unidentified endangered or threatened species or their habitat in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. For example, the U.S. Fish and Wildlife Service in May 2014 proposed a rule to alter how that agency designates critical habitat. That rule was finalized in 2016 and, depending on how it is implemented, could expand the reach of the ESA.

At the state level the COGCC issued a rule in 2013 governing mandatory minimum setbacks between oil and gas wells and occupied buildings and other areas. Also in 2013, the COGCC issued rules that require baseline sampling of certain ground and surface water in most areas of Colorado and impose stringent spill reporting and remediation requirements. These new sampling requirements could increase the costs of developing wells in certain locations. Other regulatory amendments and policies recently adopted or being proposed by the COGCC address wellbore integrity, hydraulic fracturing, well control, waste management, spill reporting, development of large scale facilities in urban mitigation areas, and certain local government notice requirements. In addition to increasing costs of operation and permitting times, some of these rules and policies, as well as litigation by public interest groups challenging application of these rules or policies, could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues.

In addition, during 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to public health, safety, or welfare; require the COGCC to assess a penalty for each day there is evidence of a violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting from gross negligence or knowing and willful misconduct. In December 2014, the COGCC convened a hearing and adopted proposed amendments to its regulations to implement this new legislation and address certain other issues. Among other things, the amendments create a new process for calculating penalties, new standards for determining days of violation and penalty amounts, new restrictions on the use of informal enforcement procedures, and penalty reductions for voluntary disclosures. Following the adoption of this new penalty scheme, Colorado operators have experienced increased penalties for violations within COGCC’s jurisdiction.

In 2015, the COGCC convened hearings on regulations for large facilities located in urban mitigation areas. These new rules require best available technology and include required mitigations for emissions, flaring, fire, fluid leak detection, repair, reporting, automated well shut-in, storage tank pressure control, and proppant dust control. During these hearings, COGCC staff reported there would

35

also be site-specific mitigation requirements for noise, ground and surface water protection, visual impacts, and remote stimulation. After debate, the rule did not include duration limits despite an opinion from the State Attorney General Office that the COGCC possessed authority to impose duration limits under current and existing statutes.

In February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) finalized regulations imposing stringent new requirements relating to air emissions from oil and gas facilities in Colorado. The new rules impose significantly more stringent control, monitoring, recordkeeping, and reporting requirements than those required under comparable new federal rules. In addition, as part of the rule, the AQCC approved the direct regulation of hydrocarbon (i.e., methane) emissions from the Colorado oil and gas sector. Such state-only, direct regulation of methane (a greenhouse gas) from a single industry sector affected federal regulations from the EPA and the BLM, and continues to have the potential to adversely affect operations in Colorado as well as in other parts of the country. Along the same lines, local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies, in combination with other air quality-related studies that are national in scope, may result in the imposition of additional regulatory requirements on oil and gas operations.

CERCLA (or the “Superfund law”) and some comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. This includes potential liability for activities on properties we may currently own or operate upon, but where previous owner/operators caused the release of a hazardous substance. In addition, we may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been or threaten to be released into the environment. From time to time, we are involved in remediation activities at such properties.

Regulatory focus on worker safety and health regulations involving operating hazards in oil and natural gas exploration and production activities is also increasing. One example is a recent investigation by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain fuel transfer and related tasks. Several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. For example, in December 2015, the Department of Labor and the Department of Justice, Environment and Natural Resources Division released a Memorandum of Understanding (“MOU”), announcing an inter-agency effort to increase the enforcement of workplace safety crimes that occur in conjunction with environmental crimes. Consistent with this MOU, DOJ will look for additional felony violations (such as false statements and willful violations of certain standards) when prosecuting safety crimes in order to heighten prospective penalties and strengthen enforcement. In October 2016, OSHA issued a Regional Emphasis Program (REP) notice for the purpose of conducting safety and hazard inspections at oil and gas industry facilities in Region III (Pennsylvania and West Virginia). Similar notices could result in increased OSHA activities in the areas in which we operate.

Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Ohio. This could adversely affect our existing operations in the state and the economic viability of future drilling. Additional laws, regulations, or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flows, in addition to undermining the demand for the crude oil, natural gas, and NGLs we produce.

Certain federal income tax deductions currently available with respect to crude oil and natural gas and exploration and development may be eliminated as a result of future legislation.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include, but are not limited to (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, which could negatively affect our financial condition and results of operations. In addition, proposals are made from time to time in states where we operate to implement or increase severance or other taxes at the state level, and any such additional taxes would have similarly adverse effects on us.

Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following:

• The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.

• If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.

• Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us.

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The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. The election of President Trump has resulted in uncertainty with respect to the future of the Dodd-Frank Act generally and derivative regulation specifically, and the future impact this may have on PDC is currently unknown.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. 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

In August 2015, we received the Information Request from the 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. The Information Request focused on historical operation and design information for 46 of our production facilities and asks that we conduct sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016. Throughout 2016, we continued to meet with the EPA, Department of Justice, and Colorado Department of Public Health and Environment, and in December we received a draft consent decree from the EPA.

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 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 operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. This matter has been combined with the matter discussed above. The ultimate outcome related to these combined actions has not been determined at this time.

In 2014, we experienced a loss of well control while drilling an oil and gas well in Morgan County, Ohio. The event resulted in a release of well fluids, including oil based drilling mud. We have completed the appropriate remediation to address the release. In August 2015, the EPA issued us a Notice of Intent seeking civil penalties. We and the EPA settled this matter for a civil fine of approximately $152,000 in November 2015.

Action Regarding Firm Transportation Contracts

A group of 42 independent West Virginia natural gas producers has filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. ("Dominion"), certain entities affiliated with Dominion, and our 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. RNG and Dominion have removed the case to the U.S. District Court for the Northern District of West Virginia and have filed pre-trial pleadings. At this time, the case has been remanded back to the state court. 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.

Class Action Regarding 2010 and 2011 Partnership Purchases

In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of unit holders of 12 former limited partnerships, related to its repurchase of the 12 partnerships, which were formed beginning in late 2002 through 2005. The mergers were completed in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and was titled Schulein v. Petroleum Development Corp. The complaint primarily alleged that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court.

In October 2014, the Company and plaintiffs’ counsel reached a settlement agreement in principle that was given final court approval in March 2015. Under this settlement agreement, the plaintiffs received a cash payment of $37.5 million in January 2015, of which the Company paid $31.5 million and insurers paid $6.0 million. In March 2015, the class action was dismissed with prejudice and all class claims were released. In 2014, the Company recorded an expense of $31.5 million related to this litigation, which was included in general and administrative expense in the consolidated statements of operations.

Further information regarding our legal proceedings can be found in the footnote titled Commitments and Contingencies – Litigation to our consolidated financial statements included elsewhere in this report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth the range of high and low sales prices for our common stock based on intra-day trading for each of the periods presented:

	High		Low
January 1 - March 31, 2015	$	55.47	$	37.62
April 1 - June 30, 2015	61.41		51.01
July 1 - September 30, 2015	61.55		41.17
October 1 - December 31, 2015	64.99		52.46
January 1 - March 31, 2016	60.56		42.68
April 1 - June 30, 2016	65.86		51.92
July 1 - September 30, 2016	71.00		50.12
October 1 - December 31, 2016	84.88		59.82

As of February 15, 2017, we had approximately 675 stockholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility as well as the indenture agreements governing our 2024 Senior Notes and our 7.75% senior notes due 2022 ("2022 Senior Notes"), and we presently intend to continue a policy of using retained earnings for expansion of our business.

The following table presents information about our purchases of our common stock during the three months ended December 31, 2016:

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share
October 1 - 31, 2016	5,742	$	66.98
November 1 - 30, 2016	—	$	—
December 1 - 31, 2016	19,969	$	73.37
Total fourth quarter 2016 purchases	25,711	$	71.94

__________

(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.

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STOCKHOLDER PERFORMANCE GRAPH

The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2016, with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 211 crude petroleum and natural gas companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2011, and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance.

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ITEM 6. SELECTED FINANCIAL DATA

	Year Ended/As of December 31,
	2016 (1)			2015			2014			2013			2012
	(in millions, except per share data and as noted)
Statement of Operations (From Continuing Operations) (2):
Crude oil, natural gas and NGLs sales	$	497.4		$	378.7		$	471.4		$	340.8		$	228.0
Commodity price risk management gain (loss), net of actual settlements and changes in mark-to-market valuation adjustments	(125.7		)	$	203.2		310.3			(23.9		)	29.3
Total revenues	382.9			595.3			856.2			392.7			307.1
Income (loss) from continuing operations	(245.9		)	(68.3		)	107.3			(21.1		)	(19.4		)
Earnings (loss) per share from continuing operations:
Basic	$	(5.01	)	$	(1.74	)	$	3.00		$	(0.65	)	$	(0.70	)
Diluted	(5.01		)	(1.74		)	2.93			(0.65		)	(0.70		)
Statement of Cash Flows:
Net cash flows from:
Operating activities	$	486.3		$	411.1		$	236.7		$	159.2		$	174.7
Investing activities	(1,509.1		)	(604.3		)	(474.1		)	(217.1		)	(451.9		)
Financing activities	1,266.1			178.0			60.3			248.7			271.4
Capital expenditures from development and exploration activities (3)	436.9			599.5			623.8			384.7			344.2
Acquisitions of crude oil and natural gas properties	1,073.7			—			—			9.7			312.2
Balance Sheet:
Total assets	$	4,485.8		$	2,370.5		$	2,331.1		$	1,991.7		$	1,777.9
Working capital	129.2			30.7			89.5			90.0			(67.6		)
Total debt, net of unamortized discount and debt issuance costs	1,044.0			642.4			655.5			593.9			637.5
Total equity	2,622.8			1,287.2			1,137.4			967.6			703.2
Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for Production Taxes):
Average sales price (excluding net settlements on derivatives)	$	22.43		$	24.64		$	50.72		$	52.23		$	46.85
Lease operating expenses	$	2.70		$	3.71		$	4.56		$	5.18		$	5.54
Transportation, gathering, and processing	$	0.83		$	0.66		$	0.49		$	0.79		$	0.56
Production taxes	$	1.42		$	1.20		$	2.76		$	3.33		$	2.86
Production taxes as a percent of sales	6.3		%	4.9		%	5.4		%	6.4		%	6.1		%
Production (MBoe):
Production from continuing operations	22,175.9			15,369.4			9,294.4			6,524.7			4,866.5
Production from discontinued operations	—			—			1,093.0			2,032.6			3,458.7
Total production	22,175.9			15,369.4			10,387.4			8,557.3			8,325.2
Total proved reserves (MMBoe) (4)(5)	341.4			272.8			250.1			265.8			192.8

______________

(1) In 2016, we closed acquisitions in the Delaware Basin for aggregate consideration of approximately $1.76 billion.  See footnotes titled Properties and Equipment - Delaware Basin Acreage Acquisition and Business Combination to our consolidated financial statements included elsewhere in this report for further information regarding these acquisitions.

(2) In 2014, we completed the sale of our ownership interest in PDCM.  Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations.  See footnote titled Divestiture and Discontinued Operations to our consolidated financial statements included elsewhere in this report for further information regarding this divestiture.

(3) Includes impact of change in accounts payable related to capital expenditures.

(4) Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe and 30 MMBoe as of December 31, 2013 and 2012, respectively. The joint venture that owned these reserves was sold in late 2014.

(5) Includes total proved reserves related to our Piceance Basin and North Eastern Colorado ("NECO") assets of 14 MMBoe as of December 31, 2012. These assets were sold in 2013.

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ITEM 7. 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 consolidated financial statements and related notes to consolidated financial statements included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report.

SUMMARY

2016 Financial Overview of Operations and Liquidity

Production volumes increased to 22.2 MMBoe in 2016, including 0.2 MMBoe from our recent acquisitions in the Delaware Basin, compared to 15.4 MMBoe in 2015, representing an increase of 44 percent. The increase in production volumes was primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Crude oil production increased 25 percent in 2016, which comprised approximately 39 percent of total production. Natural gas production increased 55 percent and NGLs increased 70 percent in 2016 compared to 2015. These increases were the result of our shift in focus to the higher rate of return drilling projects located in the higher gas to oil ratio inner and middle core areas of the Wattenberg Field during the first half of 2016. On a combined basis, total liquids production of crude oil and NGLs comprised 61 percent of production in 2016 compared to 64 percent of production in 2015, a decrease of four percent. For the month ended December 31, 2016, we maintained an average production rate of 73 MBoe per day, up from 52 MBoe per day for the month ended December 31, 2015.

Crude oil, natural gas, and NGLs sales increased to $497.4 million in 2016 compared to $378.7 millionin 2015, due to a 44 percent increase in production, offset in part by a nine percent decrease in the weighted-average realized prices of crude oil, natural gas, and NGLs, driven by lower commodity prices and changes in commodity mix. Crude oil, natural gas, and NGLs sales, coupled with the impact of positive net settlements of derivatives, also increased in 2016 as compared to 2015. When combining the physical commodity sales and the net settlements received on our commodity derivative instruments, the total net revenues increased 14 percent to $705.4 million in 2016 from $617.6 million in 2015. The low crude oil and natural gas index prices in 2016 and 2015 were the primary reason for the positive net settlements of $208.1 million and $238.9 million on commodity derivatives in 2016 and 2015, respectively.

In 2016, we generated a net loss of $245.9 million, or $5.01 per diluted share. In the same period we generated $435.6 million of adjusted EBITDA, a non-U.S. GAAP financial measure, and invested $396.4 million in the development and exploration of our oil and natural gas properties, which is net of the change in accounts payable related to capital expenditures. Our cash flow from operations was $486.3 million and our adjusted cash flow from operations was $466.8 million in 2016. Adjusted EBITDA and adjusted cash flow from operations are non-U.S. GAAP financial measures as defined and more fully described later in this section.

Other significant changes impacting our 2016 results of operations include the following:

• The net change in the fair value of unsettled derivative positions in 2016 was a loss of $333.8 million compared to a loss of $35.8 million in 2015. The decrease in the fair value of unsettled derivative positions is largely driven by the normal monthly settlements of the commodity derivative instruments in 2016. Additionally, the change in fair value was attributable to hedging positions entered into in 2016 at lower strike prices and the upward shift in the crude oil and natural gas forward curves that occurred during 2016 versus a downward shift in 2015.

• Production tax expense increased to $31.4 million in 2016 from $18.4 million in 2015 due to increased production of 44 percent and higher overall sales proceeds. Additionally, we had a higher effective production tax rate in 2016 primarily from a reduction in ad valorem credits from the prior year to offset current year severance taxes due.

• Impairment of crude oil and natural gas properties was $10.0 million in 2016 compared to $161.6 million in 2015. The 2016 impairments are a result of the write-off of certain leases that were no longer part of our development plan and to reflect the fair value of other land and buildings that are held for sale. The Utica Shale was the largest component of the 2015 write-down which included both producing and non-producing crude oil and natural gas properties.

• General and administrative expense increased to $112.5 million in 2016 compared to $90.0 million in 2015. The increase was attributable to professional and transaction fees related to the Delaware Basin acquisitions and increases in payroll and employee benefits, as we increased our staff by nine percent over the course of 2016.

• Depreciation, depletion, and amortization expense increased to $416.9 million in 2016 compared to $303.3 million in 2015, due to the increase in production volumes from year to year.

• We recorded a provision for uncollectible notes receivable of $44.0 million in the first quarter of 2016 to impair a note receivable.

• Interest expense increased to $62.0 million in 2016 from $47.6 million in 2015. The increase was primarily attributable to a $9.3 million charge for the bridge loan commitment related to our initial Delaware Basin acquisition, a $7.4 million increase in interest expense resulting from the issuance of our 2024 Senior Notes, and a $2.9 million increase in interest expense for the issuance of our 2021 Convertible Notes in September 2016. The increases were partially offset by a $5.1 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016.

Available liquidity as of December 31, 2016 was $932.4 million compared to $402.2 million as of December 31, 2015. Available liquidity as of December 31, 2016 is comprised of $244.1 million of cash and cash equivalents and $688.3 million available for borrowing under our revolving credit facility. In December 2016, pursuant to an amendment to our credit facility and in conjunction with the closing of

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the acquisitions of the Delaware Basin properties, we increased the aggregate commitment under our revolving credit facility from $450 million to $700 million.

In March 2016, we completed a public offering of 5.9 million shares of our common stock at a price to us of $50.11 per share. Net proceeds of the offering were $296.6 million, after deducting offering expenses and underwriting discounts. We used the net proceeds of the offering to repay all amounts then outstanding on our revolving credit facility, the principal and interest owed upon the maturity of the $115 million face value of 2016 Convertible Notes in May 2016 and for general corporate purposes. We settled the 2016 Convertible Notes with a combination of cash and stock, paying the aggregate principal amount, plus cash for fractional shares, totaling approximately $115 million. The conversion price for the 2016 Convertible Notes was $42.40 per share, resulting in the issuance of 792,406 shares of common stock for the excess conversion value.

In June 2016, we entered into definitive agreements with Noble Energy Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core Wattenberg Field. In September 2016, we closed the acreage exchange transaction. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The difference in net acres was primarily due to variances in leasehold net revenue interests and third-party mid-stream contracts. This acreage trade has resulted in opportunities for longer length horizontal laterals with increased working interests, while minimizing potential surface impact.

In September 2016, we sold 9.1 million shares of common stock for net proceeds of $558.5 million, we issued the 2024 Senior Notes for net proceeds of $392.2 million, and we issued the 2021 Convertible Senior Notes convertible at 11.7113 shares of common stock per $1,000 principal amount for net proceeds of $193.9 million (collectively, the "Securities Issuances"). The total net proceeds of $1.1 billion from the Securities Issuances were used to fund a portion of the purchase price of the acquisitions of the Delaware Basin properties, pay related fees and expenses, and for general corporate purposes.

We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flow from our 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 program, utilization of our borrowing capacity under our revolving credit facility, and the pursuit of capital markets transactions from time to time.

Delaware Basin Acquisitions

Through a deliberate and disciplined process of searching for, and evaluating, a large-scale acquisition in a U.S. onshore basin that diversifies our operations and is capable of creating material long-term value-added growth, we recently acquired proved and unproved leasehold in the Delaware Basin in Reeves and Culberson Counties in Texas. The acquisition criteria focused on four key attributes:

• top-tier acreage in core geologic positions;

• significant drilling inventory with additional expansion through down spacing;

• portfolio optionality for capital allocation and diversification; and

• the ability to deliver long-term corporate accretion.

We believe the Delaware Basin acquisitions met these criteria.

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We completed two acquisition transactions associated with the Delaware Basin. The first acquisition closed in early December 2016, and we acquired acreage, approximately 30 producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion, which was comprised of approximately $952.1 million in cash (including the repayment of $40.0 million of debt from the seller at closing) and 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed. The total purchase price remains subject to certain post-closing adjustments as of the date of this report and we expect that it may take into mid-2017 until all post-closing adjustments are settled.

The acquisitions were 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. The details of the purchase price and the preliminary allocation of the purchase price for the first transaction are presented below (in thousands):

Acquisition costs:
Cash, net of cash acquired	$	912,142
Retirement of seller's debt	40,000
Total cash consideration	952,142
Common stock, 9.4 million shares	690,702
Other purchase price adjustments	1,026
Total acquisition costs	$	1,643,870
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	8,201
Crude oil and natural gas properties - proved	216,000
Crude oil and natural gas properties - unproved	1,721,334
Infrastructure, pipeline, and other	32,590
Construction in progress	12,148
Goodwill	62,041
Total assets acquired	2,052,314
Liabilities assumed:
Current liabilities	(24,844		)
Asset retirement obligations	(3,705		)
Deferred tax liabilities, net	(379,895		)
Total liabilities assumed	(408,444		)
Total identifiable net assets acquired	$	1,643,870

The 2016 results of operations of the acquired properties in the first transaction had a loss from operations of $1.7 million, which is included in our consolidated statements of operations for 2016.

The second transaction closed at the end of December 2016. In this transaction, we acquired primarily unproved acreage for cash consideration of $120.6 million. This acquisition is also subject to final settlement as there were some limited producing assets. The final settlement is not expected to be completed until mid-2017.

2016 Drilling Overview

During 2016, we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. Through July 2016, we ran four automated drilling rigs in the Wattenberg Field. In August 2016, we decreased the number of automated drilling rigs to three in anticipation of higher working interests in wells drilled resulting from the acreage exchange. During 2016, we spud 128 gross horizontal, (109.4 net), wells and turned-in-line 140 gross, (109.7 net), horizontal wells in the Wattenberg Field. Also in the Wattenberg Field, we participated in 17 gross (3.6 net) horizontal non-operated wells that were spud and 24 gross (5.0 net) horizontal non-operated wells which were turned-in-line. In the Utica Shale, we completed five gross horizontal (4.5 net) wells, all of which were turned-in-line in 2016. Following the closing of our acquisitions in the Delaware Basin, we spud one well (0.9 net), and turned-in-line another well (1.0 net) prior to the end of 2016.

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The following table summarizes our 2016 drilling and completion activity:

	Gross		Net
In-process as of December 31, 2015	102		63.4
Wells spud during the period	144		112.2
Wells turned-in-line to sales	(170	)	(120.2	)
Acquired in-process	5		4.9
In-process as of December 31, 2016	81		60.3

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. We do not have a practice of inventorying our drilled but uncompleted wells. The majority of these in-process wells at each year end are drilled, but not completed as we do not begin the completion process until the entire well pad is drilled. All costs incurred through the end of the period have been capitalized or accrued to capital, while the capital investment to complete the wells will be incurred in the following year. The cost of completing these wells is included in our 2017 capital forecast.

2017 Operational Outlook

We expect our production for 2017 to range between 30.0 MMBoe to 33.0 MMBoe and we estimate that our production rate will average approximately 82,200 to 90,400 Boe per day. We expect that 41 percent to 43 percent of our 2017 production will be comprised of crude oil and 20 percent to 22 percent will be NGLs, for total liquids of 61 percent to 65 percent of our total 2017 production. Our previously-announced 2017 capital forecast of between $725 million and $775 million is focused on continued development in the core Wattenberg Field and the integration of the core Delaware Basin assets. Due to recent cost escalation for services and the modification of our drilling schedule in the Delaware Basin, where we have accelerated the deployment of an additional drilling rig, we currently expect that our 2017 capital investment will be at or near the high end of the range. These changes to our capital investment outlook are not expected to impact our expected 2017 production as the incremental wells drilled are contemplated to be turned-in-line to sales late in the year.

Wattenberg Field. The 2017 investment outlook of approximately $470 million in the Wattenberg Field anticipates a three to four-rig drilling program based on our current commodity price outlook. Approximately $460 million of our 2017 capital investment program is expected to be allocated to development activities, comprised of approximately $440 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder of the Wattenberg Field capital investment program is expected to be used for miscellaneous workover 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. In 2017, to help manage our priorities, we now anticipate spudding 137 and turning-in-line approximately 139 horizontal operated wells with lateral lengths of 5,000 to 10,000 feet.

Delaware Basin. Our 2017 investment outlook contemplates operating a two-rig to four-rig program in the Delaware Basin from time to time during the year. Total capital investment in the Delaware Basin is estimated to be $300 million, of which approximately $235 million is allocated to spud 31 and turn-in-line an estimated 26 wells.  Of the the 26 planned turn-in-lines, 14 are expected to have 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 12 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. Based on the timing of our operations and the requirements to hold acreage, we may adapt our capital investment program to drill wells in addition to those currently anticipated, as we are continuing to analyze terms of the leaseholds related to our recent acquisitions of properties in the basin. We plan to invest approximately $35 million for leasing, seismic, and technical studies with an additional $30 million for midstream-related projects including gas connections, salt water disposal wells, and surface location infrastructure.

Utica Shale.  At this time, we are currently evaluating all of our strategic alternatives with respect to our Utica Shale position. As a result of such evaluation, we are deferring our 2017 planned expenditure of $18 million to drill, complete, and turn-in-line two wells in Guernsey County.  In 2017, our capital investment program for the Utica Shale is expected to include between $2 million to $3 million for additional leasing. Such leasing may be necessary to complete certain drilling operations if we decide to continue development of our existing position in the northern portion of our acreage.

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Results of Operations

Summary Operating Results

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

	Year Ended December 31,
										Percent Change
	2016			2015			2014			2016-2015		2015-2014
	(dollars in millions, except per unit data)
Production
Crude oil (MBbls)	8,728			6,984			4,322			25.0	%	61.6	%
Natural gas (MMcf)	51,730			33,302			19,298			55.3	%	72.6	%
NGLs (MBbls)	4,826			2,835			1,756			70.2	%	61.4	%
Crude oil equivalent (MBoe)	22,176			15,369			9,294			44.3	%	65.4	%
Average Boe per day	60,590			42,108			25,464			43.9	%	65.4	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	348.9		$	280.3		$	348.6		24.5	%	(19.6	)%
Natural gas	91.6			68.0			74.7			34.7	%	(9.0	)%
NGLs	56.9			30.4			48.1			87.2	%	(36.8	)%
Total crude oil, natural gas, and NGLs sales	$	497.4		$	378.7		$	471.4		31.3	%	(19.7	)%
Net Settlements on Commodity Derivatives (1)
Crude oil	$	165.2		$	208.9		$	2.3		(20.9	)%	*
Natural gas	42.9			30.0			(3.1		)	43.0	%	*
Total net settlements on derivatives	$	208.1		$	238.9		$	(0.8	)	(12.9	)%	*
Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	39.96		$	40.14		$	80.67		(0.4	)%	(50.2	)%
Natural gas (per Mcf)	1.77			2.04			3.87			(13.2	)%	(47.3	)%
NGLs (per Bbl)	11.80			10.72			27.39			10.1	%	(60.9	)%
Crude oil equivalent (per Boe)	22.43			24.64			50.72			(9.0	)%	(51.4	)%
Average Costs and Expenses (per Boe)
Lease operating expenses	$	2.70		$	3.71		$	4.56		(27.2	)%	(18.6	)%
Production taxes	1.42			1.20			2.76			18.3	%	(56.5	)%
Transportation, gathering, and processing expenses	0.83			0.66			0.49			25.8	%	34.7	%
General and administrative expense	5.07			5.85			13.29			(13.3	)%	(56.0	)%
Depreciation, depletion, and amortization	18.80			19.73			20.71			(4.7	)%	(4.7	)%
Other Costs and Expenses
Exploration expense	$	4.7		$	1.1		$	0.9		*		16.4	%
Impairment of properties and equipment	10.0			161.6			166.8			(93.8	)%	(3.1	)%
Interest expense	62.0			47.6			47.8			30.3	%	(0.6	)%
Gas Marketing Contribution Margin (2)	$	(1.5	)	$	(0.8	)	$	(0.4	)	(87.5	)%	(100.0	)%

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

Amounts may not recalculate due to rounding.

______________

(1) Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to gas marketing.

(2) Represents sales from gas marketing, net of costs of gas marketing, including net settlements and net change in fair value of unsettled derivatives related to gas marketing activities.

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Crude Oil, Natural Gas and NGLs Sales

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

	Year Ended December 31,
				Change
Production by Operating Region	2016	2015	2014	2016-2015		2015-2014
Crude oil (MBbls)
Wattenberg Field	8,229.7	6,490.4	4,026.7	26.8	%	61.2	%
Delaware Basin (1)	79.5	—	—	*		*
Utica Shale	419.1	493.4	295.2	(15.1	)%	67.1	%
Total	8,728.3	6,983.8	4,321.9	25.0	%	61.6	%
Natural gas (MMcf)
Wattenberg Field	48,889.1	30,752.8	17,108.9	59.0	%	79.7	%
Delaware Basin (1)	373.3	—	—	*		*
Utica Shale	2,467.8	2,548.9	2,189.1	(3.2	)%	16.4	%
Total	51,730.2	33,301.7	19,298.0	55.3	%	72.6	%
NGLs (MBbls)
Wattenberg Field	4,567.5	2,615.9	1,605.7	74.6	%	62.9	%
Delaware Basin (1)	36.1	—	—	*		*
Utica Shale	222.2	219.4	150.5	1.3	%	45.8	%
Total	4,825.8	2,835.3	1,756.2	70.2	%	61.4	%
Crude oil equivalent (MBoe)
Wattenberg Field	20,945.4	14,231.7	8,483.8	47.2	%	67.8	%
Delaware Basin (1)	177.8	—	—	*		*
Utica Shale	1,052.7	1,137.7	810.6	(7.5	)%	40.4	%
Total	22,175.9	15,369.4	9,294.4	44.3	%	65.4	%

(1) Reflects the Delaware Basin acquisitions that occurred in December 2016.

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

Amounts may not recalculate due to rounding.

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	Year Ended December 31,
Weighted-Average Sales Price by Operating Region							Change
(excluding net settlements on derivatives)	2016		2015		2014		2016-2015		2015-2014
Crude oil (per Bbl)
Wattenberg Field	$	39.99	$	40.03	$	80.61	(0.1	)%	(50.3	)%
Delaware Basin (1)	49.28		—		—		*		*
Utica Shale	37.62		41.59		81.52		(9.5	)%	(49.0	)%
Weighted-average price	39.96		40.14		80.67		(0.4	)%	(50.2	)%
Natural gas (per Mcf)
Wattenberg Field	1.77		2.06		3.94		(14.1	)%	(47.7	)%
Delaware Basin (1)	2.78		—		—		*		*
Utica Shale	1.58		1.85		3.35		(14.6	)%	(44.8	)%
Weighted-average price	1.77		2.04		3.87		(13.2	)%	(47.3	)%
NGLs (per Bbl)
Wattenberg Field	11.59		10.58		25.95		9.5	%	(59.2	)%
Delaware Basin (1)	17.87		—		—		*		*
Utica Shale	15.11		12.43		42.76		21.6	%	(70.9	)%
Weighted-average price	11.80		10.72		27.39		10.1	%	(60.9	)%
Crude oil equivalent (per Boe)
Wattenberg Field	22.38		24.64		51.10		(9.2	)%	(51.8	)%
Delaware Basin (1)	31.50		—		—		*		*
Utica Shale	21.88		24.59		46.87		(11.0	)%	(47.5	)%
Weighted-average price	22.43		24.64		50.72		(9.0	)%	(51.4	)%

(1) Reflects the Delaware Basin acquisitions that occurred in December 2016.

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

Amounts may not recalculate due to rounding.

The year-over-year change in crude oil, natural gas, and NGLs sales revenue were primarily due to the following:

	Year Ended December 31,
	2016			2015
	(in millions)
Increase in production from development of existing properties	$	128.8		$	298.5
Increase in production from acquisitions	0.2			—
Decrease in average crude oil price	(1.6		)	(283.1		)
Decrease in average natural gas price	(14.0		)	(60.9		)
Increase (decrease) in average NGLs price	5.2			(47.2		)
Total increase (decrease) in crude oil, natural gas and NGLs sales revenue	$	118.6		$	(92.7	)

Production volumes increased 44 percent in 2016 compared to 2015. Crude oil production increased 25 percent in 2016, which comprised approximately 39 percent of total production. Natural gas production increased 55 percent and NGLs increased 70 percent in 2016 compared to 2015. The increases in crude oil are different from the comparative period because of our shift in focus to the higher rate of return drilling projects located in the higher gas to oil ratio inner and middle core areas of the Wattenberg Field during the first half of 2016. On a combined basis, total liquids production of crude oil and NGLs comprised 61 percent of production in 2016 compared to 64 percent of production in 2015, a decrease of four percent. Production volumes increased 65 percent in 2015 compared to 2014.  Production of crude oil, natural gas and NGLs was relatively consistent across commodities at 62 percent, 73 percent, and 61 percent, respectively, as we focused our 2015 and 2014 drilling on the middle and outer core areas of the Wattenberg Field. We currently expect our 2017 individual commodity growth and overall production growth to be similar.

Crude oil, natural gas, and NGLs sales in 2016 increased 31 percent compared to 2015. The increase was primarily attributable to higher volumes sold in 2016 of 22.2 MMBoe, up from 15.4 MMBoe in 2015. This was offset in part by a decrease in commodity prices and modest changes in the commodity mix, which resulted in a nine percent decline in the average realized price on a barrel of oil equivalent basis in 2016 compared to 2015. The higher volumes were primarily contributed from turning in-line to sales 140 new gross wells in the Wattenberg Field that delivered significant production volumes. Included in the 22.2 MMBoe is production of 0.2 MMBoe from our acquisitions of producing properties in the Delaware Basin. Our average daily sales volumes increased to 60.6 MBoe per day in 2016

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compared to 42.1 MBoe per day in 2015 as a result of continued drilling and completion activities. The average NYMEX crude oil and natural gas prices decreased by 11 percent and eight percent in 2016 compared to 2015. For crude oil the change was to $43.32 per barrel in 2016 from $48.80 per barrel in 2015, and we were able to offset the majority of the decrease in the NYMEX sales prices through actions that decreased our contractual deductions to $4.39 per barrel in 2016 from $9.95 per barrel in 2015. The natural gas realized sales price decreased more than the decrease in the NYMEX price because a portion of our deductions for natural gas are based on fixed price elements and have a more pronounced effect at lower prices.

Crude oil, natural gas, and NGLs sales in 2015 decreased 20 percent compared to 2014. The decrease was primarily attributable to a significant decrease in commodity prices, resulting in a 51 percent decline in the price of a barrel of crude oil equivalent in 2015 compared to 2014. The decrease was offset in part by the higher volumes sold in 2015 of 15.4 MMBoe, up from 9.3 MMBoe in 2014. Our average daily sales volumes increased to 42.1 MMBoe per day in 2015 compared to 25.5 MMBoe per day in 2014. The average NYMEX crude oil and natural gas prices decreased by 47 percent and 40 percent in 2015 and 2014, respectively.

During various times between 2012 and the summer of 2015, our production had been adversely affected by high line pressures in the natural gas gathering facilities in the Wattenberg Field. Such pressures did not materially affect our production during 2016 due to the investment in the midstream capabilities by our midstream providers and a decrease in development activity by certain producers in the Wattenberg Field resulting in more relative capacity being available to deliver our production. In 2016, approximately 90 percent of our production in the Wattenberg Field was delivered from horizontal wells, with the remaining 10 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 from periodic gas system pressure issues.

We rely on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our, and the overall field's, production growth. We anticipate gathering system pressures to vary throughout the year, with increases coinciding with the warmer summer months.  We, along with other operators in the Wattenberg Field, continue to work closely with our third-party midstream providers in an effort to ensure adequate system capacity going forward as evidenced by a recent commitment of DCP to build additional gathering and processing in the field. This expansion of gathering and processing facilities is expected to improve natural gas gathering pipelines and processing facilities and assist in the control of line pressures in the Wattenberg Field. However, the timing and availability of adequate infrastructure is not within our control and if our midstream provider's construction projects are delayed, we could experience higher line pressures that may negatively impact our ability to fulfill our growth plans. Total system infrastructure needs may also be affected by a number of factors, including potential increases in production from the Wattenberg Field and warmer than expected weather.

Crude Oil, Natural Gas, and NGLs Pricing. Our results of operations depend upon many factors, particularly the price of crude oil, natural gas, and NGLs, and our ability to market our production effectively. Crude oil, natural gas, and NGL prices have a high degree of volatility. While the price of crude oil decreased during the first half of 2016 compared to 2015, prices increased during the second half of 2016 as compared to the first half of the year as the number of U.S. crude oil rigs and inventories declined in the last half of 2015 and into early 2016. Natural gas prices decreased during 2016 compared to 2015, primarily due to domestic oversupply driven by a lack of a normal winter withdrawal cycle in the winter of 2015-2016. We experienced improved NGL pricing towards the end of 2016; however, due to an oversupply of nearly all domestic NGLs products, our average realized sales price for NGLs during most of 2016 reflected the same depressed levels seen during 2015. With the initiation of ethane exports and increased domestic demand for NGLs driven by the completion of petrochemical processing plants, the industry is beginning to see NGL prices trend upward, including in the near term forward market.

Crude Oil. Crude oil pricing is predominately driven by the physical market, supply and demand, the relative strength of the U.S. dollar, financial markets, and national and international politics. In the Wattenberg Field, our crude oil is sold under various purchase contracts with monthly and longer term transportation provisions based on NYMEX pricing, adjusted for differentials. We have entered into commitments ranging in term from one month to over three years to deliver crude oil to competitive markets, resulting in improved overall average deductions in 2016, as noted previously. We continue to pursue various alternatives with respect to oil transportation, particularly in the Wattenberg Field, with a view toward further improving pricing and limiting our use of trucking through delivering greater quantities of our crude oil via pipeline to liquid markets. We began delivering crude oil in accordance with our long term commitment to the White Cliffs pipeline in July 2015. The White Cliffs agreement is one of several we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition, to the White Cliffs agreement described above, we have signed a long-term agreement with Saddle Butte Rockies Midstream, LLC for gathering of crude oil at the wellhead by pipeline from several of our producing pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability, reducing the overall physical footprint of our well pads, and reducing emissions. We began delivering crude oil into this pipeline during the fourth quarter of 2015 and continued to grow these volumes during 2016.

In the Delaware Basin, our crude oil production is sold at the wellhead and transported via trucks to pipelines that deliver the oil to the Midland, Texas, crude oil market. Given the increased level of activity in the form of acquisitions, leasing, and the increases in rig count in the Delaware Basin over the last six months, we expect the balance between production and pipeline takeaway capacity to tighten during 2017. At the current time, there are pipeline, truck and rail pathways out of the basin, all of which are available to us. We are evaluating near-term and longer-term solutions that contemplate the increased activity levels we expect, as well as our anticipated future production. These may include longer-term sales agreements.

In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual pad based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities, or barge loading terminals on the Ohio River. To date, we have not experienced any issues with takeaway capacity in this region for our crude oil.

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Natural Gas. Natural gas prices vary quite significantly by region and locality, depending upon the distance to markets, availability of pipeline capacity, and supply and demand relationships in that region or locality. The price we receive for our natural gas produced in the Wattenberg Field is based on CIG pricing provisions or local distribution company monthly/daily pricing provisions, adjusted for certain deductions. Our natural gas from the Delaware Basin is sold into the Waha hub and El Paso index markets. Natural gas produced in the Utica Shale is sold based on TETCO M-2 pricing.

Natural Gas Liquids. Our NGL sales are priced based upon the components of the product and are correlated to the price of crude oil. Our price for NGLs produced in the Wattenberg Field is based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. While NGL prices remained low during the majority of 2016, we realized improvements in NGL pricing during the fourth quarter of 2016 and are seeing this improvement continue in early 2017. Given the lack of liquidity in the forward markets, it is unclear if this trend will continue. Delaware Basin NGLs sales are indexed to NYMEX and sold into the Mt. Belvieu, Texas market. The NGLs produced in the Utica Shale are sold based on month-to-month pricing to various markets.

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 commodities in the Delaware Basin, and for crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering, and 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 a specified deduction. We sell our commodities at the wellhead or what is tantamount 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 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 the White Cliffs and Saddle Butte pipelines, 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 earn. Rather, we contract separately with the midstream provider 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 a result of the White Cliffs and Saddle Butte agreements, during 2016 and 2015, our Wattenberg Field crude oil average sales price increased approximately $1.60 and $0.73,respectively, per barrel, relative to the benchmark price because we recognized the costs for transportation on the White Cliffs and Saddle Butte pipelines as an increase in revenues and transportation expense, rather than as a deduction from revenues.

Lease Operating Expenses

Lease operating expenses were $60.0 million in 2016 compared to $57.0 million in 2015. Due to newer and more horizontal well completions that deliver larger volumes of production per well than older vertical wells, we are seeing the lease operating costs spread over more volume, resulting in lower lease operating cost per Boe. This is reflected in the fact that our per Boe lease operating expense decreased by 27 percent to $2.70 for 2016 from $3.71 for 2015. The $3.0 million increase in the total lease operating expenses in 2016 as compared to 2015 was primarily due to an increase of $3.7 million for increases in wages and employee benefits related to an increase in headcount, including costs for additional contract labor, $1.8 million for additional leased compressors to address line pressures, and an increase of $1.5 million related to lease operating expenses for the acquisitions in the Delaware Basin. These increases were partially offset by a decrease in environmental remediation and regulatory compliance projects of $3.2 million due to a reduction in new remediation projects, and a decrease of $1.4 million related to fewer workover and maintenance related projects. With our entry into the Delaware Basin, we anticipate that our per Boe lease operating cost will be higher initially as we have limited wells and production over which to apply our lease operating costs. With time, we expect that the lease operating costs per Boe in the Delaware Basin will improve.

Lease operating expenses were $57.0 million in 2015 compared to $42.4 million in 2014. The $14.6 million increase in lease operating expenses in 2015 as compared to 2014 was primarily due to an increase of $4.2 million for environmental remediation and regulatory compliance projects due to increases in the number of projects and an increase in per project expenses, an increase of $3.4 million for additional wages and employee benefits primarily due to additional headcount, including costs for additional contract labor, $2.0 million for additional workover and maintenance related projects, $1.4 million for additional compressors to correct high line pressures in the Wattenberg Field, $1.0 million for the increasing number of non-operated wells in the Wattenberg Field, and $0.9 million for additional costs pertaining to water hauling and disposal. Lease operating expenses per Boe decreased significantly to $3.71 for 2015 from $4.56 in 2014, as a result of increased production.

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Production Taxes

Production taxes are directly related to crude oil, natural gas, and NGLs sales. Production taxes are comprised of both statutory severance tax rates as well as ad valorem tax rates for the applicable production periods. There are a number of adjustments to the statutory rates based on certain credits that are determined based on activity levels and relative commodity prices from year-to-year. The $13.0 million, or 70 percent, increase in production taxes for 2016 compared to 2015 is primarily related to the 31 percent increase in crude oil, natural gas, and NGLs sales, higher ad valorem mill rates, and an overall higher effective tax rate resulting from a decrease in ad valorem tax credits available from the prior year to offset current year severance taxes, driven by the relatively depressed commodity pricing in 2015. These items resulted in effective production tax rates of 6.3 percent and 4.9 percent in 2016 and 2015, respectively. Similarly, the $7.2 million, or 28 percent, decrease in production taxes for 2015 compared to 2014 is primarily related to the 20 percent decrease in crude oil, natural gas, and NGLs sales.

On a per Boe basis, the increase in rates in 2016 impacted the production tax expense, which increased to $1.42 for 2016 compared to $1.20 for 2015 due to the higher effective tax rate noted above. With the decrease in commodity pricing for 2015, production taxes per Boe decreased to $1.20 for 2015 compared to $2.76 for 2014. These items resulted in effective production tax rates of 4.9 percent and 5.4 percent in 2015 and 2014, respectively.

Transportation, Gathering and Processing Expenses

The $8.3 million, or 81 percent, increase in transportation, gathering, and processing expenses for 2016 compared to 2015 was mainly attributable to the costs associated with the White Cliffs and Saddle Butte pipelines in the Wattenberg Field as we began delivering crude oil on these pipelines in July 2015 and December 2015, respectively. We expect to continue to incur these oil transportation costs pursuant to our long-term firm transportation agreement for 6,600 gross barrels per day. The $5.6 million, or 121 percent, increase in transportation, gathering, and processing expenses for 2015 compared to 2014 was mainly attributable to costs associated with the White Cliffs pipeline. Transportation, gathering, and processing expenses per Boe increased to $0.83 for 2016 compared to $0.66 for 2015 and $0.49 for 2014. By using these pipelines and having the pipelines be able to deliver product to the Cushing, Oklahoma market, we benefit from the liquidity associated with the purchasers’ delivery point.

Commodity Price Risk Management, Net

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

Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled derivatives related to our crude oil and natural gas production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing, which are included in sales from and cost of gas marketing.

Net settlements of commodity derivative instruments are based on the difference between the crude oil, natural gas and natural gas 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 as discussed above. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward curves and changes in certain differentials.

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The following table presents net settlements and net change in fair value of unsettled commodity derivatives included in commodity price risk management, net:

	Year Ended December 31,
	2016			2015			2014
	(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil fixed price swaps and collars	$	165.2		$	208.9		$	2.3
Natural gas fixed price swaps and collars	41.9			31.0			(3.7		)
Natural gas basis protection swaps	1.0			(1.0		)	0.6
Total net settlements of commodity derivative instruments	208.1			238.9			(0.8		)
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	(220.0		)	(186.9		)	13.3
Crude oil fixed price swaps and collars	(78.6		)	99.3			256.1
Natural gas fixed price swaps and collars	(37.1		)	53.3			41.7
Natural gas basis swaps	1.9			(1.4		)	—
Net change in fair value of unsettled commodity derivative instruments	(333.8		)	(35.7		)	311.1
Total commodity price risk management gain (loss), net	$	(125.7	)	$	203.2		$	310.3

Exploration Expense

The following table presents the major components of exploration expense:

	Year Ended December 31,
	2016		2015		2014
	(in millions)
Geological and geophysical costs, including seismic purchases	$	3.5	$	—	$	—
Operating, personnel and other	1.2		1.1		0.9
Total exploration expense	$	4.7	$	1.1	$	0.9

Geological and geophysical costs. Geological and geophysical costs in 2016 were primarily related to the portion of the purchase of seismic data related to unproved acreage in the Delaware Basin.

Impairment of Properties and Equipment

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

	Year Ended December 31,
	2016		2015		2014
	(in millions)
Impairment of proved and unproved properties	$	5.6	$	154.6	$	161.6
Amortization of individually insignificant unproved properties	1.4		7.0		4.4
Land and buildings	3.0		—		0.8
Total impairment of properties and equipment	$	10.0	$	161.6	$	166.8

Due to a significant decline in commodity prices and decreases in our net realized sales prices, we experienced triggering events during 2015 and 2014 that required us to assess our crude oil and natural gas properties for possible impairment.  As a result of our assessments, we recorded impairment charges of $150.3 million and $158.3 million in 2015 and 2014, respectively, to write-down our Utica Shale proved and unproved properties.  Of these impairment charges, $24.7 million and $112.6 million were recorded in 2015 and 2014, respectively, to write-down certain capitalized well costs on our Utica Shale proved producing properties. In 2015 and 2014, we also recorded

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impairment charges of $125.6 million and $45.7 million to write-down our Utica Shale lease acquisition costs.  The impairment charges, which are included in the consolidated statements of operations line item impairment of properties and equipment, represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair values.  We continued to monitor whether any further impairments were triggered and required measurement throughout 2016 given the continued volatility of commodity prices and the continued capital investment in the development and acquisition of oil and gas properties. No such triggering events occurred during 2016. Impairment charges in 2016 relate to the retirement of certain leases that were no longer part of our development plan and to reflect the fair value of other property and equipment that was held for sale as of December 31, 2016. Future deterioration of commodity prices or other operating circumstances could result in additional impairment charges to our properties and equipment.

Amortization of individually insignificant unproved properties. The decrease in 2016 as compared to 2015 is due to the impairment of leases in 2015, which significantly reduced total lease costs. The increase in 2015 as compared to 2014 was primarily related to a higher number of insignificant leases that were subject to amortization in 2015, primarily in the Utica Shale.

Land and buildings. The impairment charge for 2016 represents the excess of the carrying value over the estimated fair value, less the cost to sell, of a field operating facility in Greeley, Colorado, and 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters. The fair values of these assets were determined based upon estimated future cash flows from unrelated third-party bids.

General and Administrative Expense

General and administrative expense increased $22.5 million, or 25 percent, in 2016 compared to 2015. The increase in cash based general and administrative costs was primarily attributable to $12.2 million of legal and professional fees related to the acquisitions in the Delaware Basin, a $7.7 million increase in payroll and employee benefits due to per capita increases in wages and increases in headcount given the increase in our personnel by nine percent over the course of 2016. Stock-based compensation expense in 2016 and 2015 was $19.5 million and $20.1 million, respectively.

General and administrative expense decreased $33.6 million, or 27 percent, in 2015 compared to 2014. The decrease was primarily attributable to $40.3 million recorded in 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships and a $1.8 million decrease in costs for legal and other professional services in 2015. The decreases were offset in part by an $8.2 million increase in payroll and employee benefits in 2015, of which $3.3 million was related to stock-based compensation. Stock-based compensation expense in 2015 and 2014 was $20.1 million and $17.5 million, respectively.

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Depreciation, Depletion, and Amortization

Crude oil and natural gas properties. During 2016, 2015, and 2014, we invested $396.4 million, $554.3 million and $663.4 million, which is net of the change in accounts payable related to capital expenditures, in the development of our oil and natural gas properties, respectively. We also incurred $1.76 billion to acquire proved reserves during 2016. We did not invest in any acquisitions of proved reserves in 2015 or 2014. 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 $413.1 million, $298.8 million, and $188.5 million in 2016, 2015, and 2014, respectively. The year-over-year change in DD&A expense related to crude oil and natural gas properties were primarily due to the following:

	Year Ended December 31,
	2016 - 2015			2015 - 2014
	(in millions)
Increase in production	$	132.3		$	123.4
Decrease in weighted-average depreciation, depletion and amortization rates	(18.0		)	(13.1		)
Total increase in DD&A expense related to crude oil and natural gas properties	$	114.3		$	110.3

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

	Year Ended December 31,
Operating Region/Area	2016		2015		2014
	(per Boe)
Wattenberg Field	$	19.11	$	20.13	$	19.26
Delaware Basin	8.34		—		—
Utica Shale	10.66		10.74		31.19
Total weighted-average	18.63		19.44		20.28

The 2016 rate for the Delaware Basin is related to our acquisitions in the Delaware Basin. The slight decrease in the Wattenberg Field rate for 2016 as compared to 2015 was primarily due to the impact of our 2016 year-end reserves. The decrease in the Utica Shale DD&A expense rates in 2015 relative to 2014 was primarily due to the effect of impairments recorded in 2015 and 2014 to write-down certain capitalized well costs on our Utica Shale proved producing properties.

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. Later in 2016, we collected a $0.7 million promissory note and reversed the related provision and allowance for uncollectible notes receivable.

Accretion of Asset Retirement Obligations

Accretion of asset retirement obligations ("ARO") for 2016 increased by $0.8 million, or 13 percent, compared to 2015, and increased by $2.9 million, or 84 percent, in 2015 compared to 2014. The increase in 2016 was due to adding new wells and the associated increase in amortization expense. The increase in 2015 was primarily attributable to decreases in the estimated useful life of certain vertical wells in the Wattenberg Field.

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Interest Expense

Interest expense increased by approximately $14.4 million in 2016 compared to 2015. The increase is primarily attributable to a $9.3 million charge for the bridge loan commitment related to acquisitions of properties in the Delaware Basin, a $7.4 million increase in interest for the issuance of our 2024 Senior Notes, and a $2.9 million increase in interest expense for the issuance of our 2021 Convertible Notes in September 2016. The increases were partially offset by a $5.1 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016. The entire $9.3 million of interest expense attributed to the bridge loan facility was expensed in 2016 as the bridge loan was replaced with equity and longer term debt financing.

Interest expense decreased by approximately $0.3 million in 2015 compared to 2014. The decrease is primarily comprised of a $1.6 million decrease attributable to an increase in capitalized interest, offset in part by a $0.9 million increase due to higher average borrowings on our revolving credit facility in 2015.

Interest costs capitalized in 2016, 2015, and 2014 were $4.5 million, $5.1 million, and $3.5 million, respectively.

Provision for Income Taxes

The current income tax benefit (expense) in 2016, 2015, and 2014 was $9.9 million, $(3.1) million, and $(0.5) million, respectively. Current income taxes generally relate to the cash that is paid or recovered for income taxes associated with the applicable period. The remaining portion of the total income tax expense is comprised of deferred income tax expense (benefit), which is a result of differences in the timing of deductions for our GAAP presentation of financial statements and the income tax regulations.

For 2016, 2015, and 2014, the effective income tax rate (the "rate") of 37.4 percent, 35.9 percent, and 39.5 percent on income (loss) from operations differs from the federal statutory tax rate of 35 percent primarily due to state taxes and excess stock compensation benefits, offset by nondeductible expenses that consist primarily of officers' compensation cost and government lobbying expenses.

As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions. We continue to voluntarily participate in the Internal Revenue Service’s ("IRS") Compliance Assurance Program (the "CAP Program") for the 2015, 2016, and 2017 tax years. We have received a full acceptance notice from the IRS for our filed 2015 federal tax return and the IRS's post filing review is complete.

We acquired a net deferred tax liability of $379.9 million in 2016 associated with a lack of tax basis relative to the purchase price of one of the Delaware Basin acquisitions. This has resulted in a material increase in our deferred tax liability on the balance sheet as of December 31, 2016.

There has been increased discussion by the federal government of a potential reduction of the corporate income tax rate and corresponding changes to the tax code. In the event of a change in federal or state income tax rates, the impact of the rate change will be required to be recorded through deferred income tax expense. Should statutory income tax rates decrease, our deferred tax liability would decrease, resulting in deferred tax benefit for the period. If the statutory income tax rates increase, our deferred tax liability would increase resulting in a deferred tax expense.

Discontinued Operations

Appalachian Marcellus Shale Assets. In October 2014, we completed the sale of our entire 50 percent ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192.0 million, comprised of approximately $152.8 million in net cash proceeds and a promissory note due in 2020 of approximately $39.0 million. The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions in effect at the time. The divestiture resulted in a pre-tax gain of $76.3 million. The divestiture represented a strategic shift in our operations. Accordingly, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for 2014 and prior periods in the Selected Financial Information disclosures.

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

The factors resulting in changes in net loss in 2016 and 2015 compared to net income in 2014 are discussed above. These same reasons similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes, of $208.9 million, $22.2 million, and $193.1 million in 2016, 2015, and 2014, respectively. Adjusted net loss, a non-U.S. GAAP financial measure, was $37.0 million, $46.1 million, and $37.7 million in 2016, 2015, and 2014 respectively. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of this non-U.S. GAAP financial measure.

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Financial Condition, Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in debt, and equity capital market transactions and asset sales. In 2016, our primary sources of liquidity were net cash flows from operating activities of $486.3 million, the net proceeds received from the March 2016 public offering of our common stock of approximately $296.6 million, and the net proceeds from the Securities Issuances of approximately $1.1 billion.

We used a portion of the net proceeds from the March 2016 common stock offering to repay all amounts then outstanding on our revolving credit facility and the principal amount owed upon the maturity of the 2016 Convertible Notes in May 2016 and the remainder for general corporate purposes. The net proceeds from the Securities Issuances were used to fund a portion of the purchase price and related fees for acquisitions in the Delaware Basin and for general corporate purposes.

Our primary source of cash flows from operating activities is the sale of crude oil, natural gas, and NGLs. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we partially manage this volatility through our use of commodity derivative instruments. In 2016 and 2015, net settled commodity derivatives comprised approximately 43 percent and 58 percent, respectively, of our cash flows from operating activities. Based upon our hedge position and assuming year-end forward strip pricing, in 2017 and thereafter our derivatives may not be a significant source of cash flow, and may result in cash outflows in 2017 and 2018. As of December 31, 2016, the fair value of our derivatives was a net liability of $70.0 million. Based on the forward pricing strip at December 31, 2016, we would expect negative net settlements totaling approximately $45 million during 2017.

The covenants under our revolving credit agreement limit the volume of our expected future production that we may hedge. However, we may enter into commodity derivative instruments with future settlement periods of up to sixty months from the date of issuance of the commodity derivative instrument. We do not have minimum hedging requirements associated with our revolving credit facility.

Our net 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 historical practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility when we have borrowings outstanding. At December 31, 2016, we had a working capital surplus of $129.2 million compared to a surplus of $30.7 million at December 31, 2015. The increase in working capital is primarily the result of an increase of $243.3 million in cash and cash equivalents, the $112.9 million reduction in the current portion of long-term debt due to the settlement of our 2016 Convertible Notes in May 2016, and no current amounts outstanding under our revolving credit facility as of December 31, 2016, partially offset by a negative change in the fair value of our commodity derivative instruments of $264.9 million from 2015 to 2016. The net cash position was a result of the Securities Issuances and our desire to have cash available to fund the portion of the 2017 capital investment program that is expected to exceed operating cash flows.

We ended 2016 with cash and cash equivalents of $244.1 million and availability under our revolving credit facility of $688.3 million, providing for a total liquidity position of $932.4 million, compared to $402.2 million at December 31, 2015. The change in liquidity of $530.2 million, or 131.8 percent, was primarily attributable to:

•net cash flows from operating activities of $486.3 million;

•net proceeds received from the March 2016 public offering of our common stock of approximately $296.6 million;

•net proceeds from the Securities Issuances of approximately $1.1 billion; offset in part by,

•cash outflows for capital investments associated with development, exploration, and acquisition activity of

$1.76 billion during 2016; and

•cash payment of approximately $115 million upon the maturity of our Convertible Notes in May 2016.

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

In March 2015, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants or purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. We have utilized the shelf registration statement to raise capital from time to time, and we may utilize the facility in the future to raise additional capital.

Our revolving credit facility is a borrowing base facility and availability under the facility is subject to redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. In September 2016, we entered into a Third Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amended the revolving credit facility to permit the completion of acquisitions in the Delaware Basin and, effective upon closing of the acquisitions, adjusted the interest rate payable on amounts borrowed under the facility, increased the aggregate commitments under the facility from $450 million to $700 million, and reduced our maximum leverage ratio to 4.00:1.00 times as described in more detail below. The maturity date of our revolving credit facility is May 2020. In October 2016, we entered into the Fourth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, reaffirmed our borrowing base at $700 million and, increased the percentage of our

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future production that we are permitted to hedge. Our borrowing base availability 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.

Our borrowings bear interest at either the LIBOR or prime rate plus an applicable margin, depending on the percentage of the commitment that has been utilized as of December 31, 2016, the applicable margin is 1.25%, and the unused commitment fee is 0.50%.

We had no balance outstanding on our revolving credit facility as of December 31, 2016. As of December 31, 2016, RNG had issued an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit expires in September 2017 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. While we have added and expect to continue to add producing reserves through our drilling operations, the effect of any such reserve additions on our borrowing base could be offset by other factors including, among other things, a prolonged period of depressed commodity prices or regulatory pressure on lenders to reduce their exposure to exploration and production companies.

Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.00 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) ("EBITDAX"), and (ii) an adjusted current ratio of at least 1.00:1.00. 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 December 31, 2016, we were in compliance with all debt covenants with a 2.10 times debt to EBITDAX ratio and a 5.00:1.00 current ratio. We expect to remain in compliance into the foreseeable future.

The indentures governing our 2024 Senior Notes and 2022 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 limitations as to availability 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 December 31, 2016, we were in compliance with all covenants and expect to remain in compliance into the foreseeable future.

In January 2017, pursuant to the filing of the supplemental indentures for the 1.25% convertible senior notes due in 2021 ("2021 Convertible Senior Notes"), the 2024 Senior Notes, and the 2022 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 provided by operating activities increased in 2016 compared to 2015. The $75.2 million increase was primarily due to the increase in crude oil, natural gas, and NGLs sales of $118.7 million. We also realized an increase in the change of funds held for future distribution of $36.5 million, and an increase in the deferral of income taxes of $13.1 million. The increases were partially offset by a decrease in monthly derivative commodity settlements of $30.8 million, and increases in general and administrative expense of $22.5 million, interest expense of $14.4 million, production taxes of $13.0 million and transportation, gathering, and processing expenses of $8.3 million.

Cash flows provided by operating activities increased in 2015 compared to 2014. The $174.4 million increase was primarily due to the increase in normal monthly derivative commodity settlements of $241.0 million and a decrease in general and administrative expense of $33.6 million and production taxes of $7.2 million. The increase was offset by the decrease in crude oil, natural gas, and NGLs sales of $92.7 million and an increase in lease operating costs of $14.6 million.

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $46.0 million in 2016 to $466.8 million, and $170.6 million to $420.8 million in 2015, when compared to the respective prior years. These changes were 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/or receipts of our assets and liabilities of $19.5 million and $9.7 million in 2016 and 2015, respectively.

Adjusted EBITDA, a non-U.S. GAAP financial measure, decreased by $7.6 million in 2016 to $435.6 million from $443.2 million in 2015, primarily as a result of the provision for uncollectible notes receivable of $44.0 million, the decrease in net settlements from our monthly derivative commodity settlements of $30.8 million, an increase in general and administrative expense of $22.5 million, and a $27.8 million increase in production and exploration expense. The decrease was partially offset by the increase in crude oil, natural gas, and NGLs sales of $118.7 million.

Adjusted EBITDA increased by $78.9 million in 2015 from 2014, primarily as a result of the increase in normal monthly derivative commodity settlements of $241.0 million and a decrease in general and administrative expense of $33.6 million. The increase was partially

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offset by the decrease in crude oil, natural gas, and NGLs sales of $92.7 million, and an $88.8 million decrease in contribution margins from discontinued operations and a $14.6 million increase in lease operating costs.

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 invest significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital markets are not available 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. During 2016, our acquisitions in the Delaware Basin comprised the majority of our cash flows used in investing activities. Net cash used in the Delaware Basin acquisitions was $1.1 billion and we used cash of $436.9 million for our oil and gas operations. Our total cash used in investing activities during 2016 was approximately $1.5 billion. Through July 2016, we ran four automated drilling rigs in the Wattenberg Field. In August 2016, we decreased the number of automated drilling rigs to three in anticipation of higher working interests in wells drilled resulting from an acreage exchange. In the Utica Shale, we drilled and completed five gross (4.5 net) wells, all of which were turned-in-line to sales in 2016. With the closing of our acquisitions in the Delaware Basin, we completed the drilling of two wells that were in-process at closing, spud an additional well, and turned-in-line one well prior to the end of 2016.

Net cash used in investing activities of $604.3 million during 2015 was primarily related to cash utilized for our drilling operations. Net cash used in investing activities of $474.1 million during 2014 was primarily related to cash utilized for our drilling operations of $623.8 million, offset in part by the $152.8 million net cash proceeds received from the sale of our entire 50 percent ownership interest in PDCM.

Financing Activities. Net cash from financing activities in 2016 was primarily related to the $855.1 million of net proceeds received from the issuance of 9.4 million shares of our common stock, $392.2 million of net proceeds from issuance of the 2024 Senior Notes and $193.9 million of net proceeds from issuance of the 2021 Convertible Notes, partially offset by the $115 million payment 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.

Net cash from financing activities in 2015 was primarily related to $202.9 million of net proceeds received from the issuance of our common stock in March 2015, partially offset by net payments of approximately $19.0 million to pay down amounts borrowed under our revolving credit facility. Net cash from financing activities in 2014 were primarily comprised of net borrowings under our revolving credit facility of $63.8 million to execute our capital budget.

Contractual Obligations and Contingent Commitments

The following table presents our contractual obligations and contingent commitments as of December 31, 2016:

	Payments due by period
			Less than		1-3		3-5		More than
Contractual Obligations and Contingent Commitments	Total		1 year		years		years		5 years
	(in millions)
Long-term liabilities reflected on the consolidated balance sheet (1)
Long-term debt (2)	$	1,100	$	—	$	—	$	900	$	200
Commodity derivative contracts (3)	81		54		27		—		—
Capital leases (4)	2		1		1		—		—
Production tax liability	53		24		29		—		—
Asset retirement obligations	93		10		20		22		41
Other liabilities (5)	7		1		1		2		3
	1,336		90		78		924		244
Commitments, contingencies and other arrangements (6)
Interest on long-term debt (7)	537		91		181		169		96
Operating leases	22		3		6		6		7
Firm transportation and processing agreements (8)	187		17		52		49		69
	746		111		239		224		172
Total	$	2,082	$	201	$	317	$	1,148	$	416

__________

(1) Table does not include deferred income tax liability to taxing authorities of $143.5 million, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

(2) Amount presented does not agree with the consolidated balance sheets in that it excludes $37.5 million of unamortized debt discount and $18.6 million of unamortized debt issuance costs.

(3) Represents our gross liability related to the fair value of derivative positions.

(4) Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets.

(5) Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.

(6) Table does not include an undrawn $11.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

(7) Amounts presented include $224.4 million to the holders of our 2022 Senior Notes, $188.7 million to the holders of our 2024 Senior Notes, and $115.2 million payable to the holders of our 2021 Convertible Notes. Amounts also include $11.0 million payable to the participating banks in our revolving credit facility, of which interest of $9.0 million is related to unutilized commitments at a rate of 0.38% per annum, and $0.2 million is related to our undrawn letters of credit.

(8) Represents our gross commitment which 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. This includes anticipated and estimated commitments associated with a new gas processing facility by our primary mid-stream provider. The timing of such payments has been estimated and is subject to change based on the completion of construction and the commencing of operations by the midstream provider.

As the managing general partner of affiliated partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability.

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.

Critical Accounting Policies and Estimates

We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the presentation of our financial position and results of operations and we may use significant judgment in the application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see the footnote titled Summary of Significant Accounting Policies to our consolidated financial statements included elsewhere in this report.

Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves.

Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions, new drilling, and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income (loss).

Exploration costs, including geological and geophysical expenses, the acquisition of seismic data covering unproved acreage,

and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied.

The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil and natural gas properties. The

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amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of crude oil and natural gas properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

We assess our crude oil and natural gas properties for possible impairment upon a triggering event or when circumstances warrant

by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. Any impairment in value is charged to impairment of properties and equipment. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices, or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

Crude Oil, Natural Gas, and NGLs Sales Revenue Recognition. Crude oil, natural gas, and NGLs sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas, and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have been immaterial. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded.

Fair Value of Financial Instruments. 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.

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

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

Net settlements on our commodity derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our commodity derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the commodity derivative instrument. We have evaluated the credit risk of the counterparties holding our commodity derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding commodity derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our commodity derivative instruments is not significant.

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Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing. The judgments used in applying these policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates.

Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses and assets. The value of the purchase consideration takes into account the degree to which the consideration is objective and measurable such as cash consideration paid to a seller. With the issuance of equity, restrictions upon the sale of the issued stock are taken into consideration. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices, and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties.

In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors.

We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Recent Accounting Standards

See the footnote titled Summary of Significant Accounting Policies - Recently Adopted Accounting Standards to our consolidated financial statements included elsewhere in this report.

Reconciliation of Non-U.S. GAAP Financial Measures

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

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 effects. 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 mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. Additionally, other items which we believe are not indicative of future results may be excluded to clearly identify operating trends.

Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, depreciation, depletion, and amortization and accretion of asset retirement obligations, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), nor as an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA 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 EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts, and others that utilize our financial statements to analyze such things as:

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

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

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

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

PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors, and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves.

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

	Year Ended December 31,
	2016			2015			2014
	(in millions)
Adjusted cash flows from operations:
Net cash from operating activities	$	486.3		$	411.1		$	236.7
Changes in assets and liabilities	(19.5		)	9.7			13.5
Adjusted cash flows from operations	$	466.8		$	420.8		$	250.2
Adjusted net income (loss):
Net income (loss)	$	(245.9	)	$	(68.3	)	$	155.4
(Gain) loss on commodity derivative instruments	125.6			(203.2		)	(309.3		)
Net settlements on commodity derivative instruments	208.2			239.0			(2.0		)
Tax effect of above adjustments	(124.9		)	(13.6		)	118.2
Adjusted net income (loss)	$	(37.0	)	$	(46.1	)	$	(37.7	)
Net income (loss) to adjusted EBITDA:
Net income (loss)	$	(245.9	)	$	(68.3	)	$	155.4
(Gain) loss on commodity derivative instruments, including net settlements	125.6			(203.2		)	(309.3		)
Net settlement (gain) loss on commodity derivative instruments	208.2			239.0			(2.0		)
Interest expense, net	61.0			42.8			48.6
Income tax expense (benefit)	(147.2		)	(38.3		)	99.2
Impairment of properties and equipment	10.0			161.6			167.3
Depreciation, depletion and amortization	416.9			303.3			201.7
Accretion of asset retirement obligations	7.0			6.3			3.4
Adjusted EBITDA	$	435.6		$	443.2		$	364.3
Cash from operating activities to adjusted EBITDA:
Net cash from operating activities	$	486.3		$	411.1		$	236.7
Interest expense, net	61.0			42.8			48.6
Stock-based compensation	(19.5		)	(20.1		)	(17.5		)
Amortization of debt discount and issuance costs	(16.2		)	(7.0		)	(6.9		)
Gain on sale of properties and equipment	—			0.4			76.0
Other	(56.5		)	6.3			13.9
Changes in assets and liabilities	(19.5		)	9.7			13.5
Adjusted EBITDA	$	435.6		$	443.2		$	364.3
PV-10:
PV-10	$	1,675.0		$	1,337.5		$	3,450.1
Present value of estimated future income tax discounted at 10%	(254.4		)	(240.6		)	(1,143.6		)
Standardized measure of discounted future net cash flows	$	1,420.6		$	1,096.9		$	2,306.5

Amounts above include results from continuing and discontinued operations.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Market-Sensitive Instruments and Risk Management

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

Interest Rate Risk

Changes in interest rates affect the amount of interest we earn on our interest bearing cash and cash equivalents 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 December 31, 2016, our interest-bearing deposit accounts included money market accounts and checking accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2016 was $208.8 million, with a weighted-average interest rate of 0.3 percent.Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2016 and assuming we had $208.8 million outstanding throughout the period, we estimate that a one percent increase in interest rates would have increased interest income for the twelve months ended December 31, 2016 by approximately $2.1 million.

As of December 31, 2016, 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, 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 and natural gas 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.

The following table presents our commodity derivative positions related to crude oil and natural gas sales in effect as of December 31, 2016:

	Collars					Fixed-Price Swaps			Basis Protection Swaps
Commodity/ Index/ Maturity Period	Quantity(Gas - BBtu Oil - MBbls)	Weighted-Average Contract Price				Quantity(Gas - BBtu Oil - MBbls)	Weighted- Average Contract Price		Quantity (BBtu)	Weighted- Average Contract Price				Fair Value December 31, 2016 (1) (in millions)
		Floors		Ceilings
Crude Oil
NYMEX
2017	2,464	$	49.54	$	62.32	6,002	$	49.14	—	$	—			$	(44.3	)
2018	1,512	41.85		54.31		3,364	53.25		—	—				(19.1		)
Total Crude Oil	3,976					9,366			—				—	$	(63.4	)
Natural Gas
NYMEX
2017	7,920	$	3.59	$	4.13	27,290	$	3.55	28,116	$	(0.29	)		$	(0.5	)
2018	1,230	3.00		3.67		45,280	2.94		18,200	(0.29		)		(6.1		)
Total Natural Gas	9,150					72,570			46,316					$	(6.6	)
Total Crude Oil and Natural Gas														$	(70.0	)

_____________

(1) Approximately 44 percent of the fair value of our commodity derivative assets and 18percentof the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

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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:

	Year Ended December 31,
	2016		2015
Average Index Price:
Crude oil (per Bbl)
NYMEX	$	43.32	$	48.80
Natural gas (per MMBtu)
NYMEX	$	2.46	$	2.66
Average Sales Price Realized:
Excluding net settlements on commodity derivatives
Crude oil (per Bbl)	$	39.96	$	40.14
Natural gas (per Mcf)	1.77		2.04
NGLs (per Bbl)	11.80		10.72

Based on a sensitivity analysis as of December 31, 2016, it was estimated that a 10 percent increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in a decrease in the fair value of our derivative positions of $87.0 million, whereas a 10 percent decrease in prices would have resulted in an increase in fair value of $86.7 million.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties.

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

Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions, and end-users in various industries. The underlying operations of these entities are however geographically concentrated in the same region, which increases the credit risk associated with this segment. As natural gas prices continue to remain depressed, certain third-party producers relating to our Gas Marketing segment are continuing 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 segment.

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 CommodityDerivative Financial Instruments to our 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 December 31, 2016, it does not consider those exposures or positions which could arise after that date. Our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information
Financial Statements:
Report of Independent Registered Public Accounting Firm	64
Consolidated Balance Sheets - December 31, 2016 and 2015	65
Consolidated Statements of Operations - Years Ended December 31, 2016, 2015 and 2014	66
Consolidated Statements of Cash Flows - Years Ended December 31, 2016, 2015 and 2014	67
Consolidated Statements of Equity - Years Ended December 31, 2016, 2015 and 2014	68
Notes to Consolidated Financial Statements	69
Supplemental Information - Unaudited:
Crude Oil and Natural Gas Information	97
Quarterly Financial Information	103
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts	104

63

Report of Independent Registered Public Accounting Firm

Tothe Board of Directors and Shareholders of PDC Energy, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows, and equity present fairly, in all material respects, the financial position of PDC Energy, Inc. and its subsidiaries at December 31, 2016 and December 31, 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the three years ended December 31, 2016, appearing under Item 8, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Annual Report on Internal Control over Financial Reporting, management has excluded certain Delaware Basin acquisitions from their assessment of internal control over financial reporting as of December 31, 2016, because they were acquired by the Company in a purchase business combination during 2016. We have also excluded these acquisitions from our audit of internal control over financial reporting. The acquisitions are wholly owned subsidiaries whose total assets and total revenues represent 11% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2016.

/s/PricewaterhouseCoopers LLP

Denver, Colorado

February 28, 2017

64

PDC ENERGY, INC.

Consolidated Balance Sheets

(in thousands, except share and per share data)

As of December 31,	2016			2015
Assets
Current assets:
Cash and cash equivalents	$	244,100		$	850
Accounts receivable, net	143,392			104,274
Fair value of derivatives	8,791			221,659
Prepaid expenses and other current assets	3,542			5,266
Total current assets	399,825			332,049
Properties and equipment, net	4,008,266			1,940,552
Fair value of derivatives	2,386			44,387
Goodwill	62,041			—
Other assets	13,324			53,555
Total Assets	$	4,485,842		$	2,370,543
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	66,322		$	92,613
Production tax liability	24,767			26,524
Fair value of derivatives	53,595			1,595
Funds held for distribution	71,339			29,894
Current portion of long-term debt	—			112,940
Accrued interest payable	15,930			9,057
Other accrued expenses	38,625			28,709
Total current liabilities	270,578			301,332
Long-term debt	1,043,954			529,437
Deferred income taxes	400,867			143,452
Asset retirement obligations	82,612			84,032
Fair value of derivatives	27,595			695
Other liabilities	37,482			24,398
Total liabilities	1,863,088			1,083,346
Commitments and contingent liabilities
Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,704,568 and 40,174,776 issued as of December 31, 2016 and 2015, respectively	657			402
Additional paid-in capital	2,489,557			907,382
Retained earnings	134,208			380,422
Treasury shares - at cost, 28,763 and 20,220 as of December 31, 2016 and 2015, respectively	(1,668		)	(1,009		)
Total stockholders' equity	2,622,754			1,287,197
Total Liabilities and Stockholders' Equity	$	4,485,842		$	2,370,543

See accompanying Notes to Consolidated Financial Statements

65

PDC ENERGY, INC.

Consolidated Statements of Operations

(in thousands, except per share data)

Year Ended December 31,	2016			2015			2014
Revenues
Crude oil, natural gas, and NGLs sales	$	497,353		$	378,713		$	471,413
Sales from gas marketing	8,725			10,920			71,571
Commodity price risk management gain (loss), net of settlements	(125,681		)	203,183			310,304
Other income	2,518			2,510			2,919
Total revenues	382,915			595,326			856,207
Costs, expenses and other
Lease operating expenses	59,950			56,992			42,402
Production taxes	31,410			18,443			25,615
Transportation, gathering and processing expenses	18,415			10,151			4,592
Cost of gas marketing	10,193			11,717			72,015
Exploration expense	4,669			1,102			947
Impairment of properties and equipment	9,973			161,620			166,847
General and administrative expense	112,470			89,959			123,559
Depreciation, depletion and amortization	416,874			303,258			192,528
Provision for uncollectible notes receivable	44,038			—			—
Accretion of asset retirement obligations	7,080			6,293			3,415
(Gain) loss on sale of properties and equipment	(43		)	(385		)	507
Total cost, expenses and other	715,029			659,150			632,427
Income (loss) from operations	(332,114		)	(63,824		)	223,780
Interest expense	(61,972		)	(47,571		)	(47,842		)
Interest income	963			4,807			1,290
Income (loss) before income taxes	(393,123		)	(106,588		)	177,228
Income tax benefit (expense)	147,195			38,308			(69,967		)
Income (loss) from continuing operations	(245,928		)	(68,280		)	107,261
Income from discontinued operations, net of tax	—			—			48,174
Net income (loss)	$	(245,928	)	$	(68,280	)	$	155,435
Earnings per share:
Basic
Income (loss) from continuing operations	$	(5.01	)	$	(1.74	)	$	3.00
Income from discontinued operations, net of tax	—			—			1.34
Basic	$	(5.01	)	$	(1.74	)	$	4.34
Diluted
Income (loss) from continuing operations	$	(5.01	)	$	(1.74	)	$	2.93
Income from discontinued operations, net of tax	—			—			1.31
Diluted	$	(5.01	)	$	(1.74	)	$	4.24
Weighted-average common shares outstanding:
Basic	49,052			39,153			35,784
Diluted	49,052			39,153			36,678

See accompanying Notes to Consolidated Financial Statements

66

PDC ENERGY, INC.

Consolidated Statements of Cash Flows

(in thousands)

Year Ended December 31,	2016			2015			2014
Cash flows from operating activities:
Net income (loss)	$	(245,928	)	$	(68,280	)	$	155,435
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	333,770			35,791			(311,281		)
Depreciation, depletion and amortization	416,874			303,258			201,656
Provision for uncollectible notes receivable	44,038			—			—
Impairment of properties and equipment	9,973			161,620			167,280
Accretion of asset retirement obligation	7,080			6,293			3,455
Stock-based compensation	19,502			20,068			17,518
Excess tax benefits from stock-based compensation	—			(1,361		)	(1,999		)
Gain from sale of properties and equipment	(43		)	(385		)	(75,972		)
Amortization of debt discount and issuance costs	16,167			7,040			6,938
Deferred income taxes	(137,249		)	(41,415		)	88,474
Other	2,603			(1,855		)	(1,329		)
Total adjustments to net income (loss) to reconcile to net cash from operating activities:	712,715			489,054			94,740
Changes in assets and liabilities:
Accounts receivable	(32,627		)	24,769			(34,598		)
Other assets	2,303			(2,264		)	(3,296		)
Restricted cash	—			46			2,214
Production tax liability	9,223			(1,629		)	3,358
Accounts payable and accrued expenses	(162		)	(30,310		)	21,453
Funds held for future distribution	36,510			2,699			(4,372		)
Other liabilities	4,229			(3,012		)	1,755
Total changes in assets and liabilities	19,476			(9,701		)	(13,486		)
Net cash from operating activities	486,263			411,073			236,689
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(436,884		)	(599,546		)	(623,750		)
Capital expenditures for other properties and equipment	(3,464		)	(5,122		)	(4,842		)
Acquisition of crude oil and natural gas properties, net of cash acquired	(1,073,723		)	—			—
Proceeds from sale of properties and equipment, net	4,945			405			154,457
Net cash from investing activities	(1,509,126		)	(604,263		)	(474,135		)
Cash flows from financing activities:
Proceeds from sale of equity, net of issuance costs	855,074			202,851			—
Proceeds from senior notes, net of issuance costs	392,172			—			—
Proceeds from convertible senior notes, net of issuance costs	193,935			—			—
Proceeds from revolving credit facility	85,000			397,000			263,750
Repayment of revolving credit facility	(122,000		)	(416,000		)	(200,000		)
Redemption of convertible notes	(115,000		)	—			—
Payment of debt issuance costs	(15,556		)	(974		)	(88		)
Excess tax benefits from stock-based compensation	—			1,361			1,999
Purchase of treasury shares	(6,935		)	(6,056		)	(5,392		)
Other	(577		)	(208		)	—
Net cash from financing activities	1,266,113			177,974			60,269
Net change in cash and cash equivalents	243,250			(15,216		)	(177,177		)
Cash and cash equivalents, beginning of year	850			16,066			193,243
Cash and cash equivalents, end of year	$	244,100		$	850		$	16,066
Supplemental cash flow information:
Cash payments for:
Interest, net of capitalized interest	$	43,406		$	45,642		$	46,809
Income taxes, net of refunds	167			10,049			1,800
Non-cash investing activities:
Issuance of common stock for acquisition of crude oil and natural gas properties related to Delaware Basin acquisition	690,702			—			—
Change in accounts payable related to capital expenditures	(40,448		)	(45,230		)	39,667
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal	4,894			14,030			33,250
Change in other assets related to sale of properties and equipment	—			—			39,048
Purchase of properties and equipment under capital leases	1,404			1,601			—
See footnote titled Business Combinations for non-cash transactions related to our acquisitions.

See accompanying Notes to Consolidated Financial Statements

67

PDC ENERGY, INC.

Consolidated Statements of Equity

(in thousands, except share data)

	Common Stock							Treasury Stock
	Shares		Amount		Additional Paid-in Capital			Shares		Amount			Retained Earnings			Total Stockholders' Equity
Balances, January 1, 2014	35,675,656		$	357	$	674,211		(5,508	)	$	(241	)	$	293,267		$	967,594
Net income	—		—		—			—		—			155,435			155,435
Purchase of treasury shares	—		—		—			(97,646	)	(5,392		)	—			(5,392		)
Issuance of treasury shares	—		—		(4,817		)	83,208		4,817			—			—
Retirement of treasury shares	(703	)	—		(35		)	703		35			—			—
Non-employee directors' deferred compensation plan	—		—		—			(2,400	)	(130		)	—			(130		)
Issuance of stock awards, net of forfeitures	253,032		2		—			—		—			—			2
Stock-based compensation expense, including tax impact	—		—		19,850			—		—			—			19,850
Balances, December 31, 2014	35,927,985		$	359	$	689,209		(21,643	)	$	(911	)	$	448,702		$	1,137,359
Net loss	—		—		—			—		—			(68,280		)	(68,280		)
Issuance pursuant to sale of equity	4,002,000		40		202,811			—		—			—			202,851
Purchase of treasury shares	—		—		—			(120,864	)	(6,055		)	—			(6,055		)
Issuance of treasury shares	—				(6,206		)	127,159		6,206			—			—
Non-employee directors' deferred compensation plan	—		—		—			(4,872	)	(249		)	—			(249		)
Issuance of stock awards, net of forfeitures	237,071		3		—			—		—			—			3
Exercise of stock options	7,720		—		—			—		—			—			—
Stock-based compensation expense, including tax impact	—		—		21,568			—		—			—			21,568
Balances, December 31, 2015	40,174,776		$	402	$	907,382		(20,220	)	$	(1,009	)	$	380,422		$	1,287,197
Net loss	—		—		—			—		—			(245,928		)	(245,928		)
Issuance pursuant to acquisition	9,386,768		94		690,608			—		—			—			690,702
Issuance pursuant to sale of equity	15,007,500		150		854,933			—		—			—			855,083
Issuance pursuant to note conversion	792,406		8		(8		)	—		—			—			—
Convertible debt discount, net of issuance costs and tax	—		—		23,518			—		—			—			23,518
Purchase of treasury shares	—		—		—			(116,085	)	(6,935		)	—			(6,935		)
Issuance of treasury shares	(114,697	)	—		(6,661		)	114,697		6,661			—			—
Non-employee directors' deferred compensation plan	—		—		—			(7,155	)	(385		)	—			(385		)
Issuance of stock awards, net of forfeitures	411,731		3		(3		)	—		—			—			—
Exercise of stock options	46,084		—		—			—		—			—			—
Stock-based compensation expense	—		—		19,502			—		—			—			19,502
Adoption of updated stock-based compensation accounting	—		—		286			—		—			(286		)	—
Balances, December 31, 2016	65,704,568		$	657	$	2,489,557		(28,763	)	$	(1,668	)	$	134,208		$	2,622,754

See accompanying Notes to Consolidated Financial Statements

68

PDC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 acquires, produces, develops, and explores for crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and, beginning in December 2016, the Delaware Basin in Reeves and Culberson Counties, Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays, our Delaware Basin operations are currently focused in the Wolfcamp zones, and our Ohio operations are focused in the Utica Shale play. As of December 31, 2016, we owned an interest in approximately 2,900 productive gross wells. We are engaged in two business segments: The Oil and Gas Exploration and Production Segment and the Gas Marketing Segment. In October 2014, we sold our entire 50 percent ownership interest in our joint venture, PDCM, to an unrelated third-party.

The audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries PDC Permian, Inc. and Riley Natural Gas ("RNG"), our proportionate share of our four affiliated partnerships and, for the information presented covering the year ended December 31, 2014, our proportionate share of PDCM. All material intercompany accounts and transactions have been eliminated in consolidation.

The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas, and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; impairment of proved and unproved properties; valuation and allocations of purchased businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.

Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas, and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes.

All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose for issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of gas marketing. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows.

The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below.

Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have three units-of-production fields which are the Wattenberg Field, the Delaware Basin, and the Utica Shale. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations, and common cost environments in these areas. We calculate quarterly depreciation, depletion, and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statements of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A.

Exploration costs, including geological and geophysical expenses, seismic costs on unproved leasehold, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but

69

PDC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability, or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded.

Proved Property Impairment. Upon a triggering event and when general industry conditions warrant review, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas, and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices, or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A.

Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates, and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.

Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment.

The following table presents the estimated useful lives of our other property and equipment:

Transportation, pipeline, and other equipment	2 - 30 years
Buildings	20 - 40 years

Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $3.8 million, $4.5 million, and $4.1 million in 2016, 2015, and 2014, respectively.

Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $4.5 million, $5.1 million, and $3.5 million in 2016, 2015, and 2014, respectively.

Goodwill. Goodwill represents the residual value of purchase price over net tangible and identifiable intangible assets of an acquired business and is stated at cost. Goodwill is not amortized; rather it is assessed annually for impairment, or more frequently if any event indicates that the carrying amount of goodwill may be impaired.

Assets Held for Sale and Discontinued Operations. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by

70

PDC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

third parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. Assets held for sale of $5.3 million as of December 31, 2016, represents the fair value of field office facilities and a parcel of land. Assets held for sale of $2.9 million as of December 31, 2015, represents the fair value of a parcel of land. These amounts are included in properties and equipment, net on our consolidated balance sheets.

For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations.

Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem, and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas, and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed and included in the statement of operations line item production taxes. Affiliated partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $29.0 million and $19.0 million in December 31, 2016 and 2015, respectively.

Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2016 and 2015, we had no valuation allowance.

Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes, and the 2022 Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving credit facility are included in other accrued expenses on the consolidated balance sheets.

Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations.

Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.

Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below.

Crude oil, natural gas, and NGLs sales. Crude oil, natural gas, and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred, and collection of revenue is reasonably assured. Our crude oil, natural gas, and NGLs sales are recorded under either the "net-back" or "gross" method of accounting, depending upon the transportation, gathering or processing method used. We use the net-back method of accounting for a portion of our crude oil production in the Wattenberg Field and for substantially all crude oil production in the Delaware Basin and the Utica Shale, as well as natural gas and NGLs from the Delaware Basin and the Wattenberg Field as the majority of the purchasers of these commodities also provide transportation, gathering, and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the gross method of accounting for Wattenberg Field crude oil delivered through the White Cliffs and Saddle Butte pipelines 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. Under this method, we recognize revenues based on the gross selling price.

Gas marketing. Gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our gas marketing subsidiary, RNG, suppliers, and customers. RNG purchases gas from many small producers and bundles the gas together for a

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price advantage to sell in larger amounts to purchasers of gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled commodity derivatives of the RNG commodity-based derivative transactions for gas marketing are included in sales from or cost of gas marketing, as applicable.

Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses and assets. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices, and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.

In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value.

We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2016, 2015, or 2014.

Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas, and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs, and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations.

Recently Adopted Accounting Standards.

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

In March 2016, the FASB issued an accounting update on stock-based compensation that is intended to simplify several aspects of the accounting for employee share-based payment award transactions. Areas of simplification include income tax consequences, classification of the awards as either equity or liabilities and the classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. We early adopted this standard in the fourth quarter of 2016.

• The primary impact of the adoption was the recognition of excess tax benefits in our provision for income taxes rather than additional paid-in capital, as well as the adjustment in stock-based compensation expense as a result of our changes in forfeiture policy. The new guidance eliminates the requirement to delay the recognition of excess tax benefits until it reduces current taxes payable. We adopted this change on a prospective basis, and recorded unrecognized excess tax benefits amounting to $1.5 million, which increased retained earnings in the fourth quarter of 2016.

• The new guidance also requires us to record, subsequent to the adoption, excess tax benefits and tax deficiencies in the period they occur. Prior to the adoption, the excess tax benefits would have been recorded as APIC. This change could create future volatility in our effective tax rate depending upon the amount of exercise or vesting activity from our stock awards. Under the new guidance,

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we have elected to change our policy and have started to recognize forfeitures of awards as they occur. The change in forfeiture policy was adopted using a modified retrospective transition method. We recorded a cumulative-effect adjustment to decrease retained earnings by $0.3 million upon transition on January 1, 2016, and an increase of stock-based compensation of $0.1 million during the fourth quarter of 2016. Per the guidance in the accounting standard update, the adjustment to stock-based compensation should be recorded on a retrospective basis. Our adjustment was not material to our condensed consolidated financial statements, therefore, we recorded the entire adjustment in the fourth quarter of 2016.

• The amendment to the minimum statutory withholding tax requirements was adopted on a modified retrospective basis. The adoption had no impact on retained earnings.

• In addition, we adopted the presentation of taxes paid related to the net share settlement as a financing activity on the statement of cash flows on a retrospective basis. Adoption had no impact to any of the periods presented in our consolidated cash flows statements since such cash flows have historically been presented as a financing activity.

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 underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (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. In March 2016, the FASB issued an update to the standard intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations when recognizing revenue. In December 2016, the FASB issued technical corrections and improvements to the standard. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are in the process of assessing potential impacts of the new standard on our existing revenue recognition criteria, as well as on related revenue disclosures.

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 in the process of assessing 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. This is an expansive set of revisions to the cash flow presentation standards, but at this time we do not believe that these changes will impact our consolidated financial statements.

NOTE 3 - BUSINESS COMBINATION

Delaware Basin Acquisition completed December 6, 2016. On December 6, 2016, we closed on an acquisition which has been accounted for as a business combination. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion, comprised of approximately $952.1 million in cash, including the repayment of $40.0 million of debt from the seller 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.

.

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

	Year Ended December 31, 2016
Acquisition costs:
Cash, net of cash acquired	$	912,142
Retirement of seller's debt	40,000
Total cash consideration	952,142
Common stock, 9.4 million shares	690,702
Other purchase price adjustments	1,026
Total acquisition costs	$	1,643,870
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	8,201
Crude oil and natural gas properties - proved	216,000
Crude oil and natural gas properties - unproved	1,721,334
Infrastructure, pipeline, and other	32,590
Construction in progress	12,148
Goodwill	62,041
Total assets acquired	2,052,314
Liabilities assumed:
Current liabilities	(24,844		)
Asset retirement obligations	(3,705		)
Deferred tax liabilities, net	(379,895		)
Total liabilities assumed	(408,444		)
Total identifiable net assets acquired	$	1,643,870

The estimated fair value of assets acquired and liabilities assumed in the acquisition presented above are preliminary and subject to post-closing adjustments as more detailed analysis associated with the acquired properties are completed. As of the date of this report, we expect that it may take into mid-2017 until all post-closing adjustments are finalized.

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, and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are 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 is calculated as the excess of the purchase price over the fair value of net assets acquired 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. Goodwill related to the Delaware Basin acquisition was recorded in our oil and gas exploration and production segment. Any value assigned to goodwill is not expected to be deductible for income tax purposes.

Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total revenue and $1.7 million of loss from operations. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2016 and December 31, 2015, assuming the acquisition had been completed as of January 1, 2015. This pro forma financial information includes the Securities Issuances in September 2016, the shares issued to the sellers, and other acquisition costs. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.

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	Years Ended December 31,
	2016			2015
	(in thousands, except per share amounts)
Total revenue	$	412,746		$	598,932
Net loss	$	(270,942	)	$	(138,904	)
Earnings (loss) per share:
Basic and diluted	$	(4.22	)	$	(2.41	)

NOTE 4 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net of accumulated DD&A:

	As of December 31,
	2016			2015
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	3,499,718		$	2,881,189
Unproved	1,874,671			60,498
Total crude oil and natural gas properties	5,374,389			2,941,687
Infrastructure, pipeline, and other	62,093			30,098
Land and buildings	12,165			12,667
Construction in progress	122,591			113,115
Properties and equipment, at cost	5,571,238			3,097,567
Accumulated DD&A	(1,562,972		)	(1,157,015		)
Properties and equipment, net	$	4,008,266		$	1,940,552

Delaware Basin Acreage Acquisition. On December 30, 2016, we closed the purchase of approximately an additional 4,600 net bolt-on acres in Reeves and Culberson Counties, Texas, for consideration to the sellers of approximately $120.6 million, in cash, subject to post-closing adjustments. The transaction was accounted for as an acquisition of assets.

Acreage Exchange. In September 2016, we closed on an acreage exchange transaction with Noble Energy, Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The assets exchanged were all in the same unit of production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged.

The following table presents impairment charges recorded for properties and equipment:

	Year Ended December 31,
	2016		2015		2014
	(in thousands)
Impairment of proved and unproved properties	$	5,562	$	154,608	$	161,604
Amortization of individually insignificant unproved properties	1,379		7,012		4,465
Land and buildings	3,032		—		778
Impairment of properties and equipment	9,973		161,620		166,847
Discontinued operations:
Impairment of proved and unproved properties	—		—		433
Total discontinued operations	—		—		433
Total impairment of properties and equipment	$	9,973	$	161,620	$	167,280

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Due to a significant decline in commodity prices and decreases in our net realized sales prices, we experienced triggering events during 2015 and 2014 that required us to assess our crude oil and natural gas properties for possible impairment.  As a result of our assessments, we recorded impairment charges of $150.3 million and $158.3 million in 2015 and 2014, respectively, to write-down our Utica Shale proved and unproved properties.  Of these impairment charges, $24.7 million and $112.6 million were recorded in 2015 and 2014, respectively, to write-down certain capitalized well costs on our Utica Shale proved producing properties. In 2015 and 2014, we also recorded impairment charges of $125.6 million and $45.7 million to write-down our Utica Shale lease acquisition costs.  The impairment charges, which are included in the consolidated statements of operations line item impairment of properties and equipment, represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair values.  We continued to monitor whether any further impairments were triggered and required measurement throughout 2016 given the continued volatility of commodity prices and the continued capital investment in the development and acquisition of oil and gas properties. No such triggering events occurred during 2016. Impairment charges in 2016 relate to the write-off of certain leases that were no longer part of our development plan and to reflect the fair value of other land and buildings that is held for sale as of December 31, 2016.

Suspended Well Costs

As of December 31, 2016 and 2015, there were no suspended well costs or wells pending determination.

NOTE 5 - 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 and natural gas, we utilize the following economic hedging strategies for each of our business segments.

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

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

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2016, we had derivative instruments, which were comprised of collars, fixed-price commodity swaps, basis protection swaps, and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 81,720 BBtu of natural gas and 13,342 MBbls of crude oil. The commodity derivative contracts were entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices.

As of December 31, 2016, our derivative instruments were comprised of collars, fixed-price commodity swaps, basis protection swaps, and physical sales and purchases.

• Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty;

• Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty;

• Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of 2016, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and

• Physical sales and purchases are commodity derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical commodity derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale.

We have elected not to designate any of our derivative instruments as cash flow hedges, and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in

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commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of gas marketing.

The following table presents the balance sheet location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2016 and 2015:

Derivative instruments:		Consolidated Balance sheet line item	2016		2015
			(in thousands)
Derivative assets:	Current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	$	8,239	$	221,161
	Related to gas marketing	Fair value of derivatives	251		441
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	301		57
			8,791		221,659
	Non-current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	1,104		44,292
	Related to gas marketing	Fair value of derivatives	19		51
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	1,263		44
			2,386		44,387
Total derivative assets			$	11,177	$	266,046
Derivative liabilities:	Current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	$	53,353	$	—
	Related to gas marketing	Fair value of derivatives	212		417
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	30		1,178
			53,595		1,595
	Non-current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	27,581		275
	Related to gas marketing	Fair value of derivatives	14		46
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	—		374
			27,595		695
Total derivative liabilities			$	81,190	$	2,290

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

	Year Ended December 31,
Consolidated statements of operations line item	2016			2015			2014
	(in thousands)
Commodity price risk management gain (loss), net -
Net settlements	$	208,103		$	238,935		$	(837	)
Net change in fair value of unsettled derivatives	(333,784		)	(35,752		)	311,141
Total commodity price risk management gain (loss), net	$	(125,681	)	$	203,183		$	310,304
Sales from gas marketing -
Net settlements	$	543		$	778		$	(208	)
Net change in fair value of unsettled derivatives	(676		)	(318		)	364
Total sales from gas marketing	$	(133	)	$	460		$	156
Cost of gas marketing -
Net settlements	$	(483	)	$	(745	)	$	346
Net change in fair value of unsettled derivatives	690			279			(451		)
Total cost of gas marketing	$	207		$	(466	)	$	(105	)

All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets.

The following table reflects the impact of netting agreements on gross derivative assets and liabilities:

As of December 31, 2016	Derivative instruments, recorded in 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

As of December 31, 2015	Derivative instruments, recorded in consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	266,046	$	(1,921	)	$	264,125
Liability derivatives:
Derivative instruments, at fair value	$	2,290	$	(1,921	)	$	369

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

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

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

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

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

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

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

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

	As of December 31,
	2016									2015
	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)
Total assets	$	6,350		$	4,827		$	11,177		$	174,758	$	91,288	$	266,046
Total liabilities	66,789			14,401			81,190			2,290		—		2,290
Net asset (liability)	$	(60,439	)	$	(9,574	)	$	(70,013	)	$	172,468	$	91,288	$	263,756

The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value:

	2016			2015			2014
	(in thousands)
Fair value of Level 3 instruments, net asset beginning of period	$	91,288		$	62,356		$	1,111
Changes in fair value included in consolidated statement of operations line item:
Commodity price risk management gain (loss), net	(28,530		)	65,018			62,003
Sales from gas marketing	(20		)	146			(22		)
Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net	(72,242		)	(36,169		)	(737		)
Sales from gas marketing	(70		)	(63		)	1
Fair value of Level 3 instruments, net asset (liability) end of period	$	(9,574	)	$	91,288		$	62,356
Net change in fair value of Level 3 unsettled derivatives included in statement of operations line item:
Commodity price risk management gain (loss), net	$	(12,905	)	$	43,540		$	15,632
Sales from gas marketing	—			—			3
Total	$	(12,905	)	$	43,540		$	15,635

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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 the financial statements.

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 for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. 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, natural gas and NGLs will be sold.

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 or convertible 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 December 31, 2016:

	Estimated Fair Value		% of Par
	(in millions)
Senior notes:
2021 Convertible Notes	$	220.2	110.1	%
2024 Senior Notes	408.0		102.0	%
2022 Senior Notes	535.0		107.0	%

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 vehicle lease.

NOTE 7 - CONCENTRATION OF RISK

Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts:

	As of December 31,
	2016			2015
	(in thousands)
Crude oil, natural gas and NGLs sales	$	97,520		$	41,873
Joint interest billings	20,118			35,017
Derivative counterparties	10,266			24,437
Income tax receivable	11,505			—
Insurance reimbursement	—			879
Other	6,173			4,077
Allowance for doubtful accounts	(2,190		)	(2,009		)
Accounts receivable, net	$	143,392		$	104,274

Our accounts receivable primarily relate to sales of our crude oil, natural gas, and NGLs production, receivable balances from other third parties that own working interests in the properties we operate, and derivative counterparties. For the years ended December 31, 2016 and 2015, amounts written off to allowance for doubtful accounts were not material. As of December 31, 2016, we had no customers representing 10 percent or greater of our accounts receivable balance. As of December 31, 2015, we had one customer representing 10 percent or greater of our accounts receivable balance.

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Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues:

	Year Ended December 31,
Customer	2016		2015		2014
Suncor Energy Marketing, Inc.	22.3	%	14.3	%	19.7	%
DCP Midstream, LP	20.2	%	13.2	%	15.1	%
Aka Energy Group, LLC	13.4	%	—	%	—	%
Concord Energy, LLC	13.4	%	23.2	%	18.3	%
Bridger Energy, LLC	11.5	%	—	%	—	%
Shell Trading Company	—	%	13.8	%	—	%
Teppco Crude Oil, LLC	—	%	—	%	12.9	%

The concentration of revenue represented by the customers noted above relate to our oil and gas exploration and production segment.

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; however, 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 December 31, 2016, taking into account the estimated likelihood of nonperformance.

Note Receivable

The following table presents information regarding our note receivable outstanding:

	As of December 31,
	2016			2015
	(in thousands)
Principal and PIK Interest outstanding at beginning of period	$	43,069		$	39,707
PIK Interest	969			3,362
Principal and PIK Interest outstanding at end of period	44,038			43,069
Allowance for uncollectible notes receivable	(44,038		)	—
Note receivable, net	$	—		$	43,069

In October 2014, we sold our entire 50 percent ownership interest in PDCM to an unrelated third-party as described in the footnote titled Divestiture and Discontinued Operations. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million, bearing varying interest rates beginning at eight percent and increasing annually. Pursuant to the Note agreement, interest shall be paid quarterly, in arrears, commencing December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. Through December 31, 2016, the issuer of the Note had elected the PIK Interest option for each quarterly period since inception. The principal and any unpaid interest shall be due and payable in full in September 2020 and can be prepaid in whole or in part at any time, and in certain circumstances must be repaid prior to maturity. Any such prepayment will be made without premium or penalty. Legally, the Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets; however, we believe that the collection of the Note is not reasonably assured.

We examine the Note for evidence of collectability, evaluating factors such as the creditworthiness of the issuer of the Note and the value of the underlying assets that secure the Note. We performed our evaluation and cash flow analysis during the first quarter of 2016 and, based upon the year-end financial statements for 2015, the crude oil and natural gas reserve report of the issuer of the Note, and existing market conditions, determined that collection of the Note and PIK Interest was not reasonably assured. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million outstanding balance as of March 31, 2016, which was included in the consolidated balance sheet line item other assets. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Note and began accounting for the interest on the Note under the cash basis method. To date, we have not received any interest payments. As of December 31, 2016, there has been no change to our assessment of the collectibility of the Note or related interest,

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and continue to believe collection is not reasonably assured. Under the effective interest method, we previously recognized $4.5 million of interest income for the year ended December 31, 2015, of which $3.4 million was PIK Interest. As of December 2015, the $43.1 million outstanding balance on the Note was included in the consolidated balance sheet line item other assets.

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

	As of December 31,
	2016		2015
	(in thousands)
Employee benefits	$	22,282	$	17,774
Asset retirement obligations	9,775		5,460
Environmental expenses	3,238		4,143
Other	3,330		1,332
Other accrued expenses	$	38,625	$	28,709

NOTE 8 - INCOME TAXES

The table below presents the components of our provision for income taxes from continuing operations for the years presented:

	Year Ended December 31,
	2016		2015			2014
	(in thousands)
Current:
Federal	$	9,646	$	(2,944	)	$	(1,514	)
State	300		(163		)	966
Total current income tax benefit (expense)	9,946		(3,107		)	(548		)
Deferred:
Federal	118,427		37,352			(60,698		)
State	18,822		4,063			(8,721		)
Total deferred income tax benefit (expense)	137,249		41,415			(69,419		)
Income tax benefit (expense) from continuing operations	$	147,195	$	38,308		$	(69,967	)

The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations:

	Year Ended December, 31,
	2016		2015		2014
Statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net	2.6		2.7		2.8
Effect of state income tax rate changes	0.6		(0.3	)	—
Percentage depletion	—		0.3		(0.3	)
Non-deductible compensation	(0.5	)	(1.2	)	0.7
Excess tax benefits from stock-based compensation	0.4		—		—
Other	(0.7	)	(0.6	)	1.3
Effective tax rate	37.4	%	35.9	%	39.5	%

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Amendments related to accounting for excess tax benefits of stock-based compensation have been adopted prospectively, resulting in recognition of excess tax benefits against income tax expenses rather than APIC of $1.5 million for the year ended December 31, 2016. Excess tax benefits in the amount of $1.4 million were recognized as APIC during the year ended December 31, 2015, resulting from the vesting of stock-based compensation.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2016 and 2015 are presented below. Of note, the table includes the $403.7 million effect of including the deferred tax liability for the difference in the book and tax basis of the oil and gas properties acquired in the December 6, 2016, business combination and a $23.8 million of acquired deferred tax assets:

	As of December 31,
	2016		2015
	(in thousands)
Deferred tax assets:
Deferred compensation	$	9,338	$	13,104
Asset retirement obligations	34,359		34,101
Federal NOL carryforward	29,988		—
State NOL and tax credit carryforwards, net	5,189		3,376
Alternative minimum tax - credit carryforward	5,184		2,812
Allowance for note receivable	17,292		—
Net change in fair value of unsettled derivatives	26,262		—
Other	4,716		3,412
Total gross deferred tax assets	132,328		56,805
Deferred tax liabilities:
Properties and equipment	518,964		99,191
Net change in fair value of unsettled derivatives	—		100,369
Convertible debt	14,231		697
Total gross deferred tax liabilities	533,195		200,257
Net deferred tax liability	$	400,867	$	143,452

Deferred tax assets increased in 2016, primarily due to the allowance for a note receivable, acquired federal NOL from the stock acquisition component of the Delaware Basin acquisition, current year generated NOL and the reduced fair value of unsettled derivatives.

Deferred tax liabilities increased in 2016, primarily due to the deferred tax liability arising from the excess book basis versus tax carryover basis of the properties and equipment relating to the stock acquisition component of the Delaware Basin acquisition. Deferred tax liabilities also increased due to the 2021 Convertible Notes and accelerated deductions on properties and equipment. These were partially offset by the settlement of commodity derivatives and the decrease in fair value of unsettled commodity derivatives.

During the year ending December 31, 2016, we generated a federal NOL of $55.4 million of which $32.2 million will be utilized as a carryback leaving a federal NOL carryforward of $23.1 million that will begin to expire in 2036, and we have alternative minimum tax credits of $5.2 million that may be carried forward indefinitely. Also, we acquired a federal NOL of $62.5 million as a component of the Delaware Basin acquisition that will begin to expire in 2034 which is subject to an annual limitation of $15.1 millionas a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382.

As of December 31, 2016, we have state NOL carryforwards of $130.5 million that begin to expire in 2030 and state credit carryforwards of $1.8 million that begin to expire in 2022.

Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2016. The total amount of unrecognized tax benefits that would affect the effective tax rate decreased to zero in the current year due to a settlement with the IRS on a tax filing position related to our 2014 federal tax return. The statutes of limitations for most of our state tax jurisdictions are open from 2012 forward.

The IRS fully accepted our recently filed 2015 return, with minor agreed-upon adjustments, after the IRS CAP post-filing review process was completed in early January 2017. We are currently participating in the CAP Program for the review of our 2016 and 2017 tax years. Participation in the CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings.

There has been increased discussion by the federal government of a potential reduction of the corporate income tax rate and corresponding changes to the tax code. In the event of a change in federal or state income tax rates, the impact of the rate change will be required to be recorded through deferred income tax expense. Should statutory income tax rates decrease, our deferred tax liability will

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decrease, resulting in deferred tax benefit for the period. If the statutory income tax rates increase, our deferred tax liability would increase resulting in a deferred tax expense.

As of December 31, 2016, we were current with our income tax filings in all applicable state jurisdictions.

NOTE 9 - LONG-TERM DEBT

Long-term debt consists of the following:

	As of December 31,
	2016			2015
	(in thousands)
Senior notes:
1.125% Convertible Notes due 2021:
Principal amount	$	200,000		$	—
Unamortized discount	(37,475		)	—
Unamortized debt issuance costs	(4,584		)	—
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs	157,941			—
6.125% Senior Notes due 2024:
Principal amount	400,000			—
Unamortized debt issuance costs	(7,544		)	—
6.125% Senior Notes due 2024, net of unamortized debt issuance costs	392,456			—
7.75% Senior notes due 2022:
Principal amount	500,000			500,000
Unamortized debt issuance costs	(6,443		)	(7,563		)
7.75% Senior notes due 2022, net of unamortized debt issuance costs	493,557			492,437
3.25% Convertible senior notes due 2016:
Principal amount	—			115,000
Unamortized discount	—			(1,852		)
Unamortized debt issuance costs	—			(208		)
3.25% Convertible senior notes due 2016, net of unamortized discount and debt issuance costs	—			112,940
Total senior notes	1,043,954			605,377
Revolving credit facility	—			37,000
Total debt, net of unamortized discount and debt issuance costs	1,043,954			642,377
Less current portion of long-term debt	—			112,940
Long-term debt	$	1,043,954		$	529,437

Senior Notes

2021 Convertible Notes.  In September 2016, we issued $200.0 million of 1.125% convertible senior notes due 2021 in a public offering. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016 between us and the U.S. Bank National Association, as trustee. 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, commencing on March 15, 2017. The 2021 Convertible Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the 2021 Convertible Notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The proceeds from the issuance of the 2021 Convertible Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin, to pay related fees and expenses, and for general corporate purposes.

The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to

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adjustment upon certain events. 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, as well as cash in lieu of fractional shares.

We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible.

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 for similar terms and priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of 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 and are being amortized as interest expense over the life of the notes using the effective interest method. As of December 31, 2016, 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%. Based upon the December 31, 2016 stock price of $72.58 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount.

2024 Senior Notes. In September 2016, we issued $400.0 million aggregate principal amount of 6.125% senior notes due September 2024 in a private placement to qualified institutional buyers. In connection with the issuance of the 2024 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms. In addition, we have agreed, in certain circumstances, to file a shelf registration statement covering the resale of the 2024 Senior Notes by the holders. The proceeds from the issuance of the 2024 Senior Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin (see the footnotes titled Business Combination and Properties and Equipment),to pay related fees and expenses, and for general corporate purposes.

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, commencing on March 15, 2017. 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. The 2024 Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.

The 2024 Senior Notes are redeemable after September 15, 2019, at fixed redemption prices beginning at 104.594 percent of the principal amount redeemed. At any time prior to September 15, 2019, we may redeem all or part of the 2024 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at September 15, 2019, and remaining interest payments on the 2024 Senior Notes at the time of redemption.

At any time prior to September 15, 2019, we may redeem up to 35 percent of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.

Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase.

The indenture governing the 2024 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries.

2022 Senior Notes. In October 2012, we issued $500.0 million aggregate principal amount 7.75% senior notes due October 15, 2022 in a private placement to qualified institutional buyers. The 2022 Senior Notes have been registered. 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

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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. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness and rank effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.

At any time prior to October 15, 2017, we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture. On or after October 15, 2017, we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption.

Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase.

The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company.

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

As of December 31, 2016, we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the foreseeable future.

2016 Convertible Senior Notes. In November 2010, we issued $115.0 million aggregate principal amount of 3.25% convertible senior notes due that were due in 2016 ("2016 Convertible Notes") in a private placement. The maturity for the payment of principal was May 15, 2016, and we paid the aggregate principal amount of the 2016 Convertible Notes, plus cash for the fractional shares, totaling approximately $115.0 million. Additionally, we issued 792,406 shares of common stock for the $47.9 million excess conversion value. See the footnote titled Common Stock for more information.

RevolvingCredit Facility

Revolving Credit Facility. Our revolving credit facility matures in May 2020. 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 provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base determination and subject to limitations under the 2022 Senior Notes. The amount available under the revolving credit facility is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size 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. The current borrowing base and aggregate commitments under the facility are $700 million.

    The weighted-average borrowing rate on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.7 percent and 2.6 percent per annum for the years ended December 31, 2016 and 2015, respectively. We capitalized $8.8 million and $3.6 million of debt issuance costs as of December 31, 2016 and 2015, respectively, related to our revolving credit facility which is included in other assets on the consolidated balance sheets.

We had no outstanding balance on our revolving credit facility as of December 31, 2016 compared to $37.0 million outstanding as of December 31, 2015. 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 greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus an applicable margin 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 December 31, 2016, the applicable margin is 1.25 percent, and the unused commitment fee is 0.50 percent. No principal payments are generally required until the credit agreement 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 1.00:1.00 and (b) not exceed a maximum leverage ratio of 4.00:1.00. Our borrowing base availability under the

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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 the applicable indenture. As of December 31, 2016, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the foreseeable future. As of December 31, 2016, our calculated debt to EBITDAX ratio was 2.10 and our current ratio was 5.00.

The revolving credit facility contains restrictions as to when we can directly or indirectly retire, redeem, repurchase, or prepay in cash any part of the principal of the 2021 Convertible Notes, 2022 Senior Notes, or 2024 Senior Notes. Among other things, the restriction on redemption of the 2021 Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement, or prepayment, the aggregate commitment under the revolving credit facility must exceed the aggregate credit exposure under such facility by at least an amount equal to or greater than 20 percent of such aggregate commitment.

As of December 31, 2016, RNG had issued an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit currently expires in September 2017 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of December 31, 2016, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $688.3 million.

NOTE 10 - 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 leased vehicles under capital leases:

	As of December 31,
	2016			2015
	(in thousands)
Vehicles	$	2,975		$	1,601
Accumulated depreciation	(776		)	(211		)
	$	2,199		$	1,390

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 December 31,	Amount
	(in thousands)
2017	$	914
2018	1,099
2019	560
	2,573
Less executory cost	(96		)
Less amount representing interest	(263		)
Present value of minimum lease payments	$	2,214
Short-term capital lease obligations	$	699
Long-term capital lease obligations	1,515
	$	2,214

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

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NOTE 11 - ASSET RETIREMENT OBLIGATIONS

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

	2016			2015
	(in thousands)
Balance at beginning of period	$	89,492		$	73,855
Obligations incurred with development activities and assumed with acquisitions	4,894			2,373
Accretion expense	7,080			6,293
Revisions in estimated cash flows	—			11,658
Obligations discharged with disposal of properties and asset retirements	(9,079		)	(4,687		)
Balance at end of period	92,387			89,492
Less current portion	(9,775		)	(5,460		)
Long-term portion	$	82,612		$	84,032

Our estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2016, 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.

The increase in the current portion of asset retirement obligations in 2016 is attributable to an increase in the number of wells to be plugged and abandoned to allow for the drilling of nearby horizontal wells. The revisions in estimated cash flows during 2015 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells.

NOTE 12 - EMPLOYEE BENEFIT PLANS

We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was$4.8 million, $4.9 million, and $3.9 millionfor 2016, 2015, and 2014, respectively.

NOTE 13 - COMMITMENTS AND CONTINGENCIES

Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales, and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. Our statements of operations reflect our share of these firm transportation costs. These contracts require us to pay these transportation and processing charges, whether or not the required volumes are delivered. As natural gas prices remain depressed, certain third-party producers under our Gas Marketing Segment have continued to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, no counterparty default losses have been material to us. In 2016 and 2015, we recorded an allowance for doubtful accounts of approximately $1.3 million and $0.5 million, respectively. 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.

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

	Year Ending December 31,
Area	2017		2018		2019		2020		2021 and Through Expiration		Total		Expiration Date
Natural gas (MMcf)
Wattenberg Field (1)	—		2,300		17,125		18,300		86,700		124,425		September 30, 2025
Gas Marketing segment	7,117		7,117		7,117		7,136		11,550		40,037		August 31, 2022
Utica Shale	2,738		2,738		2,738		2,745		7,064		18,023		July 22, 2023
Total	9,855		12,155		26,980		28,181		105,314		182,485
Crude oil (MBbls)
Wattenberg Field	2,413		2,413		2,413		1,204		—		8,443		June 30, 2020
Dollar commitment (in thousands)	$	17,158	$	18,626	$	33,221	$	27,430	$	89,896	$	186,331

__________

(1) In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities.  The midstream provider is expected to construct a new 200 MMcfd cryogenic plant.  We will be bound to the volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which in the above table is estimated to be September 30, 2018.  The agreement requires a baseline volume commitment of current sales volumes to this midstream provider and an incremental volume commitment of 50 MMcfd for seven years, of which we may be required to pay a shortfall fee for any volumes under the 50 MMcfd incremental commitment.  Any shortfall of this volume commitment may be offset, in part, by additional third party producers’ volumes sold to the midstream provider when a certain total volume is achieved. We are also required for the first three years of the contract to guarantee a certain target profit margin to the midstream provider on these volumes sold.  Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments.  Using the NYMEX forward pricing strip at December 31, 2016, the target profit margin would be achieved without an additional payment from us.

During 2016, 2015, and 2014, long-term firm transportation costs for our Gas Marketing segment as shown above were $3.4 million in each year and were recorded in cost of gas marketing in our consolidated statements of operations. For the years 2016, 2015, and 2014, commitments for long-term transportation volumes for Utica Shale natural gas and Wattenberg Field crude oil were $10.0 million, $4.7 million, and $0.3 million, respectively, and were recorded in transportation, gathering and processing expense in our consolidated statements of operations.

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. 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.

Class Action Regarding 2010 and 2011 Partnership Purchases

We finalized a settlement associated with the repurchase of certain partnership purchases in 2015. All required amounts associated with this settlement had been expensed in 2014.

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. We are not aware of any environmental claims existing as of December 31, 2016, 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 consolidated balance sheets.

In August 2015, we received the Information Request from the 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. The Information Request focuses on historical operation and design information for 46 of our production facilities and asks that we conduct sampling and analyses at the identified 46 facilities. We responded to the the Information Request in January 2016. Throughout 2016, we continued to meet with the EPA, Department of Justice, and Colorado Department of Public Health and Environment, and in December we received a draft consent decree from the EPA.

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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 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 operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. We are in the process of responding to the advisory, but cannot predict the outcome of this matter at this time.

Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space, and general office equipment.

The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2016:

	Year Ending December 31,
	2017		2018		2019		2020		2021		Thereafter		Total
	(in thousands)
Minimum Lease Payments	$	3,056	$	3,041	$	3,033	$	3,093	$	3,154	$	6,786	$	22,163

Operating lease expense for 2016, 2015, and 2014 was $10.2 million, $9.8 million, and $7.0 million, respectively.

NOTE 14 - COMMON STOCK

Sale of Equity Securities

We issued 9.4 million shares of common stock as partial consideration for 100 percent of the common stock of Arris Petroleum and for the acquisition of certain Delaware Basin properties on December 6, 2016. These shares are restricted for sale until June 6, 2017, due to previously-disclosed lock up agreements. Accordingly, the value of the shares was discounted from the market price on the date of issuance by 6 percent.

The following table provides a summary of our public offerings of common stock in 2016 and 2015:

Date	Shares Issued	Price per Share		Net Proceeds
				(in millions)
September 2016	9,085,000	$	61.51	$	558.5
March 2016	5,922,500	50.11		296.6
March 2015	4,002,000	50.73		202.9

Stock-Based Compensation Plans

2010 Long-Term Equity Compensation Plan. In June 2010, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued 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 stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of SARs, restricted stock, restricted stock units ("RSUs"), performance shares, and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock, and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2016, 839,052 shares remain available for issuance pursuant to the 2010 Plan.

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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:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Stock-based compensation expense	$	19,502		$	20,068		$	17,518
Income tax benefit	(7,296		)	(7,636		)	(5,955		)
Net stock-based compensation expense	$	12,206		$	12,432		$	11,563

Stock Appreciation Rights ("SARs")

The 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.

The Compensation Committee has awarded SARs to our executive officers in 2016, 2015, and 2014. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:

	Year Ended December 31,
	2016			2015			2014
Expected term of award	6.0 years			5.2 years			6.0 years
Risk-free interest rate	1.8		%	1.4		%	2.1		%
Expected volatility	54.5		%	58.0		%	65.6		%
Weighted-average grant date fair value per share	$	26.96		$	22.23		$	29.96

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 all periods presented:

	Year Ended December 31,
	2016							2015						2014
	Number of SARs		Weighted-Average Exercise Price		Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)		Number of SARs		Weighted-Average Exercise Price		Aggregate Intrinsic Value (in thousands)		Number of SARs	Weighted-Average Exercise Price		Aggregate Intrinsic Value (in thousands)
Outstanding beginning of year, January 1,	326,453		$	38.99	7.3	$	4,697	279,011		$	38.77	$	1,472	190,763	$	33.77	$	3,711
Awarded	58,709		51.63		—	—		68,274		39.63		—		88,248	49.57		—
Exercised	(141,084	)	40.16		—	2,770		(20,832	)	38.05		473		—	—		—
Outstanding at December 31,	244,078		41.36		6.9	7,620		326,453		38.99		4,697		279,011	38.77		1,472
Exercisable at December 31,	174,919		38.72		6.3	5,924		222,489		37.70		3,489		139,334	36.27		982

Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2016, was $1.5 million. The cost is expected to be recognized over a weighted-average period of 1.7 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 that a participant is continuously employed.

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The following table presents the changes in non-vested time-based awards during 2016:

	Shares		Weighted-Average Grant Date Fair Value
Non-vested at December 31, 2015	525,081		$	50.23
Granted	290,010		58.52
Vested	(317,034	)	48.61
Forfeited	(18,415	)	56.10
Non-vested at December 31, 2016	479,642		56.09

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

	As of/Year Ended December 31,
	2016		2015		2014
	(in thousands, except per share data)
Total intrinsic value of time-based awards vested	$	18,973	$	17,077	$	18,278
Total intrinsic value of time-based awards non-vested	34,812		28,029		23,290
Market price per common share as of December 31,	72.58		53.38		41.27
Weighted-average grant date fair value per share	58.52		48.88		56.45

Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2016 was $17.5 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.

In January 2016, the Compensation Committee awarded a total of 24,280 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total stockholder return ("TSR"), which is essentially the Company’s 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, 2018 and can result in a payout between 0 percent and 200 percent of the total shares awarded. As of December 31, 2016, we had approximately 48,000 non-vested market based restricted shares that could result in a payout between 0 and approximately 96,000 shares of our common stock. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions:

	Year Ended December 31,
	2016			2015
Expected term of award	3 years			3 years
Risk-free interest rate	1.2		%	0.9		%
Expected volatility	52.3		%	53.0		%
Weighted-average grant date fair value per share	$	72.54		$	66.16

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.

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The following table presents the change in non-vested market-based awards during 2016:

	Shares		Weighted-Average Grant Date Fair Value per Share
Non-vested at December 31, 2015	71,549		$	63.60
Granted	24,280		72.54
Vested	(47,409	)	66.78
Non-vested at December 31, 2016	48,420		64.97

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

	As of/Year Ended December 31,
	2016		2015		2014
	(in thousands, except per share data)
Total intrinsic value of market-based awards vested	$	6,562	$	4,293	$	1,260
Total intrinsic value of market-based awards non-vested	3,514		3,819		3,455
Market price per common share as of December 31,	72.58		53.38		41.27
Weighted-average grant date fair value per share	72.54		66.16		56.87

Total compensation cost related to non-vested market-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2016 was $1.7 million. This cost is expected to be recognized over a weighted-average period of 1.7 years.

Treasury Share Purchases

In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's 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 APIC. As of December 3, 2015, we had 9,009 shares remaining available for reissuance pursuant to our 2010 plan. Additionally, as of December 31, 2016 and 2015, we had 18,366 and 11,211, respectively, of shares of treasury stock related to a rabbi trust. During the year ended December 31, 2016, we acquired 116,085 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 114,697 shares were reissued and 10,397 shares are available for reissuance pursuant to our 2010 Plan.

Stockholders’ Rights Agreement

In 2007, we entered into a rights agreement designed to improve the ability of our Board to protect the interest of our stockholders in the event of an unsolicited takeover attempt.  The rights agreement and all rights were set to expire in September 2017.  In June 2016, we entered into an amendment to the rights agreement, which accelerated the expiration date from September 2017 to June 2016. Upon the expiration in June 2016, all of the rights distributed to holders of our common stock pursuant to the rights agreement expired. The amendment was entered into as a result of governance considerations and not in contemplation of any anticipated business combination or similar transaction.

Preferred stock

We are authorized, pursuant to stockholder approval in 2008, to issue 50,000,000 shares of preferred stock, par value $0.01, 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. As of December 31, 2016, no preferred shares had been issued.

NOTE 15 - 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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The following table presents a reconciliation of the weighted-average diluted shares outstanding:

	Year Ended December 31,
	2016	2015	2014
	(in thousands)
Weighted-average common shares outstanding - basic	49,052	39,153	35,784
Dilutive effect of:
Restricted stock	—	—	279
Convertible notes	—	—	564
Other equity-based awards	—	—	51
Weighted-average common shares and equivalents outstanding - diluted	49,052	39,153	36,678

For 2016 and 2015, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same 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:

	Year Ended December 31,
	2016	2015	2014
	(in thousands)
Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	689	831	8
Convertible notes	292	562	—
Other equity-based awards	109	101	26
Total anti-dilutive common share equivalents	1,090	1,494	34

In September 2016, we issued the 2021 Convertible Notes, which give the holders 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 would 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.

In November 2010, we issued the 2016 Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured and were redeemed in May 2016, as described more fully in the footnote titled Long Term Debt. Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeded the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2015 as the effect would have been anti-dilutive to our earnings per share. Shares issuable upon conversion of the 2016 Convertible Notes were included in the diluted earnings per share calculation for the year ended December 31, 2014 as the average market price during the period exceeded the conversion price.

NOTE 16 - DIVESTITURE AND DISCONTINUED OPERATIONS

In October 2014, we completed the sale of our entire 50 percent ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million, comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million. The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million. As the divestiture represented a strategic shift that had a major effect on our operations as our organization structure no longer has joint venture partners and we no longer have dry gas assets, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for the year ended December 31, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. The following table presents consolidated statements of operations data related to our discontinued operations:

Consolidated statements of operations - discontinued operations	Year Ended December 31, 2014
	(in thousands)
Revenues
Crude oil, natural gas and NGLs sales	$	24,149
Commodity price risk management loss, net	(1,085		)
Other income	48
Total revenues	23,112
Costs, expenses and other
Lease operating expenses	1,280
Production taxes	1,579
Transportation, gathering and processing expenses	3,536
Impairment of properties and equipment	433
Depreciation, depletion and amortization	9,128
Other	4,170
Gain on sale of properties and equipment	(76,479		)
Total costs, expenses and other	(56,353		)
Interest expense	(2,222		)
Interest income	194
Income from discontinued operations	77,437
Provision for income taxes	(29,263		)
Income from discontinued operations, net of tax	$	48,174

The following table presents supplemental cash flows information related to our 50 percent ownership interest in PDCM, which is classified as discontinued operations:

Supplemental cash flows information - discontinued operations	Year Ended December 31, 2014
	(in thousands)
Cash flows from investing activities:
Capital expenditures	$	(17,253	)
Significant non-cash investing items:
Change in accounts payable related to purchases of properties and equipment	(5,727		)

NOTE 17 - TRANSACTIONS WITH AFFILIATES

PDCM. In 2014, our Gas Marketing segment marketed the natural gas produced by PDCM. Our cost of gas marketing includes $23.2 million in 2014 related to the marketing of this gas.

NOTE 18 - BUSINESS SEGMENTS

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

Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas, and NGLs. Segment revenue includes crude oil, natural gas, and NGLs sales, commodity price risk management, net, and other income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of properties and equipment, direct general and administrative expense, and DD&A expense. Segment DD&A expense was$413.1 million, $298.8 million, and $188.5 million in 2016, 2015, and 2014, respectively.

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PDC ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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

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

The following tables present our segment information:

	2016			2015			—	2014
	(in thousands)
Year Ended December 31,
Segment revenues:
Oil and gas exploration and production	$	374,190		$	584,406			$	784,636
Gas marketing	8,725			10,920				71,571
Total revenues	$	382,915		$	595,326			$	856,207
Segment income (loss) before income taxes:
Oil and gas exploration and production	$	(170,370	)	$	31,429			$	344,149
Gas marketing	(1,468		)	(797		)		(445		)
Unallocated	(221,285		)	(137,220		)		(166,476		)
Income (loss) before income taxes	$	(393,123	)	$	(106,588	)		$	177,228
Expenditures for segment long-lived assets:
Oil and gas exploration and production	$	436,884		$	599,617			$	623,912
Acquisition of crude oil and natural gas properties, net of cash acquired	1,073,723			—				—
Unallocated	3,464			5,051				4,680
Total	$	1,514,071		$	604,668			$	628,592
As of December 31,
Segment assets:
Oil and gas exploration and production	$	4,451,510		$	2,294,288
Gas marketing	4,329			4,217
Unallocated	30,003			72,038
Total assets	$	4,485,842		$	2,370,543

96

PDC ENERGY, INC.

SUPPLEMENTAL INFORMATION

(Unaudited)

SUPPLEMENTAL INFORMATION - UNAUDITED

CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED

Net Proved Reserves

All of our crude oil, natural gas, and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, and NGL reserves. As of December 31, 2016, 2015, and 2014, all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott and beginning in 2016, NSAI prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves are those quantities of crude oil, natural gas, and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial booking date.

The indicated index prices for our reserves, by commodity, are presented below.

	Average Benchmark Prices
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	42.75	$	2.48	$	42.75
2015	50.28		2.59		50.28
2014	94.99		4.35		94.99

The netted back price used to estimate our reserves, by commodity, are presented below.

	Price Used to Estimate Reserves*
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	38.67	$	1.85	$	11.97
2015	42.10		2.05		12.23
2014	84.65		3.92		32.27

___________

* These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.

97

PDC ENERGY, INC.

SUPPLEMENTAL INFORMATION

(Unaudited)

The following tables present the changes in our estimated quantities of proved reserves:

	Crude Oil, Condensate (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)
Proved Reserves:
Proved reserves, January 1, 2014 (1)	93,830		739,640		48,671		265,774
Revisions of previous estimates	(29,777	)	(149,064	)	(10,204	)	(64,825	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	40,792		202,957		23,411		98,029
Acquisition of reserves	5		43		5		17
Dispositions	(13	)	(237,306	)	(8	)	(39,572	)
Production	(4,322	)	(19,298	)	(1,756	)	(9,294	)
Proved reserves, December 31, 2014	100,515		536,972		60,119		250,129
Revisions of previous estimates	(43,268	)	(154,775	)	(24,407	)	(93,471	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	48,707		311,709		30,835		131,494
Acquisition of reserves	17		215		23		76
Dispositions	(12	)	(82	)	(8	)	(34	)
Production	(6,984	)	(33,302	)	(2,835	)	(15,369	)
Proved reserves, December 31, 2015	98,975		660,737		63,727		272,825
Revisions of previous estimates	(22,097	)	(80,426	)	(7,130	)	(42,631	)
Extensions, discoveries and other additions	494		4,094		355		1,531
Acquisition of reserves	50,126		305,224		32,586		133,583
Dispositions	(601	)	(4,202	)	(424	)	(1,725	)
Production	(8,728	)	(51,730	)	(4,826	)	(22,176	)
Proved reserves, December 31, 2016	118,169		833,697		84,288		341,407

Proved Developed Reserves, as of:
December 31, 2014	26,798	186,633	17,002	74,905
December 31, 2015	26,257	175,367	15,011	70,496
December 31, 2016	30,013	264,452	24,196	98,284
Proved Undeveloped Reserves, as of:
December 31, 2014	73,717	350,339	43,117	175,224
December 31, 2015	72,718	485,370	48,716	202,329
December 31, 2016	88,156	569,245	60,092	243,122

2016 Activity. During 2016, we increased proved reserves by 25 percent or 68.6 MMBoe, relative to December 31, 2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped reserves in the Delaware Basin.

Extensions, discoveries and other additions for 2016 of 1.5 MMBoe includes the addition of five wells in the Utica Shale.

Acquisitions of reserves of 133.6 MMBoe includes proved developed producing properties and proved undeveloped (“PUD”) locations acquired in our Delaware Basin acquisitions, and new proved locations obtained from an acreage exchange transaction. Because of the preferential economics of the more concentrated acreage in the Wattenberg Field, we rescheduled the timing of anticipated development in the field. This resulted in a downward revision to our proved reserves. The net downward revisions were 42.6 MMBoe. The revision was most notably attributed to a 61.0 MMBoe decrease in reserves due to 2015 PUD locations being removed from our five year development plan and being replaced by PUD locations reflected in purchases of reserves. Infill reserve additions of 16.8 MMBoe in the Wattenberg Field were included as a positive revision of previous estimates. Infill reserve additions for years prior to 2016 for the Wattenberg Field were reported in extensions, discoveries and other additions, including infill reserves in an existing proved field. Revisions also include a 0.5 MMBoe decrease on production due to pricing. The remaining 2.1 MMBoe in positive revisions of previous estimates includes performance revisions and other items.

We had minimal dispositions of 1.7 MMBoe related to acreage traded in the acreage exchange.

98

PDC ENERGY, INC.

SUPPLEMENTAL INFORMATION

(Unaudited)

At December 31, 2015, we projected a PUD reserve conversion rate of 19 percent for 2016. As a result of revisions to our drilling plan during the last two months of 2016, our actual reserve conversion rate was 16 percent, resulting in 32.2 MMBoe of reserves recorded as PUDs at December 31, 2015, being converted to proved developed reserves as of December 31, 2016.

Based on economic conditions on December 31, 2016, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2016, our 2017 PUD reserve conversion rate is expected to be approximately 26 percent. The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities.

2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to December 31, 2014. In 2015, we produced 15.4 million MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16 percent for 2015. Our actual conversion rate was 17 percent, resulting in 29 MMBoe of reserves booked as PUDs at December 31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of proved reserves in 2015.

Extensions, discoveries, and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The reserve additions associated with these projects are largely the result of data generated from our downspacing testing. This led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally, due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling rig utilized during the course of the year. We have 791 gross PUD horizontal drilling locations at December 31, 2015, which is an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries, and other additions to our developed reserves related to wells drilled that were not related to reserves booked as of prior year-end.

We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. Also, contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to well performance and forecast adjustments.

Based on the economic conditions on December 31, 2015, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. The continued success of our increased well density tests in the Wattenberg Field in 2015 allowed for the additional increased well density of PUD locations as of December 31, 2015. Because we expect to continue to drill primarily proved Wattenberg Field locations in 2016 and as a result of additional newly-booked downspaced PUDs at December 31, 2015, our 2016 PUD conversion rate is expected to be approximately 19 percent. The balance of the locations are scheduled to be drilled over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities.

2014 Activity. Overall, our proved reserves decreased by 16 MMBoe as of December 31, 2014 as compared to December 31, 2013. In 2014, we produced 9.3 MMBoe. At December 31, 2013, we projected a PUD conversion rate of seven percent for 2014. Our actual conversion rate was seven percent, resulting in 13 MMBoe of reserves booked as PUDs at December 31, 2013 being converted to proved developed reserves during 2014. As shown, we acquired minimal proved reserves in 2014. We divested a total of 40 MMBoe in 2014, primarily from the sale of our Marcellus Shale assets.

Extensions, discoveries and other additions, including infill reserves, resulted in an increase of approximately 98 MMBoe in 2014, substantially all of which was added in the Wattenberg Field and primarily related to Niobrara and Codell projects. These reserve increases are primarily due to adding 78 MMBoe from new proved undeveloped reserves as a result of adjustments in well spacing, which extended the field by enabling us to book more reserves per section in the Niobrara and Codell formations. In addition, approximately 16 MMBoe of previously unbooked locations were developed in the current year and 2 MMBoe due to various other factors. Approximately 2 MMBoe was added in the Utica Shale.

We recorded a downward revision of our previous estimate of proved reserves of approximately 65 MMBoe. The revision was primarily related to decreases of approximately 55 MMBoe for adjustments to our development plans in the Wattenberg Field to focus on a more balanced commodity production mix and increased well density which delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. In addition, 8 MMBoe of Utica Shale PUDs are no longer in our drilling plans as we directed more capital to higher-return projects in the Wattenberg Field and 2 MMBoe that were due to various other factors.

99

PDC ENERGY, INC.

SUPPLEMENTAL INFORMATION

(Unaudited)

Based on the economic conditions on December 31, 2014, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2014 drilling program focused on testing increased well density in the Wattenberg Field.

Results of Operations for Crude Oil and Natural Gas Producing Activities

The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to gas marketing and other income.

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Revenue:
Crude oil, natural gas and NGLs sales	$	497,353		$	378,713		$	495,562
Commodity price risk management gain (loss), net	(125,681		)	203,183			309,219
	371,672			581,896			804,781
Expenses:
Lease operating expenses	59,950			56,992			43,682
Production taxes	31,410			18,443			27,194
Transportation, gathering and processing expenses	18,415			10,151			8,128
Exploration expense	4,669			1,102			948
Impairment of properties and equipment	9,973			161,620			167,280
Depreciation, depletion, and amortization	413,105			298,760			201,656
Accretion of asset retirement obligations	7,080			6,293			3,455
Loss on sale of properties and equipment	(43		)	(385		)	(75,972		)
	544,559			552,976			376,371
Results of operations for crude oil and natural gas producing activities before provision for income taxes	(172,887		)	28,920			428,410
Provision for income taxes	64,733			(10,394		)	(166,930		)
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	(108,154	)	$	18,526		$	261,480

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes, and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration, and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates.

100

PDC ENERGY, INC.

SUPPLEMENTAL INFORMATION

(Unaudited)

Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration, and Development Activities

Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below.

	Year Ended December 31,
	2016		2015		2014
	(in thousands)
Acquisition of properties: (1)
Proved properties (2)	$	268,567	$	3,561	$	11,973
Unproved properties	1,843,985		15		45,999
Development costs (3)	383,336		552,104		608,176
Exploration costs: (4)
Exploratory drilling	—		—		—
Geological and geophysical	4,669		—		1
Total costs incurred	$	2,500,557	$	555,680	$	666,149

__________

(1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.

(2) Includes approximately $40.9 million of infrastructure and pipeline costs in 2016.

(3) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2016, 2015, and 2014, $204.6 million, $207.8 million, and $125.2 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end.

(4) Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs.

Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities

Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below:

	As of December 31,
	2016			2015
	(in thousands)
Proved crude oil and natural gas properties	$	3,499,718		$	2,881,189
Unproved crude oil and natural gas properties	1,874,671			60,498
Uncompleted wells, equipment and facilities	150,424			109,385
Capitalized costs	5,524,813			3,051,072
Less accumulated DD&A	(1,534,678		)	(1,131,705		)
Capitalized costs, net	$	3,990,135		$	1,919,367

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btucontent, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion, and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits, and allowances related to the properties.

The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves.

101

PDC ENERGY, INC.

SUPPLEMENTAL INFORMATION

(Unaudited)

	As of December 31,
	2016			2015			2014
	(in thousands)
Future estimated cash flows	$	7,122,525		$	6,297,298		$	12,550,515
Future estimated production costs*	(1,624,167		)	(1,493,040		)	(2,746,811		)
Future estimated development costs	(2,219,914		)	(2,036,685		)	(2,528,755		)
Future estimated income tax expense	(597,476		)	(508,332		)	(2,336,510		)
Future net cash flows	2,680,968			2,259,241			4,938,439
10% annual discount for estimated timing of cash flows	(1,260,339		)	(1,162,377		)	(2,631,974		)
Standardized measure of discounted future estimated net cash flows	$	1,420,629		$	1,096,864		$	2,306,465

___________

* Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses.

The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Beginning of period	$	1,096,864		$	2,306,465		$	1,782,163
Sales of crude oil, natural gas and NGLs production, net of production costs	(387,576		)	(293,127		)	(387,789		)
Net changes in prices and production costs (1)	(205,760		)	(1,752,921		)	129,213
Extensions, discoveries, and improved recovery, less related costs	15,128			489,178			1,444,581
Sales of reserves	(3,745		)	(463		)	(402,595		)
Purchases of reserves	487,636			374			238
Development costs incurred during the period	268,672			368,840			161,404
Revisions of previous quantity estimates	(320,286		)	(1,286,462		)	(654,318		)
Changes in estimated income taxes	(13,630		)	902,994			(221,874		)
Net changes in future development costs	391,145			112,958			46,499
Accretion of discount	133,747			345,007			270,389
Timing and other	(41,566		)	(95,979		)	138,554
End of period	$	1,420,629		$	1,096,864		$	2,306,465

__________

(1) Our weighted-average price, net of production costs per Boe, in our 2016 reserve report decreased to $15.73 as compared to $17.30 for 2015 and $37.78 for 2014.

The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

102

PDC ENERGY, INC.

QUARTERLY FINANCIAL INFORMATION - UNAUDITED

Quarterly financial data for the years ended December 31, 2016 and 2015 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year.

	2016
	Quarter Ended
	March 31			June 30			September 30			December 31
	(in thousands, except per share data)
Total revenues	$	90,831		$	20,097		$	163,890		$	108,097
Total cost, expenses and other	193,864			163,379			179,178			178,608
Loss from operations	(103,033		)	(143,282		)	(15,288		)	(70,511		)
Loss before income taxes	(113,369		)	(153,777		)	(35,341		)	(90,636		)
Net loss	$	(71,530	)	$	(95,450	)	$	(23,309	)	$	(55,639	)
Earnings per share:
Basic	$	(1.72	)	$	(2.04	)	$	(0.48	)	$	(0.94	)
Diluted	(1.72		)	(2.04		)	(0.48		)	(0.94		)

	2015
	Quarter Ended
	March 31		June 30			September 30			December 31
	(in thousands, except per share data)
Total revenues	$	144,632	$	50,960		$	231,100		$	168,634
Total costs, expenses and other	106,235		117,514			283,047			152,354
Income (loss) from operations	38,397		(66,554		)	(51,947		)	16,280
Income (loss) before income taxes	27,785		(76,986		)	(62,661		)	5,274
Net income (loss)	$	17,062	$	(46,870	)	$	(41,494	)	$	3,022
Earnings per share:
Basic	$	0.47	$	(1.17	)	$	(1.04	)	$	0.08
Diluted	0.46		(1.17		)	(1.04		)	0.07

103

PDC ENERGY, INC.

FINANCIAL STATEMENT SCHEDULE

Schedule II -VALUATION AND QUALIFYING ACCOUNTS

Description	Beginning Balance January 1		Charged to Costs and Expenses		Deductions (1)		Ending Balance December 31
	(in thousands)
2016:
Allowance for uncollectible notes	$	—	$	44,038	$	—	$	44,038
Allowance for doubtful accounts	2,009		1,309		1,128		2,190
Allowance for expirations of unproved crude oil and natural gas properties	144		215		—		359
2015:
Allowance for doubtful accounts	486		1,700		177		2,009
Allowance for expirations of unproved crude oil and natural gas properties	9,293		7,012		16,161		144
2014:
Allowance for doubtful accounts	896		78		488		486
Allowance for expirations of unproved crude oil and natural gas properties	5,142		4,465		314		9,293

_______________

(1) For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.

104

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2016, 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 December 31, 2016.

Management's Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

In conducting our evaluation of the effectiveness of our internal control over financial reporting, we excluded the internal control over financial reporting and associated activities of the Delaware Basin acquisitions that were accounted for as a business combination, which were consolidated into our financial statements on December 6, 2016, due to the size of the acquisition and integration into our internal control structure which was in process as of December 31, 2016.  These properties constituted 11 percent of total assets and one percent of total revenue of the consolidated financial statement amounts as of and for the year ended December 31, 2016.  Such exclusion was in accordance with the SEC guidance that an assessment of a recently acquired business may be omitted in management’s report on internal controls over financial reporting, providing the acquisition took place within twelve months of management’s evaluation.

Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016, based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2016.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2016, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control over Financial Reporting

During the fourth quarter of 2016, 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.

ITEM 9B. OTHER INFORMATION

None.

105

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report.

ITEM 11. EXECUTIVE COMPENSATION

Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	(1)	Exhibits:
		See Exhibits Index on the following page.

106

ITEM 16. FORM 10-K SUMMARY

None.

Exhibits Index

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
2.1	Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the "Company").	8-K12B	001-37419	2.1	6/8/2015
2.2	Stock Purchase and Sale Agreement, dated August 23, 2016, by and among the seller parties thereto, Kimmeridge Energy Management Company GP, LLC, Arris Petroleum Corporation, and PDC Energy, Inc.	8-K	001-37419	2.1	8/24/2016
2.3	Asset Purchase and Sale Agreement, dated August 23, 2016, by and among 299 Resources, LLC, 299 Production, LLC, 299 Pipeline, LLC, Kimmeridge Energy Management Company GP, LLC and PDC Energy, Inc.	8-K	001-37419	2.2	8/24/2016
3.1	Certificate of Incorporation of the Company.	8-K12B	001-37419	3.1	6/8/2015
3.2	By-laws of the Company.	8-K12B	001-37419	3.2	6/8/2015
4.1	Form of Common Stock Certificate of the Company.					X
4.2	Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022.	8-K	000-07246	4.1	10/3/2012
4.3	Base Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee.	8-K	001-37419	4.1	9/14/2016
4.4	First Supplemental Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee, relating to the 1.125% Convertible Senior Notes due 2021.	8-K	001-37419	4.2	9/14/2016
4.5	Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024.	8-K	001-37419	4.1	9/15/2016
10.1*	Form of Indemnification Agreement.	8-K	000-07246	10.1	6/8/2015
10.2*	401(k) and Profit Sharing Plan, as amended on January 4, 2016.					X
10.3*	Amended and Restated Non-Employee Director Deferred Compensation Plan.	10-K	000-07246	10.3	2/21/2014
10.4*	2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan").	10-K	000-07246	10.26	2/27/2009
10.4.1*	Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan.	8-K	000-07246		4/23/2010
10.5*	Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended.	10-K	001-37419	10.5	2/22/2016
10.6*	Executive Severance Compensation Plan, as amended.	10-K	001-37419	10.6	2/22/2016
10.7*	Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement.	10-K	000-07246	10.5.2	2/21/2014
10.7.1*	Form of 2013 Performance Share Agreement.	10-K	000-07246	10.9	2/27/2013
10.7.2*	Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement.	10-K	000-07246	10.10	2/27/2013
10.7.3*	Form of 2014 Performance Share Agreement.	10-K	000-07246	10.5.4	2/19/2015

107

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
10.7.4*	Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement.	10-K	000-07246	10.5.5	2/19/2015
10.7.5*	Form of 2015 Performance Share Agreement.	10-K	000-07246	10.5.6	2/19/2015
10.7.6*	Form of 2015 Restricted Stock Unit Agreement.	10-K	000-07246	10.5.7	2/19/2015
10.7.7*	Form of 2015 Stock Appreciation Rights Agreement.	10-K	000-07246	10.5.8	2/19/2015
10.7.8*	Form of 2016 Performance Share Agreement.	10-K	001-37419	10.7.8	2/22/2016
10.8*	Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010.	8-K	000-07246	10.2	4/23/2010
10.9*	Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010.	8-K	000-07246	10.3	4/23/2010
10.10*	Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010.	8-K	000-07246	10.4	4/23/2010
10.11	Third Amended and Restated Credit Agreement dated as of May 21, 2013, among PDC Energy, Inc. as Borrower, Riley Natural Gas Company, a Subsidiary of PDC Energy, Inc., as Guarantor, JP Morgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities LLC as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Bank, N.A. as Syndication Agent, and Wells Fargo Securities, LLC as Co-Lead Arranger, and Certain Lenders.	8-K	000-07246	10.1	5/28/2013
10.11.1	First and Second Amendments to Third Amended and Restated Credit Agreement dated as of May 14, 2014 and September 30, 2015, respectively, among PDC Energy, Inc. as the Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders.	10-K	001-37419	10.11.1	2/22/2016
10.11.2	Third Amendment to the Third Amended and Restated Credit Agreement, dated as of September 6, 2016, 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.	8-K	001-37419	10.1	9/8/2016
10.11.3	Fourth Amendment to the Third Amended and Restated Credit Agreement, dated as of October 14, 2016, 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.	10-Q	001-37419	99.1	11/3/2016
10.12*	Consulting Agreement with James M. Trimble, dated as of June 18, 2014.	10-Q	000-07246	10.1	8/8/2014
10.13*	Retirement Agreement with Gysle R. Shellum, Chief Financial Officer, dated October 26, 2015.	8-K	001-37419	10.1	10/27/2015
10.14*	Change of Control and Severance Plan.					X
10.14.1*	Amendment to the PDC Energy Change of Control and Severance Plan			10.14.1	2/28/2017	X
10.15	Registration Rights Agreement, dated as of September 15, 2016, by and between PDC Energy, Inc. and J.P. Morgan Securities LLC, as representative of the initial purchasers, relating to the 6.125% Senior Notes due 2024.	8-K	001-37419	10.2	9/5/2016
10.16	Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Stock Purchase and Sale Agreement).	8-K	001-37419	10.1	12/7/2016
10.17	Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Asset Purchase and Sale Agreement).	8-K	001-37419	10.2	12/7/2016
12.1	Computation of Ratio of Earnings to Fixed Charges.					X
21.1	Subsidiaries.					X
23.1	Consent of PricewaterhouseCoopers LLP.					X
23.2	Consent of Ryder Scott Company, L.P., Petroleum Consultants.					X

108

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
23.3	Consent of Netherland, Sewell & Associates, Inc., Petroleum Consultants.					X
31.1	Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
31.2	Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X
32.1**	Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
99.1	Report of Independent Petroleum Consultants - Ryder Scott Company, L.P.					X
99.2	Report of Independent Petroleum Consultants - Netherland, Sewell & Associates, Inc.					X
101.INS	XBRL Instance Document					X
101.SCH	XBRL Taxonomy Extension Schema Document					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					X
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					X
*Management contract or compensatory arrangement.
** Furnished herewith.

109

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

By: /s/ Barton R. Brookman

Barton R. Brookman

President and Chief Executive Officer

February 28, 2017

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Barton R. Brookman	President, Chief Executive Officer and Director	February 28, 2017
Barton R. Brookman	(principal executive officer)
/s/ David W. Honeyfield	Senior Vice President and Chief Financial Officer	February 28, 2017
David W. Honeyfield	(principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	February 28, 2017
R. Scott Meyers	(principal accounting officer)
/s/ Jeffrey C. Swoveland	Chairman and Director	February 28, 2017
Jeffrey C. Swoveland
/s/ Joseph E. Casabona	Director	February 28, 2017
Joseph E. Casabona
/s/ Anthony J. Crisafio	Director	February 28, 2017
Anthony J. Crisafio
/s/ Larry F. Mazza	Director	February 28, 2017
Larry F. Mazza
/s/ David C. Parke	Director	February 28, 2017
David C. Parke
/s/ Kimberly Luff Wakim	Director	February 28, 2017
Kimberly Luff Wakim

110

GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS

UNITS OF MEASUREMENT

The following presents a list of units of measurement used throughout the document.

Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume.

Bcf – One billion cubic feet of natural gas volume.

Boe – One barrel of crude oil equivalent.

Btu – British thermal unit.

BBtu – One billion British thermal units.

MBoe – One thousand barrels of crude oil equivalent.

MBbls – One thousand barrels of crude oil.

Mcf – One thousand cubic feet of natural gas volume.

MMBoe – One million barrels of crude oil equivalent.

MMBbls – One million barrels of crude oil.

MMBtu – One million British thermal units.

MMcf – One million cubic feet of natural gas volume.

GLOSSARY OF INDUSTRY TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report:

CIG - Colorado Interstate Gas.

Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Developed acreage - Acreage assignable to productive wells.

Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location.

Dry gas or dry natural gas - Natural gas is considered dry when its composition is over 90 percent pure methane.

Dry well or dry hole- A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Exploratory well- A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest.

Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons.

Gross acres or wells - Refers to the total acres or wells in which we have a working interest.

Horizontal drilling- A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions, and production operations among working interest partners.

Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines.

111

Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells.

Net production- Crude oil and natural gas production that we own, less royalties and production due to others.

Non-operated - A project in which we are not the operator.

NYMEX- New York Mercantile Exchange.

Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease.

Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest.

Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable, and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates.

Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure.

Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above.

Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves or PDPs- Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves.

Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved undeveloped reserves or PUDs- Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation.

Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas, and NGLs or related substances to market, and all permits and financing required to implement the project.

Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

112

Section - A square tract of land one mile by one mile, containing 640 acres.

Spud - To begin drilling; the act of beginning a hole.

Standardized measure of discounted future net cash flows or standardized measure- Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense.

Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production.

TETCO M2 - Texas Eastern Transmission Corporation M-2 receipts.

Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves.

Waha - Waha West Texas natural gas prices

Wet gas or wet natural gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and crude oil.

Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations.

Workover - Major remedial operations on a producing well to restore, maintain, or improve the well's production.

113

EX-4.1

EX-10.2

Exhibit 10.2

SUMMARY PLAN DESCRIPTION

The PDC Energy, Inc. 401(k) & Profit Sharing Plan

The PDC Energy, Inc. 401(k) & Profit Sharing Plan

SUMMARY PLAN DESCRIPTION ................................................................................................................................... 1

I.BASIC PLAN INFORMATION ............................................................................................................................... 2

II.PARTICIPATION ...................................................................................................................................................... 4

III.CONTRIBUTIONS ................................................................................................................................................... 4

IV.INVESTMENTS ........................................................................................................................................................ 8

V.VESTING.................................................................................................................................................................... 9

VI.IN SERVICE WITHDRAWALS AND LOANS .................................................................................................... 11

VII.DISTRIBUTION OF BENEFITS .......................................................................................................................... 12

VIII.MISCELLANEOUS INFORMATION ................................................................................................................. 15

IX.INTERNAL REVENUE CODE TESTS ............................................................................................................... 16

X.PARTICIPANT RIGHTS........................................................................................................................................ 17

XI.SERVICES AND FEES .......................................................................................................................................... 20

XII.LOAN PROCEDURES FOR THE PDC ENERGY, INC. 401(K) & PROFIT SHARING PLAN................... 21

Summary Plan Description

The PDC Energy, Inc. 401(k) & Profit Sharing Plan

The The PDC Energy, Inc. 401(k) & Profit Sharing Plan (the “Plan”) of PDC Energy, Inc. has been amended as of

01/04/2016 (the “Effective Date”). This Plan is intended to be a qualified retirement plan under the Internal Revenue Code.

The purpose of the plan is to enable eligible Employees to save for retirement. As well as retirement benefits, the plan provides certain benefits in the event of death, disability, or other termination of employment. The Plan is for the exclusive benefit of eligible Employees and their Beneficiaries.

This booklet is called a Summary Plan Description (“SPD”) and it contains a summary in understandable language of your rights and benefits under the plan. If you have difficulty understanding any part of this SPD, you should contact the Plan Administrator identified in the Basic Plan Information section of this document during normal business hours for assistance.

This SPD is a brief description of the principal features of the plan document and trust agreement and is not meant to interpret, extend or change these provisions in any way. A copy of the plan document is on file with the Plan Administrator and may be read by any employee at any reasonable time. The plan document and trust agreement shall govern if there is a discrepancy between this SPD and the actual provisions of the plan.

This SPD is based on the federal tax implications of your participation in the Plan, transactions made within your Account, and distributions you may receive from the plan. The state tax implications of your participation and these transactions should be determined based on an examination of appropriate state law. Please consult with your tax advisor if you have any questions regarding state tax law.

I. BASIC PLAN INFORMATION

The information in this section contains definitions to some of the terms that may be used in this SPD and general Plan information. If the first letter of any of the terms defined below is capitalized when it is used within this SPD, then it represents the indicated defined term.

A. Account

An Account shall be established by the Trustee to record contributions made on your behalf and any related income, expenses, gains or losses. It may also be referred to as an Account balance.

B. Beneficiary

This is the person or persons (including a trust) you designate, or who are identified by the plan document if you fail to designate or improperly designate, who will receive your benefits in the event of your death. You may designate more than one Beneficiary.

C. Deferral Contribution

This is a contribution taken directly from the pay of an Employee and contributed to the Plan, subject to certain limits

(described below). The Plan permits you to make both pre-tax and certain after-tax (Roth) Deferral Contribution amounts.

D. Employee

An Employee is an individual who is employed by your Employer as a common law employee or, in certain cases, as a leased employee and is not terminated.

E. Employer

The name and address of your Employer is: PDC Energy, Inc.

120 Genesis Boulevard

P.O. Box 26

Bridgeport,WV 26330

The Employer’s federal tax identification number is: 95-2636730

The following Employer(s) also participate in the Plan and employees of each employer listed below shall be eligible to participate in accordance with the Participation section of this Summary Plan Description.

Federal Tax Identification Number	Participating Employer Name	Designation
27-1195623	PDC Mountaineer LLC	Unrelated

F. ERISA

The Employee Retirement Income Security Act of 1974 (ERISA) identifies the rights of Participants and Beneficiaries covered by a qualified retirement plan.

G. Fidelity Investments Contact Information

Fidelity Investments is the recordkeeper of your Plan. To view your Account, make changes to investments, or perform transactions, please use the contact information below:

Phone number: 1-800-835-5097

Website: www.401k.com

H. Highly Compensated Employee

An Employee is considered a highly compensated Employee if (i) at any time during the current or prior year you own, or are considered to own, at least five percent of your Employer, or (ii) received compensation from your Employer during the prior year in excess of $120,000.00, as adjusted and you are in the top paid group consisting of the top 20% of employees ranked by compensation.

I. Non-Highly Compensated Employee

An Employee who is not a Highly Compensated Employee.

J. Participant

A participant is an eligible Employee who has satisfied the eligibility and entry date requirements and is eligible to participate in the Plan or a formerly eligible Employee who has an Account balance remaining in the Plan.

K. Plan Type

The The PDC Energy, Inc. 401(k) & Profit Sharing Plan is a defined contribution plan. These types of plans are commonly described by the method by which contributions for participants are made to the plan. The The PDC Energy, Inc. 401(k) & Profit Sharing Plan is a 401(k) deferral plan. More information about the contributions made to the plan can be found in Section III, Contributions.

L. Plan Administrator

The Plan Administrator is responsible for the administration of the Plan and its duties are identified in the plan document. In general, the Plan Administrator is responsible for providing you and your Beneficiaries with information about your rights and benefits under the Plan. The name and address of the Plan Administrator is:

PDC Energy, Inc.

120 Genesis Boulevard

P.O. Box 26

Bridgeport, WV 26330

M. Plan Number

The three digit IRS number for the Plan is 001.

N. Plan Sponsor

The Plan’s Sponsor is the first Employer listed under the definition of Employer above.

O. Plan Year

The Plan Year is the twelve-month period ending on the last day of December. The Plan Sponsor may only change or have changed the Plan Year by amending and restating to a new Plan Document.

P. Qualified Military Service

Qualified Military Service is service in the uniformed services of the United States for a period of greater than 30 days that results in the Participant having a right of reemployment with the Employer under federal law.

Q. Service of Process

The plan's agent for service of legal process is the Plan Administrator.

R. Trustee

The trustee is responsible for trusteeing the Plan’s assets. The trustee’s duties are identified in the trust agreement and relate only to the assets in its possession. The name and address of the Plan's Trustee are:

Fidelity Management Trust Company

245 Summer Street

Boston, MA 02210

II. PARTICIPATION

A. Eligibility Requirements

You are eligible to participate in the Plan if you are an Employee.

However, you are not eligible to participate if you are:

•a resident of Puerto Rico

•covered by a collective bargaining agreement, unless the agreement requires the employees to be included                 under the Plan.

•a leased Employee.

You are also not eligible to participate if you are an individual who is a signatory to a contract, letter of agreement, or other document that acknowledges your status as an independent contractor not entitled to benefits under the Plan and you are not otherwise classified by the Employer as a common law employee or the Employer does not withhold income taxes, file Form W-2 (or any replacement form), or remit Social Security payments to the Federal government for you, even if you are later adjudicated to be a common law employee.

You will become eligible to participate in the Plan according to the table below:

Contribution type	Age Requirement	Service Requirement	Entry Date
All Sources	18.00	1.00 month(s)	First day of each month

Service with the following predecessor employers, if applicable, shall be counted for eligibility purposes:

•Employees that were a part of the acquisition of Seneca-Upshur Petroleum LLC on 10/04/2011

•Employees that were a part of the acquisition of Merit Energy Company on 06/30/2012

Once you become a Participant you are eligible to participate in the Plan until you terminate your employment with your Employer or become a member of a class of Employees excluded from the Plan. If you terminate your employment after you have met the eligibility requirements, and are later re-employed by your Employer, you will again be eligible to participate in the Plan when you complete one hour of service.

III. CONTRIBUTIONS

After you satisfy the participation requirements in Section II of this Summary Plan Description, you will be eligible to make Deferral Contributions. As described below, if you do not elect a Deferral Contribution rate, you may be automatically enrolled to make Deferral Contributions. In addition, your Employer may make matching and nonelective contributions to your Account. The type(s) of contributions available under the Plan are described in this section.

A. Compensation

Compensation must be defined to compute contributions under the Plan. For purposes of determining contributions, only Compensation paid to you for services you performed while employed as an Eligible Employee shall be considered. Eligible compensation for computing contributions under the Plan is the taxable compensation for a Plan Year reportable by your Employer on your IRS Form W-2, and including salary reduction contributions you made to an Employer sponsored cafeteria, qualified transportation fringe, simplified employee pension, 401(k), 457(b) or 403(b) plan.

The definition of compensation for your plan for purposes of computing contributions also excludes certain amounts as indicated in the table below.

Source	Exclusion (s)
Employee Deferral Contributions and Qualified Nonelective Contributions	Differential Wages, Stock award compensation, Reimbursements or Other Expense Allowances, Fringe Benefits (cash and non-cash), Moving Expenses, Deferred Compensation, Welfare Benefits
Employer Matching Contributions	Differential Wages, Stock award compensation, Reimbursements or Other Expense Allowances, Fringe Benefits (cash and non-cash), Moving Expenses, Deferred Compensation, Welfare Benefits
Employer Nonelective Contributions	Differential Wages, Stock award compensation, Reimbursements or Other Expense Allowances, Fringe Benefits (cash and non-cash), Moving Expenses, Deferred Compensation, Welfare Benefits

Compensation for your first year of eligible Plan participation will be based upon eligible compensation paid for the entire Plan Year. Tax laws limit the amount of compensation that may be taken into account each Plan Year; the maximum amount for the 2016 Plan Year is $265,000.

B. Contributions

1. Regular Deferral Contributions

You may elect to defer a percentage of your eligible compensation into the Plan after you satisfy the Plan’s eligibility requirements. The percentage of your eligible compensation you elect will be withheld from each payroll and contributed to an Account in the Plan on your behalf. For pre-tax contributions being withheld from your compensation, the percentage you defer is subject to an annual limit of the lesser of 60.00% of eligible compensation or $18,000 (in 2016; thereafter as adjusted by the Secretary of the Treasury) in a calendar year. This plan also contains an automatic enrollment feature. If you are subject to automatic enrollment, you will be notified approximately 30 days prior to when your Employer will begin to automatically deduct 4.00% from your pay on a pre-tax basis as a Deferral Contribution for you to the Plan. You may stop or change this automatic contribution by following the instructions provided in the notice. Deferral Contributions made automatically for you are treated the same under the Plan as Deferral Contributions made by your own election.

You will be eligible to designate some or all of your Deferral Contribution as a Roth Deferral Contribution at the time you make your deferral election. Once made, this election will be irrevocable (that is, Roth Deferral Contributions cannot later be re-characterized as pre-tax Deferral Contributions). If you elect to make Roth Deferral Contributions, the amount of your contribution will be included in your income for tax purposes, and the income tax withholding amounts will be deducted from the remainder of your pay, not from the Roth Deferral Contribution amount.

For example, if you have annual compensation of $30,000 and elect to make a Roth Deferral Contribution to the Plan equal to 5% of your compensation, your Roth Deferral Contribution to the Plan will equal $1,500 (5% of $30,000). The tax withholding applicable to the amount you have elected to contribute to the Plan as a Roth Deferral Contribution will be applied against the remainder of your compensation.

Except with respect to the income taxation of Roth Deferral Contributions at contribution (described above) and to the distribution of amounts attributable to Roth Deferral Contributions (described below), Roth Deferral Contributions are subject to the same rules applicable to pre-tax Deferral Contributions. For example, pre-tax and Roth Deferral Contributions are added together to determine whether you have reached the Federal tax law limit on Deferral Contributions ($18,000 in 2016 for those not eligible to make age 50 and over catch-up contributions) or the Plan’s deferral limit. If you have participated in more than one employer-sponsored qualified plan during the year, the Federal tax law limit on Deferral Contributions is your personal limit across all plans, and you should promptly inform your Plan Administrator of any contributions you made outside of this Plan.

Your Deferral Contributions cannot be forfeited for any reason, however, there are special Internal Revenue Code rules that must be satisfied and may require that some of your contributions be returned to you. The Plan Administrator will notify you if any of your contributions will be returned. You may increase or decrease the amount you contribute as of the first day of each month. You may also completely suspend your contributions which you may resume as of the first day of each month. If you want to increase, decrease, suspend, or resume your Deferral Contributions, you must call the Fidelity Retirement Benefits Line at 1-800-835-5097 or access the NetBenefits® web site at www.401k.com.

You may create an annual increase program to gradually raise your contribution rate each year.

2. Additional Deferrals

You may make additional Deferral Contributions during the payroll period(s) designated by your Employer. You may defer a whole percentage between 1 and 100% of your eligible compensation into the Plan by completing a special election form. The total amount of your additional and regular Deferral Contributions for the Plan Year may not exceed

60.00% of your eligible compensation or other applicable Internal Revenue Code limits. Your Employer may refuse to accept any or all of your additional Deferral Contributions if they will have an adverse effect on the Plan’s annually required Internal Revenue Code tests.

3. Age 50 and Over Catch-Up Contributions

The Plan provides that participants who are projected to be age 50 or older by the end of the taxable year and who are making Deferral Contributions to the Plan may also make a catch-up contribution of up to $6,000 (2016; thereafter as adjusted by the Secretary of the Treasury).

4. Employer Matching Contributions

You become eligible for matching contributions only if you make Deferral Contributions. For purposes of determining your matching contributions under the Plan, your Contributions will include Age 50 and Over Catch-Up Contributions. Employer matching contributions must be allocated to your Account in the Plan within prescribed legal time limits.

a. Discretionary Matching Contributions

Your Employer may make discretionary matching contributions. Discretionary matching contributions, if made, will be computed by your Employer based on your eligible compensation deferred into the Plan each Plan Year.

Your Employer will communicate the amount of any annual discretionary matching contributions.

5. Discretionary Nonelective Contributions

Your Employer may make discretionary nonelective contributions in an amount to be determined by the Board of Directors for each Plan Year. You must complete at least 1,000 hours of service during the Plan Year and be employed as of the last day of the Plan Year to be eligible to receive any nonelective contributions that may be made for that Plan Year. You do not need to satisfy this requirement if you die (including death while performing Qualified Military Service), become disabled or retire during the Plan Year.

a. Percentage of Compensation

Discretionary nonelective contributions, if any, made to the Plan by your Employer will be allocated to your Account in the ratio that your eligible compensation bears to the total eligible compensation paid to all eligible Participants.

6. Other Contributions and Limitations

a. Qualified Nonelective Contributions

Your Employer may designate all or a portion of any nonelective contributions for a Plan Year as “qualified nonelective contributions” and allocate them to certain Non-Highly Compensated Employees to help the Plan pass one or more annually required Internal Revenue Code non-discrimination test(s). You will be 100% vested in these contributions and may not request a hardship withdrawal of these contributions.

b. Limit on Contributions

Federal law requires that amounts contributed by you and on your behalf by your Employer for a given limitation year generally may not exceed the lesser of:

$53,000 (or such amount as may be prescribed by the Secretary of the Treasury); or

100.00% of your annual compensation.

The limitation year for purposes of applying the above limits is the twelve month period ending 12/31. Contributions under this Plan, along with Employer contributions under any other Employer-sponsored defined contribution plans, may not exceed the above limits. If this does occur, then excess contributions in your Account may be forfeited or refunded to you based on the provisions of the Plan document. You will be notified by the Plan Administrator if you have any excess contributions. Income tax consequences may apply on the amount of any refund you receive.

7. Rollover Contributions

You can roll over part or all of an eligible rollover distribution you receive from an eligible retirement plan into this Plan even if you have not yet satisfied the age and service Eligibility requirements described in Section II above; however you will not become a Participant in the Plan until you have met the Plan’s eligibility and entry date requirements. An eligible retirement plan is a qualified plan under Section 401(a), a 403(a) annuity plan, a 403(b) annuity contract, an eligible 457(b) plan maintained by a governmental employer, and an individual retirement Account and individual retirement annuity. An eligible rollover distribution includes any distribution from an eligible retirement plan, except any distribution from an individual retirement Account or an individual retirement annuity consisting of nondeductible contributions or any distribution from a 403(b) annuity contract consisting of after-tax employee contributions or any distribution from any other eligible retirement plan consisting of after-tax contributions. Making Rollover Contributions to the Plan that consist of assets other than qualified 401(a) plan assets may result in the loss of favorable capital gains or ten year income averaging tax treatment that may otherwise be available with respect to a lump sum distribution to you from the Plan. The loss of this favorable tax treatment may also occur if you make a Rollover Contribution to the Plan that consists of qualified 401(a) plan assets under certain circumstances. If you may be eligible for this special tax treatment, you should consult your tax advisor and carefully consider the impact of making a Rollover Contribution to the Plan.

The Plan Administrator determines which Rollover Contributions are acceptable and if any Rollover Contribution fails to meet the requirements of the Plan and must be distributed. If your Rollover Contribution to the Plan is not a direct rollover (i.e., you received a cash distribution from your eligible retirement plan), then it must be received by the Trustee within 60 days of your receipt of the distribution and must not contain any after tax contribution amounts. Rollover Contributions may only be made in the form of cash, allowable fund shares, or (if the Plan allows new loans in accordance with the terms of this SPD) promissory notes from an eligible retirement plan. Your Rollover Contributions Account will be subject to the terms of this Plan and will always be fully vested and nonforfeitable. In general, if you receive an eligible rollover distribution as a surviving spouse of a participant or as a spouse or former spouse who is an “alternate payee” pursuant to a qualified domestic relations order (“QDRO”), you may also make a Rollover Contribution to the Plan.

The Plan will accept direct Rollover Contributions of amounts attributable to Roth Deferral Contributions that you made to another qualified plan that accepted Roth Deferral Contributions and properly segregated them from other contributions. The same rules that apply to other direct Rollover Contributions apply to direct Rollover Contributions of amounts attributable to Roth Deferral Contributions, except for the income tax treatment on distribution (described below).

IV.INVESTMENTS

A. Investments

Your Employer has determined that contributions made for will be made into the stock of the Employer or a Related

Employer until you elect otherwise or by your beneficiary following your death.

If you are invested in the stock of the Employer or a Related Employer (the “Stock Fund”), generally your purchases and sales of the Stock Fund will be executed directly through the Trustee. Some Participants may be required to have all trades in or out of the Stock Fund pre-approved by the Plan Administrator. If you are one of these Participants, the Plan Administrator will provide you with a separate notice of the dates you will be able to trade and deadlines you must meet to trade on those dates. If you are invested in the Stock Fund, you will also be given the opportunity to exercise voting rights for shares of the corporation allocated to your Account at all times that corporate shareholders vote. The Plan Administrator has established procedures to ensure that Participant purchase, holding and sale of the Stock Fund, as well as the exercise of voting rights with respect to the stock, shall be held in the strictest confidence (not disclosed to the Employer). The Plan Administrator is responsible for monitoring compliance with these confidentiality procedures. You can get additional information about any investment alternative or the proxy voting for them; by contacting Fidelity.

The Employee Retirement Income Security Act of 1974 (ERISA) imposes certain duties on the parties who are responsible for the operation of the Plan. These parties, called fiduciaries, have a duty to invest Plan assets in a prudent manner. However, an exception exists for plans that comply with ERISA Section 404(c) and permit a Participant to exercise control over the assets in his/her Account and choose from a broad range of investment alternatives. This Plan is intended to be a Section 404(c) plan. To the extent that you have directed the investment of assets in your Account under the Plan, you are responsible for the investment decisions you made relating to those assets and the Plan fiduciaries are not responsible for any losses resulting from your investment instructions. To assist you in making informed investment decisions, your Plan Administrator is required to provide you with certain disclosures required under the Department of Labor's participant disclosure regulation (See DOL Regulation §2550.404a-5) initially and on an annual basis. You should contact your Plan Administrator with any questions regarding these disclosures. Fidelity is assisting your Plan Administrator in complying with this regulation and will make this disclosure notice available for you to review and access via Fidelity's website.

B. Fidelity® Portfolio Advisory Service at Work

Fidelity® Portfolio Advisory Service at Work (the “Service”) is a managed account service that invests your workplace savings plan Account in one of several model portfolios created from a mix of your plan’s eligible investment options. The Service is managed by Strategic Advisers, Inc., a registered investment adviser and a Fidelity Investments company. The investment options selected are spread among broadly diversified investment types designed to help enhance growth and manage risk. When you enroll in the Service, you are assigned to a model portfolio based on either your investment time horizon, or on your financial situation, risk tolerance, and investment time horizon, depending upon what you choose during enrollment. Once enrolled, your current workplace savings account balance will be reallocated to align with the investment allocation of your assigned model portfolio; future contributions will also be invested according to this model portfolio.

While enrolled in the Service, you are delegating the ongoing management of your Account to the Service. In return for ongoing management, your account will incur an advisory fee for the Service as described in the Pricing Supplement. This fee will be paid from your Account. You will not be able to make any exchanges among investment options or otherwise direct or restrict the management of your account. The Service will allocate and, when appropriate, reallocate the assets in your Account to ensure that it stays in balance with the model portfolio’s current mix of investments. Whenever your Account is reallocated or rebalanced to fit your model portfolio, you will receive a confirmation detailing the transactions. You will also receive prospectuses for any investment option you did not previously own.

For more information regarding Fidelity® Portfolio Advisory Service at Work, or to enroll, log onto NetBenefits® at

https://netbenefits.fidelity.com/pas or call a Fidelity Representative at 866-811-6041.

C. Statement of Account

The assets in the Plan are invested in available investment options and a separate Account is established for each Participant who receives and/or makes a contribution. The value of your Account is updated each business day to reflect any contributions, exchanges between investment options, investment earnings or losses for each investment option and withdrawals. Your account statement is available online through NetBenefits®, you can view and print a statement for any time period up to 24 previous months. A statement is also available to be automatically mailed to you every three months. You can initiate these mailings by logging on to NetBenefits® and selecting Mail Preferences under the Accounts tab.

V. VESTING

The term “vesting” refers to your nonforfeitable right to the money in your Account. You receive vesting credit for the number of years that you have worked for your Employer and any Related Employer. In addition, service with the following Employers will be included to determine the number of years of service for vesting purposes:

•Employees that were a part of the acquisition of Seneca-Upshur Petroleum LLC on 10/04/2011

•Employees that were a part of the acquisition of Merit Energy Company on 06/30/2012

If you terminate your employment with your Employer, you may be able to receive a portion or all of your Account based on your vested percentage. Your employer has preserved a prior vesting schedule in the Plan. The Additional Vesting Schedule section below will indicate if a different vesting schedule applies to you. You are always 100% vested in your Rollover Contributions, Qualified Nonelective Contributions, Deferral Contributions and any earnings thereon. Your Employer Nonelective Contributions and earnings shall be vested in accordance with the following schedule:

Years of Service	Vesting Percentage
less than 1	0
1	25.00
2	50.00
3	100.00

Your Employer Matching Contributions and earnings shall be vested in accordance with the following schedule:

Years of Service	Vesting Percentage
less than 1	0
1	25.00
2	50.00
3	100.00
4	100.00

A. Additional Vesting Schedule

Employees who are members of certain class(es), specified below, receive a different vesting schedule for the below-specified contribution:

Your Discretionary Match contributions will be subject to the vesting schedule appearing immediately below if you are a member of the following class: All employees hired on or before 12/31/2006 will remain on the prior vesting schedule of

100% immediate vestiing for Employer Matching Contributions

Years of Service	Vesting Percentage
less than 0	0
0	100.00
1	100.00

The methodology used to determine your years of service for vesting purposes has changed. Previously you received vesting credit for a year of service under the ‘general method’ if you earned at least 1,000 hours of service in a Plan Year. Vesting under the Plan is now based upon the elapsed time method. Hours of service are not counted and instead periods of service are computed. A period of service is determined based on the time you work for your Employer. Only your whole years of service with your Employer will be counted to compute your years of service for vesting purposes. For example, if you have three years and ten months of service, then for vesting purposes you will receive credit for three years of service.

If you were an Employee before July 01, 2006 you will receive vesting credit for your years of service with your Employer based upon the following:

Applicable Year(s)	Method	Measurement Period
Plan Year(s) before 2006	General	Jan 1 to Dec 31
2006	General or Elapsed Time*	Jan 1 to Dec 31
Plan Year(s) after 2006	Elapsed Time	Jan 1 to Dec 31

*You will receive the better of the vesting credit for this period using either the general method (hours of service) through

July 01, 2006 or the elapsed time method.

If you became an Employee on or after July 01, 2006 then you will receive vesting credit for your years of service with your Employer based only on the elapsed time method. In this case, your measurement period for determining your years of service will generally be based upon your date of employment with your Employer.

B. Forfeiture and Re-employment

If you terminate your employment with your Employer and are less than 100% vested in your Employer Account, you may forfeit the non-vested portion of your Employer Account. A forfeiture will occur in the Plan Year that you receive a distribution of your entire vested Account, or if you do not receive a distribution, after five consecutive one year breaks in service. Forfeitures are retained in the Plan and may first be used to pay administrative expenses. Any remaining amounts will be used to reduce future Employer contributions payable under the Plan.

Example: (This example is for illustration purposes only.) Assuming you terminate your employment in 2016 with the following Account:

Source	Amount	Vested Percentage	Vested Amount
Employee	$2,000	100%†	$2,000
Employer	$1,000	80%	800
Total	$3,000		$2,800

You received a $2,800 distribution in 2016 from the Plan. This represented a complete distribution of your

Account. A $200 forfeiture will occur in 2016.

†You are always 100% vested in your own employee Deferral Contributions and earnings in the Plan.

A one-year break in service occurs when you have less than one hour of service in the twelve consecutive month period beginning with the earlier of the day your employment terminates or the 12 month anniversary of the date on which you are otherwise first absent from service. Notwithstanding the above, if you are absent from work due to a maternity or paternity leave, then the 12-consecutive month period beginning on the first anniversary of the first date of that absence will not be a one-year break in service, and if you are absent from work due to a leave of absence under the Family and Medical Leave Act, no 12-consecutive month period beginning on the first anniversary of the first date of that absence, and subsequent anniversaries, during which the absence continues, will be a one-year break in service, provided you return to work following the leave.

When any period of absence is due to military service entitling you to reemployment rights under federal law and you return to work at the Employer or a Related Employer following that absence, there will be no break in service and you will be credited with service for the entire period of that absence.

If you were a Participant when you terminated your employment and are re-employed by your Employer, then you will

again become a Participant on the date you complete one hour of service. Your period of employment before you were rehired is referred to as your pre-break service. Your period of employment after you were rehired is referred to as your post-break service. If you are re-employed after incurring five consecutive one-year breaks in service then your post-break service will not count in determining your vesting percentage in your pre-break Account balance. Your post-break service will count in determining your vesting percentage in your pre-break Account balance and any forfeited amounts will be restored to your Account if:

• You are re-employed by your Employer before you incur five consecutive one-year breaks in service, and

• If you received distribution of your vested Account and you repay the full amount of the distribution before the end of the five-year period that begins on the date you are re-employed.

Example: Assume you terminate employment with your Employer in 2016 with an Account balance of $3,000, of which

$2,800 is vested. You elect to receive a lump sum distribution of your vested Account balance. The remainder, or $200, is forfeited in 2016. If you are rehired on January 1, 2017 and repay the $2,800 distribution prior to January 1, 2022, the $200 previously forfeited will be restored to your Account. Additionally, your service after January 1, 2017 is counted toward vesting your pre-break Account balance of $3,000.

VI.IN SERVICE WITHDRAWALS AND LOANS

If your Account balance includes an investment in the Stock Fund, and shares of the Stock Fund are sold to process a withdrawal, the withdrawal amount will not be distributed until the proceeds from the sale of the shares of the Stock Fund are available as described in the Participant User Guide.

You may contact Fidelity to take a withdrawal or loan from the Plan. The amount of any taxable withdrawal that is not rolled over into an Individual Retirement Account or another qualified employer retirement plan will be subject to Federal and state, if applicable, income taxes. In general, the amount of any taxable withdrawal that is not rolled over into an Individual Retirement Account or another qualified employer retirement plan will be subject to 20% Federal Income Tax and any applicable State Income Tax. A 10% Internal Revenue Code early withdrawal penalty tax may apply to the amount of your withdrawal if you are under the age of 59½ and do not meet one of the Internal Revenue Code exceptions. For information regarding the taxation of amounts attributable to Roth contributions, see the Cash Distribution section below.

The following types of withdrawals are available under the Plan:

A. Hardship Withdrawals

As an Employee, you may apply to withdraw certain contributions to satisfy specific and heavy financial needs. In accordance with Internal Revenue Service regulations, you must first exhaust all other assets reasonably available to you prior to obtaining a hardship withdrawal. This includes obtaining any in-service withdrawal(s) available from your Account and a loan from this Plan and any other qualified plan maintained by your Employer. Your Deferral Contributions to this Plan, and any other Employer-sponsored qualified or non-qualified plan, will be suspended for six months after your receipt of the hardship withdrawal. Your hardship application may be made directly through Fidelity and is generally subject to an electronic approval process. You will be required to provide information specific to the hardship reason selected; you must retain documentation required to substantiate your hardship as the Plan reserves the right to request copies of such documentation. The minimum hardship withdrawal is $500. Hardship withdrawals will be subject to the 10% nonperiodic income tax withholding rate unless you elect out of the withholding.

If you qualify, you may apply for a hardship withdrawal to satisfy the following needs: (1) medical expenses for you, your spouse, children, dependents or a primary beneficiary designated by you under the Plan; (2) the purchase of your principal residence; (3) to prevent your eviction from, or foreclosure on, your principal residence; (4) to pay for post-secondary education expenses (tuition, related educational fees, room and board) for you, your spouse, children, dependents or a primary beneficiary designated by you under the Plan for the next twelve months; (5) to make payments for burial or funeral expenses for your deceased parent, spouse, child, dependent or a primary beneficiary designated by you under the Plan; (6) to pay expenses for the repair of damage to your principal residence that would qualify for the casualty deduction under Section

165 of the Internal Revenue Code (without regard to whether the loss exceeds 10% of adjusted gross income); or any other immediate and heavy financial need as determined based on Internal Revenue Service regulations.

Contributions available to withdraw under the terms of this section are:

•Employee Deferral Contributions (including both pretax and Roth deferral contributions if available in the

Participant’s Account)

•Match

B. Withdrawals After Age 59½

If you have reached age 59½, then you may elect to withdraw all or a portion of your entire vested Account while you are still employed by your Employer.

C. Withdrawals After Age 70½

Starting in the calendar year in which you reach age 70½, you may elect to receive distributions calculated in the same manner as Minimum Required Distributions. For more information, please refer to the paragraph so entitled under the Distributable Events subsection of this SPD’s section on Distribution of Benefits below.

D. Withdrawals After Normal Retirement Age

You may elect to withdraw your vested Account balance after you reach the Plan’s normal retirement age, 65.00, or delay it until you retire. Notwithstanding the above, by law certain contributions including employee deferral, qualified matching, safe harbor matching, qualified nonelective, and safe harbor nonelective contributions cannot be withdrawn prior to age 59½.

E. Withdrawals of Rollover Contributions

If you have a balance in your rollover contributions Account, you may elect to withdraw all or a portion of it. There is no limit on the number of withdrawals of this type.

F. Withdrawal for Participants Performing Qualified Military Service

If you are performing Qualified Military Service, you may elect to withdraw your Deferral Contributions and Qualified Nonelective Contributions during your active duty period. You will be suspended from making any contributions for 6 months following the distribution and the withdrawal may be subject to the 10% early withdrawal penalty tax.

G. Participant Loans

Loans from your vested Account balance shall be made available to all qualifying Participants on a reasonably equivalent basis. Loans are not considered distributions and are not subject to Federal or state income taxes, provided they are repaid as required. While you do have to pay interest on your loan, both the principal and interest are deposited in your Account. You can obtain more information about loans in the Plan's Loan Procedures supplied by your Plan Administrator (which may be attached at the end of this Summary Plan Description).

VII. DISTRIBUTION OF BENEFITS

A. Eligibility For Benefits

A distribution can be made to you if you request one due to your disability, retirement or termination of employment from your Employer and any Related Employer. Your Beneficiary or Beneficiaries may request a distribution of your vested Account balance in the event of your death. The value of your Account balance will continue to increase or decrease, as appropriate, based on the investment returns until it is distributed.

You may defer receipt of your distribution until a later date. However, you cannot postpone it if your vested Account balance is $5,000 or less in which case the Plan Administrator will direct the Trustee that any amount exceeding $1,000 be distributed to an Individual Retirement Account or Annuity (“IRA”) for your benefit. If your vested Account balance is

$1,000 or less, the Plan Administrator will direct the Trustee to distribute it to you as a lump sum distribution without your consent. Prior to such distribution you still have the right to request that the amount be distributed directly to you in the form of a lump sum payment or to request that it be rolled-over to a different IRA provider or another retirement plan eligible to receive rollover contributions.

If you fail to request a different treatment of an automatic distribution under the Plan’s Cash-Out Provision, your

distribution will be paid over to an IRA provider chosen by the Plan Administrator and invested in a product designed to preserve the principal of that distribution while still providing a reasonable rate of return and preserving liquidity. The fees assessed against this newly established IRA by its provider will be paid by the participant.

If you have questions regarding the Plan’s automatic rollover rules, the Plan’s IRA provider for automatic rollovers, or the fees and expenses applicable to the automatic rollover IRA, please contact the Plan Administrator. Your consent will be required for any distribution if your vested Account balance is greater than $5,000.

You should consult with your tax advisor to determine the financial impact of your situation before you request a distribution. You may apply for a distribution by calling the Fidelity Retirement Benefits Line at 1-800-835-5097. All telephone calls will be recorded. Most distributions have been pre-approved by the Plan Administrator.

B. Distributable Events

You are eligible to request a distribution of your vested Account balance based on any of the following events:

1. Death

If you are a Participant in the Plan and die, your vested Account balance, if any, will be paid to your designated Beneficiary or Beneficiaries. If you are an Employee of your Employer or a Related Employer at the time of your death, your Account balance will automatically become 100% vested. Also, if you are a Participant in the Plan and die while performing Qualified Military Service, then your Account balance will become 100% vested. You may designate a Beneficiary or Beneficiaries on a designation form that must be properly signed and filed with the Plan Administrator.

2. Disability

Under your Plan, you are disabled if you meet the following criteria: you are eligible for Social Security disability benefits, or you are determined disabled by a physician selected by the Plan Administrator.

If you become disabled while you are employed by your Employer or a Related Employer and then terminate your employment, you will become 100% vested in your Account balance if you are not already fully vested. You may request a distribution of your Account balance only if you terminate your employment with your Employer or Related Employer.

3. Retirement

You do not have to terminate your employment with your Employer just because you attain your early retirement age of

59½ or you attain your normal retirement age of 65.00. You may take an early retirement distribution at or after age 59½, but you must first terminate your employment with your Employer or Related Employer.

4. Minimum Required Distributions

You are required by law to receive a minimum required distribution from the Employer’s Plan, unless you are a five percent owner of the Employer, no later than April 1 of the calendar year following the calendar year you turn 70½ or terminate your employment, whichever is later. If you are a five percent owner of the Employer, you must start receiving your distribution no later than April 1 of the calendar year following the calendar year you turn 70½. Once you start receiving your minimum required distribution, you should receive it at least annually until all assets in your Account are distributed. If you have any questions about your minimum required distributions, please contact your Plan Administrator.

5. Termination of Employment

Generally, if you terminate your employment with your Employer and all Related Employers, you may elect to receive a distribution of your vested Account balance from the Plan.

C. Form of Payments

1. Lump Sum Distributions

Your entire vested Account balance will be paid to you in a single distribution or other distribution that you elect.

2. Non-rollover Distribution

Any distribution paid directly to you will be subject to mandatory Federal income tax withholding of 20% of the taxable distribution and the remaining amount will be paid to you. You cannot elect out of this tax withholding but you can avoid it by electing a direct rollover distribution as described below. This withholding is not a penalty but a prepayment of your Federal income taxes.

Subject to certain exceptions (for example, with respect to a distribution of excess Deferral Contributions to Highly Compensated Employees due to nondiscrimination test results), the entire amount of your Account under the Plan attributable to Roth contributions will be distributed to you free from Federal income tax (including the earnings portion) if the distribution occurs after the five taxable year period beginning with the first taxable year you made a designated Roth contribution to the Plan (or to a plan you previously participated in, if earlier, if amounts attributable to those previous Roth contributions were directly rolled over to this Plan), provided the distribution is also made:

•On or after you attain age 59 ½ or

•To your beneficiary (or estate) on or after your death; or

•Pursuant to your being disabled.

For example, if you made your first Roth contribution held within the Plan (or another qualified plan, as described in the Rollover Contributions section above) during July, 2006, attained age 59-1/2 on January 1, 2011 and were eligible for a distribution on January 3, 2011, the portion of your distribution attributable to Roth contributions would not be subject to Federal income tax upon distribution on January 3, 2011.

You may rollover the taxable distribution you receive to an Individual Retirement Account (IRA) or your new employer’s qualified plan, if it accepts rollover contributions and you roll over this distribution within 60 days after receipt. You will not be taxed on any amounts timely rolled over into the IRA or your new employer’s qualified Plan until those amounts are later distributed to you. Any amounts not rolled over may also be subject to certain early withdrawal penalties prescribed under the Internal Revenue Code.

3. Direct Rollover Distribution

As an alternative to a non-rollover distribution, you may request that your entire distribution be rolled directly into a Fidelity IRA, a non-Fidelity IRA or to your new employer’s qualified plan if it accepts rollover contributions. Federal income taxes will not be withheld on any direct rollover distribution.

When you call the Fidelity Retirement Benefits Line to take a withdrawal, you will be asked whether you will be rolling over any part of your distribution. If you wish to have any part of your distribution rolled over to an IRA or another qualified plan, you will need to speak to a Fidelity representative.

a. Rollover to Fidelity IRA - You will be asked whether you have received a Fidelity Service for Exiting Employees (‘SEE’) Rollover IRA Kit. If you haven’t received a SEE Kit, the Fidelity representative will send out one. Then, your rollover request will be entered on the system and will pend (for up to 90 days) until the Rollover IRA Account is set up. You must return the signed Rollover IRA application to Fidelity’s Retail Customer Service Department (in Dallas, TX) in order to set up the Rollover IRA Account. Once the Rollover IRA account has been set up, your vested Account balance will be transferred to the Fidelity Rollover IRA.

b. Rollover to Non-Fidelity IRA - A check will be issued by the Trustee payable to the IRA custodian or trustee for your benefit. The check will contain the notation ‘Direct Rollover’ and it will be mailed directly to you. You will be responsible for forwarding it on to the custodian or trustee. You must provide the Plan Administrator with complete information to facilitate your direct rollover distribution.

c. Rollover to your New Employer’s Qualified Plan - You should check with your new employer to determine if its plan will accept rollover contributions. If allowed, then a check will be issued by the Trustee payable to the trustee of your new employer’s qualified plan. The check will contain the notation ‘Direct Rollover’ and it will be mailed directly to you. You will be responsible for forwarding it on to the new trustee. You must provide the plan Administrator with complete information to facilitate your direct rollover distribution.

4. Combination Non-rollover Distribution and Direct Rollover Distribution

You may request that part of your distribution be paid directly to you and the balance rolled into an IRA, your new employer’s retirement plan, or a 403(a) annuity. Any part of the distribution paid directly to you will be subject to the

Federal income tax withholding rules referred to in subsection a) above and any direct rollover distribution will be made in accordance with section b) above. Your direct rollover distribution must be at least $500.

You will pay income tax on the amount of any taxable distribution you receive from the Plan unless it is rolled into an IRA or your new employer’s qualified Plan. A 10% IRS premature distribution penalty tax may also apply to your taxable distribution unless it is rolled into an IRA or another qualified plan. The 20% Federal income tax withheld under this section may not cover your entire income tax liability. In the case of a combination distribution, if any portion of the eligible rollover distribution consists of after-tax contributions, the amount paid directly to you will be considered to consist completely of after-tax contributions before any after-tax contributions are attributed to the portion paid as a direct rollover. Consult with your tax advisor for further details. If you decide to split a distribution into partially a cash distribution and partially a direct rollover distribution, the Plan rule providing that the amount directly rolled over must be at least $500 is applied by treating any amount distributed that is attributable to Roth deferral contributions as a separate distribution from the remainder of the distribution, even if the amounts are distributed at the same time.

5. Installment Distributions

Your vested Account balance will be paid to you in substantially equal amounts over a period of time. You may elect annual or more frequent installments. You may elect to receive a lump sum distribution after you start to receive installment distributions, by completing the appropriate documentation. The direct rollover distribution rules referred to in the lump sum distribution section also apply to installment distributions.

6. Other Non-Annuity

You may also elect to receive your distribution in the form of Distribution of stock in kind.

VIII. MISCELLANEOUS INFORMATION

A. Benefits Not Insured

Benefits provided by the Plan are not insured or guaranteed by the Pension Benefit Guaranty Corporation under Title IV of the Employee Retirement Income Security Act of 1974 because the insurance provisions under ERISA are not applicable to this particular Plan. You will only be entitled to the vested benefits in your Account based upon the provisions of the Plan and the value of your Account will be subject to investment gains and losses.

B. Attachment of Your Account

Your Account may not be attached, garnished, assigned or used as collateral for a loan outside of this Plan except to the extent required by law. Your creditors may not attach, garnish or otherwise interfere with your Account balance except in the case of a proper Internal Revenue Service tax levy or a Qualified Domestic Relations Order (QDRO). A QDRO is a special order issued by the court in a divorce, child support or similar proceeding. In this situation, your spouse, or former spouse, or someone other than you or your Beneficiary, may be entitled to a portion or all of your Account balance based on the court order. Participants and Beneficiaries can obtain, without a charge, a copy of QDRO procedures from the Plan Administrator.

C. Plan-to-Plan Transfer Of Assets

The Plan Sponsor may direct the Trustee to transfer all or a portion of the assets in the Account of designated Participants to another plan or plans maintained by your Employer or other employers subject to certain restrictions. The plan receiving the Trust Funds must contain a provision allowing the transfer and preserve any benefits required to be protected under existing laws and regulations. In addition, a Participant’s vested Account balance may not be decreased as a result of the transfer to another plan.

D. Plan Amendment

The Plan Sponsor reserves the authority to amend certain provisions of the Plan by taking the appropriate action. However, any amendment may not eliminate certain forms of benefits under the Plan or reduce the existing vested percentage of your

Account balance derived from Employer contributions.

E. Plan Termination

The Plan Sponsor has no legal or contractual obligation to make annual contributions to or to continue the Plan. The Plan Sponsor reserves the right to terminate the Plan at any time by taking appropriate action as circumstances may dictate, with the approval of the Board of Directors. In the event the Plan should terminate, each Participant affected by such termination shall have a vested interest in his Account of 100 percent. The Plan Administrator will facilitate the distribution of Account balances in single lump sum payments to each Participant in accordance with Plan provisions until all assets have been distributed by the Trustee. Each Participant in the Plan upon Plan termination will automatically become 100% vested in his/her Account balance.

F. Interpretation of Plan

The Plan Administrator has the power and discretionary authority to construe the terms of the Plan based on the Plan document, existing laws and regulations and to determine all questions that arise under it. Such power and authority include, for example, the administrative discretion necessary to resolve issues with respect to an Employee’s eligibility for benefits, credited services, disability, and retirement, or to interpret any other term contained in Plan documents. The Plan Administrator’s interpretations and determinations are binding on all Participants, Employees, former Employees, and their Beneficiaries.

G. Electronic Delivery

This Summary Plan Description and other important Plan information may be delivered to you through electronic means. This Summary Plan Description contains important information concerning the rights and benefits of your Plan. If you receive this Summary Plan Description (or any other Plan information) through electronic means you are entitled to request a paper copy of this document, free of charge, from the Plan Administrator. The electronic version of this document contains substantially the same style, format and content as the paper version.

IX. INTERNAL REVENUE CODE TESTS

A. Non-Discrimination Tests

The Plan must pass Internal Revenue Code non-discrimination tests as of the last day of each Plan Year to maintain a qualified Plan. These tests are intended to ensure that the amount of contributions under the Plan do not discriminate in favor of Highly Compensated Employees. In order to meet the tests, your Employer encourages participation from all eligible Employees. Depending upon the results of the tests, the Plan Administrator may have to refund Deferral Contributions contributed to the Plan and vested matching contributions to certain Highly Compensated Employees, as determined under Internal Revenue Service regulations. Deferral Contributions or matching contributions will be refunded to you from applicable investment options. You will be notified by the Plan Administrator if any of your contributions will be refunded to you.

In the event that the Plan Administrator distributes amounts attributable to excess Deferral Contributions to Highly Compensated Employees as a result of the non-discrimination test applicable to Deferral Contributions, a Highly Compensated Employee who made both pre-tax and Roth Deferral Contributions during the applicable year will first receive a return of amounts attributable to Pre-tax Deferral Contributions to the extent the Highly Compensated Employee made pre- tax Deferral Contributions during the applicable Plan Year. The remainder of any such distribution will come from amounts attributable to the Roth Deferral Contributions the Highly Compensated Employee made during the applicable Plan Year. The Plan may be subject to additional types of non-discrimination testing depending upon the benefits available under the Plan.

B. Top Heavy Test

The Plan may be subject to the Internal Revenue Code “top-heavy” test. In that circumstance, the Plan Administrator tests this Plan, together with any other Employer-sponsored qualified plans that cover one or more key employees, to ensure that no more than 60% of the benefits are for key employees. If this Plan is top-heavy, then your Employer may be required to make a minimum annual contribution on your behalf to this, or another Employer sponsored plan, if you are employed as of Plan Year-end. You will be vested for these contributions in accordance with the vesting shown for nonelective contributions within the Vesting section of this SPD.

X. PARTICIPANT RIGHTS

A. Claims

1. Claims Procedures

A plan participant or beneficiary may make a claim for benefits under the Plan. Any such claim you file must be submitted to the Plan Administrator in a form and manner acceptable to the Plan Administrator. Contact your Plan Administrator for more information. Generally, the Plan Administrator will provide you with written notice of the disposition of your claim within 90 days after receipt of your claim by the Plan. If the Plan Administrator determines that special circumstances require an extension of time to process your claim, the Plan Administrator will furnish written notice of the extension to the claimant prior to the expiration of the initial 90-day period. In no event shall such extension exceed a period of 90 days from the end of the initial period the Plan Administrator had to dispose of your claim. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Plan expects to render the benefit determination. (A different procedure applies for disability related claims - see the next paragraph). In the event the claim is denied, the Plan Administrator will disclose to you in writing the specific reasons for the denial, a reference to the specific provisions of the Plan on which the determination is based, a description of additional material or information necessary for the claimant to perfect the claim and an explanation of why it is required, and information about the steps that must be taken to submit a timely request for review, including a statement of your right to bring a civil action under Section 502(a) of ERISA following as adverse determination upon review.

If your claim concerns disability benefits under the Plan, the Plan Administrator must notify you in writing within 45 days after you have filed your claim in order to deny it. If special circumstances require an extension of time to process your claim, the Plan Administrator must notify you before the end of the 45-day period that your claim may take up to 30 days longer to process. If special circumstances still prevent the resolution of your claim, the Plan Administrator may then only take up to another 30 days after giving you notice before the end of the original 30-day extension. If the Plan Administrator gives you notice that you need to provide additional information regarding your claim, you must do so within 45 days of that notice.

2. Review Procedures (For Appeal of an Adverse Benefit Determination)

You may appeal the denial of your claim made under the procedures described above within 60 days after the date following your receipt of notification of the denied claim (a different procedure applies for disability related claims - see the next paragraph) by filing a written request for review with the Plan Administrator. This written request may include comments, documents, records, and other information relating to your claim for benefits. You shall be provided, upon your request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to your claim for benefits. The review will take into account all comments, documents, records, and other information submitted by you relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. Generally, the Plan Administrator will provide you with written notice of the disposition of your claim on review within 60 days after receipt of your appeal by the Plan. If the Plan Administrator determines that special circumstances require an extension of time to process your claim, the Plan Administrator will furnish written notice of the extension to the claimant prior to the expiration of the initial 60-day period. In no event shall such extension exceed a period of 60 days from the end of the initial period the Plan Administrator had to dispose of your claim. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Plan expects to render the benefit determination. (A different procedure applies for disability related claims - see the next paragraph). In the event the claim on review is denied, the Plan Administrator will disclose to you in writing the specific reasons for the denial, a reference to the specific provisions of the Plan on which the determination is based, a description of additional material or information necessary for the claimant to perfect the claim and an explanation of why it is required, and information about the steps that must be taken to submit a timely request for review, including a statement of your right to bring a civil action under Section 502(a) of ERISA following as adverse determination upon review.

If your initial claim was for disability benefits under the Plan and has been denied by the Plan Administrator, you have

180 days from the date you receive notice of your denial in which to appeal that decision. Your review will be handled completely independently of the findings and decision made regarding your initial claim and will be processed by an individual who is not a subordinate of the individual who denied your initial claim. If your claim requires medical

judgment, the individual handling your appeal will consult with a medical professional who was not consulted regarding your initial claim and who is not a subordinate of anyone consulted regarding your initial claim and identify that medical professional to you. The Plan Administrator must notify you in writing within 45 days after you have filed your claim in order to deny it. If the Plan Administrator determines that special circumstances require an extension of time to process your claim, the Plan Administrator will furnish written notice of the extension to the claimant prior to the expiration of the initial 45-day period. In no event shall such extension exceed a period of 45 days from the end of the initial period the Plan Administrator had to dispose of your claim. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Plan expects to render the benefit determination.

The Plan Administrator shall notify you of the Plan’s benefit determination on review within a reasonable period of time, but not later than 60 days after receipt of your request for review by the Plan, unless the Plan Administrator determines that special circumstances require an extension of time for processing the claim. If the Plan Administrator determines that an extension of time for processing is required, written notice of the extension shall be furnished to you prior to the termination of the initial 60-day period. In no event shall such extension exceed a period of 60 days from the end of the initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Plan expects to render the determination on review.

The Plan Administrator shall provide you with written notification of a plan’s benefit determination on review. In the case of an adverse benefit determination, the notification shall set forth, in a manner calculated to be understood by you - the specific reason or reasons for the adverse determinations, reference to the specific plan provisions on which the benefit determination is based, a statement that you are entitled to receive, upon your request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to your claim for benefits.

B. Statement of ERISA Rights

As a Participant in the Plan, you are entitled to certain rights and protections under ERISA. ERISA provides that all Plan

Participants shall be entitled to:

1. Receive Information About Your Plan and Benefits

• Examine, without charge, at the Plan Administrator’s office and at other specified locations, such as worksites and union halls, all documents governing the Plan, including insurance contracts and collective bargaining agreements, and a copy of the latest annual report (Form 5500 Series) filed by the Plan with the U.S. Department of Labor and available at the Public Disclosure Room of the Employee Benefits Security Administration.

• Obtain, upon written request to the Plan Administrator, copies of documents governing the operation of the plan, including insurance contracts and collective bargaining agreements, and copies of the latest annual report (Form 5500 Series) and updated Summary Plan Description. The Plan Administrator may make a reasonable charge for the copies.

• Receive a summary of the Plan’s annual financial report. The Plan Administrator is required by law to furnish each Participant with a copy of this Summary Annual Report each year.

• Obtain a statement telling you the fair market value of your vested, accrued benefit, as of the date for which the benefits are reported, if you stop working under the Plan now. If you do not have a right to a benefit under the plan, the statement will tell you how many more years you have to work to get a right to a benefit. This statement must be requested in writing and is not required to be given more than once every twelve (12) months. The Plan must provide the statement free of charge.

2. Prudent Actions by Fiduciaries

In addition to creating rights for Plan Participants, ERISA imposes duties upon the people who are responsible for the operation of the employee benefit plan. The people who operate your Plan, called “fiduciaries” of the Plan, have a duty to do so prudently and in the interest of you, other Plan Participants and Beneficiaries. No one, including your Employer, your union, or any other person, may fire you or otherwise discriminate against you in any way to prevent you from obtaining a retirement benefit or exercising your rights under ERISA.

3. Enforce Your Rights

If your claim for a benefit under the Plan is denied or ignored, in whole or in part, you have a right to know why this was done, to obtain copies of documents relating to the decision without charge, and to appeal any denial, all within certain time schedules. Under ERISA, there are steps you can take to enforce the above rights. For instance, if you request a copy of plan documents or the latest annual report from the Plan and do not receive them within 30 days, you may file suit in a Federal court. The Plan’s agent for legal service of process in the event of a lawsuit is the Plan Administrator. In such a case, the court may require the Plan Administrator to provide the materials and pay you up to $110 a day until you receive the materials, unless the materials were not sent because of reasons beyond the control of the Plan Administrator.

If you have a claim for benefits which is denied or ignored, in whole or in part, you may file suit in a state or Federal court. In addition, if you disagree with the Plan’s decision or lack thereof concerning the qualified status of a domestic relations order, you may file suit in Federal court. If it should happen that Plan fiduciaries misuse the Plan’s money, or if you are discriminated against for asserting your rights, you may seek assistance from the U.S. Department of Labor, or you may file suit in a Federal court. The court will decide who should pay court costs and legal fees. If you are successful, the court may order the person you have sued to pay these costs and fees. If you lose, the court may order you to pay these costs and fees, for example, if it finds your claim frivolous.

4. Assistance with Your Questions

If you have any questions about your Plan, you should contact the Plan Administrator. If you have any questions about this statement or your rights under ERISA, or if you need assistance in obtaining documents from the Plan Administrator, you should contact the nearest office of the Employee Benefits Security Administration, U.S. Department of Labor, listed in your telephone directory or the Division of Technical Assistance and Inquiries, Employee Benefits Security Administration, U.S. Department of Labor, 200 Constitution Avenue N.W., Washington, D.C. 20210. You may also obtain certain publications about your rights and responsibilities under ERISA by calling the publications hotline of the Employee Benefits Security Administration.

C. When to Bring an Action in Court

You may file a lawsuit regarding the denial of an appeal after following the claims and review procedures above. You must file any lawsuit within 12 months after the date the Plan Administrator issued its final decision on an appeal. If you do not file a claim or exhaust the claims review process for any reason, any lawsuit must be filed within 12 months of the date of the conduct at issue in the lawsuit (which includes, among other things, the date you became entitled to any Plan benefits at issue in the lawsuit). If you fail to file a lawsuit within these timeframes, you will lose your right to bring the lawsuit at any later time.

Fees and expenses charged under your Account will impact your retirement savings, and fall into three basic categories. Investment fees are generally assessed as a percentage of assets invested, and are deducted directly from your investment returns. Investment fees can be in the form of sales charges, loads, commissions, 12b-1 fees, or management fees. Certain of these Investment fees may not apply depending upon the funds and share classes available in the Plan. You can obtain more information about such fees from the documents (e.g., a prospectus) that describe the investments available under your Plan. Plan administration fees cover the day-to-day expenses of your Plan for recordkeeping, accounting, legal and trustee services, as well as additional services that may be available under your Plan, such as daily valuation, telephone response systems, internet access to plan information, retirement planning tools, and educational materials. In some cases, these costs are covered by investment fees that are deducted directly from investment returns. In other cases, these administrative fees are either paid directly by your Employer, or are passed through to the participants in the Plan, in which case a recordkeeping fee will be deducted from your Account. Transaction-based fees are associated with optional services offered under your Plan, and are charged directly to your Account if you take advantage of a particular plan feature that may be available, such as a Plan loan. For more information on fees associated with your Account, refer to your Account statement or speak with your Plan Administrator.

1. Loan Application

You may apply for a loan by contacting Fidelity. You may apply for only one loan each calendar year. All loans have been pre-approved by the Plan Administrator based on the criteria outlined in the Plan’s loan procedures. Loans will be allowed for any purpose. A loan set up fee of $75.00 will be deducted from your Account for each new loan processed.

2. Loan Amount

The minimum loan is $1,000 and the maximum amount is the lesser of one-half of your vested Account balance or

$50,000 reduced by the highest outstanding loan balance in your Account during the prior twelve month period. All of your loans from plans maintained by your Employer or a Related Employer will be considered for purposes of determining the maximum amount of your loan. Up to 50% of your vested Account balance may be used as collateral for any loan.

3. Number of Loans

You may only have 1 loan outstanding at any given time. If you have an existing loan you may not apply for another loan until the existing loan is paid in full.

4. Interest Rate

All loans shall bear a reasonable rate of interest as determined by the Plan Administrator based on the prevailing interest rates charged by persons in the business of lending money for loans which would be made under similar circumstances. The interest rate shall remain fixed throughout the duration of the loan.

5. Loan Repayments and Loan Maturity

All loans must be repaid in level payments through after-tax payroll deductions on at least a quarterly basis over a five year period unless it is for the purchase of your principal residence in which case the loan repayment period may not extend beyond 10 years from the date of the loan. If repayment is not made by payroll deduction, a loan shall be repaid in accordance with procedures provided by your Plan Administrator. The level repayment requirement may be waived for a period of one year or less if you are on a leave of absence, however, your loan must still be repaid in full on the maturity date. If you are on a military leave of absence, the repayment schedule may be waived for the entire length of the time missed on leave. Your loan will accrue interest during this time, and upon return from a military leave of absence, your loan will be reamortized to extend the length of the loan by the length of the leave. If a loan is not repaid within its stated period, it will be treated as a taxable distribution to you.

6. Default or Termination of Employment

The Plan Administrator shall consider a loan in default if any scheduled repayment remains unpaid as of the last business day of the calendar quarter following the calendar quarter in which a loan is initially considered past due. In the event of a default, the entire outstanding principal and accrued interest shall be immediately due and payable. However, if your termination of employment results from a corporate action on the part of your employer and you remain performing the same job after that corporate action, within 60 days of your termination of employment you may request that the Plan Administrator roll over your loan to your new employer’s retirement plan (if such new plan will accept your loan roll over). Unless you roll over your loan, any default in repayment to the Plan will result in the treating of the balance due for your loan as a taxable distribution from the Plan.

EX-10.7.8

EXHIBIT VERSION

PDC ENERGY, INC.

2016 PERFORMANCE SHARE AGREEMENT

This Performance Share Agreement (hereinafter referred to as the "Agreement") dated January __, 2016 is by and between PDC Energy. Inc., a Nevada Corporation (hereinafter referred to as the "Company") and _________________ (hereinafter referred to as "Executive").

ARTICLE 1

PURPOSE OF AGREEMENT

1.1    Purpose of Grant. Pursuant to the Company's Amended and Restated 2010 Long-Term Equity Compensation Plan (hereinafter referred to as the "Plan") and subject further to the terms and conditions herein set forth, the Company and Executive enter into this Agreement pursuant to which the Executive may earn Performance Shares. Each Performance Share represents the value of one share of $0.01 par value common stock of the Company. Upon the Company's achievement of pre-determined objectives for a specified performance period (hereinafter referred to as the "Performance Period"), the Company will distribute to the Executive a number of Shares equal to the number of Performance Shares earned by the Executive for the Performance Period.

1.2    Committee Authority. The Plan is administered by the Compensation Committee of the Board (hereinafter referred to as the "Committee"). Under the Plan, the Committee has, among its other powers, the authority to determine the final payout under the Agreement.

ARTICLE 2

PERFORMANCE CONDITIONS

2.1    Performance Period. Pursuant to this Agreement, the Performance Period will be the three year period beginning January 1, 2016 and ending on December 31, 2018.

2.2    Performance Award. Executive has a target of _______ Performance Shares (hereinafter referred to as the "Target Award") for the Performance Period. The range of Performance Shares which may be earned by the Executive for the Performance Period is -0- to [Insert number equal to 200% of Target Award].

2.3    Performance Metric. Subject to Section 2.8, Awards of Performance Shares will be paid out to the Executive, if at all, following the close of the Performance Period based upon Total Shareholder Return ("TSR") of the Company relative to TSR for the Peer Companies (defined below) for such Performance Period (the "Performance Metric").

2.4    Total Shareholder Return (TSR).

(a)General. For purposes of the Performance Metric, except as otherwise provided in 2.4(b) or Section 2.8 below, TSR for a company, including the Company, will be a percentage equal to (x) the “Performance Period Value Change” (as defined below) divided by (y) the “Beginning Value” (as defined below).

(i)“Performance Period Value Change” shall mean:

4056597.1

EXHIBIT VERSION

(1)Average Share Price for the last twenty (20) business days of the Performance Period,

minus

(2)Beginning Value,

plus

(3)Dividends (cash or stock based on ex-dividend date) paid per share of company common stock over the Performance Period.

(ii)“Beginning Value” shall mean the Average Share Price for the twenty (20) business days preceding the beginning of the Performance Period.

(b)Acquired Companies. Notwithstanding the foregoing, TSR for any Acquired Company (as defined in Section 2.6, below) will be a percentage equal to the difference between (x) the product of (I) 100% plus the “Independent Period TSR” (as defined below) multiplied by (II) 100% plus the “Index Return” (as defined below), minus (y) 100%.

(i)“Independent Period TSR” shall mean the “Independent Period Value Change” (as defined below) divided by the Beginning Value.

(ii)“Independent Period Value Change” shall mean:

(1)The closing share price of the Acquired Company on the date on which the acquisition of the Acquired Company occurs (the date of the acquisition being the “Acquisition Date”), or if there is no closing price on the Acquisition Date, then on the most recent trading day preceding the Acquisition Date,

minus

(2)Beginning Value,

plus

(3)Dividends (cash or stock based on ex-dividend date) paid per share of company common stock between the beginning of the Performance Period and the Acquisition Date,

(iii)“Index Return” shall mean:

(1)The difference of (A) the average daily index value of the SIG Oil Exploration & Production Index or any successor index thereto (“EPX”) for the last twenty (20) business days of the Performance Period, minus (B) the index value of the EPX on the Acquisition Date.

divided by

(2)The index value of the EPX on the Acquisition Date.

2

EXHIBIT VERSION

2.5    Average Share Price. For purposes of determining the TSR used in the Performance Metric, the "Average Share Price" means the average daily closing price of the shares on the NASDAQ Global Select Market (or if the company is not listed on the NASDAQ Global Select Market, then on the principal securities exchange on which such shares are tracked) as published by a reputable source over the relevant measuring period.

2.6    Peer Companies. For purposes of the Performance Metric for the relevant Performance Period, the "Peer Companies" means the companies listed on Schedule A. Failed Companies (as defined below), Delisted Companies (as defined below), and Acquired Companies (as defined below) shall remain as Peer Companies, with Failed Companies and Delisted Companies treated in the manner set forth in Section 2.7, and the TSR of any Acquired Companies calculated in accordance with Section 2.4(b), above. “Failed Companies,” shall mean Peer Companies that cease to be publicly traded on a national securities exchange as of the end of the Performance Period as a result of a liquidation commenced under Chapter 7 of the Bankruptcy Code, an assignment of the Company’s assets for the benefit of creditors under applicable state law, or the commencement of a reorganization proceeding under Chapter 11 of the Bankruptcy Code. “Delisted Companies” shall mean Peer Companies that cease to be publicly traded on a national securities exchange at any time during the Performance Period (irrespective of whether they again become publicly traded on a national securities exchange during the Performance Period) as a result of any involuntary failure to meet the listing requirements of such national securities exchange (such as any failure to meet the minimum common stock price requirement of the exchange), but shall not include any Peer Company that does not meet the listing requirements as a result of any voluntary going private or similar transaction. “Acquired Companies” shall mean Peer Companies that cease to be independently publicly traded on a national securities exchange during the Performance Period as a result of being acquired by another entity (irrespective of whether such acquiring entity is itself publicly traded). No companies may be added to the list during the Performance Period.

2.7    Award Determination. At the end of the Performance Period, the Peer Companies and the Company shall be ranked together based on their TSR for the Performance Period with the highest TSR being number 1 and the lowest TSR being the number of Peer Companies, including the Company, remaining in the group at the end of the Performance Period, with any and all Failed Companies and Delisted Companies being ranked in last place on the list. Based on the Company's relative TSR rank among the Peer Companies for the Performance Period, Executive will have earned Performance Shares as determined by the Company's rank as follows:

• If the Company is ranked at or above the 90^th percentile of the Peer Companies, 200% of the Target Award

• If the Company is ranked at the 50^th percentile or median of the Peer Companies, including the Company, 100% of the Target Award

• If the Company is ranked at the 25^th percentile of the Peer Companies, including the Company, 50% of the Target Award

• If the Company is ranked below the 25^th percentile of the Peer Companies, including the Company, no award will be paid

3

EXHIBIT VERSION

If the Company is ranked between any of these payout levels, the percentage multiple of the Target Award will be interpolated based on the actual percentile ranking of the Company (rounded to the nearest whole percentile) in relation to the payout levels. Notwithstanding the preceding, if the Company's overall TSR is negative, no more than one hundred percent (100%) of the Target Award will be paid to the Executive. Any partial shares will be rounded up to the next whole number.

2.8    Termination of Continuous Service or Change in Control Prior to End of Performance Period.

[(a)Voluntary or Involuntary Termination Prior to Change in Control. If the Executive voluntarily terminates Continuous Service or if the Company terminates the Executive's Continuous Service during the Performance Period, in either case before a Change in Control, all Performance Shares will be immediately forfeited.][ALTERNATIVE 1 - FOR EXECUTIVES WITH EMPLOYMENT AGREEMENTS.]

[(a)Voluntary or Involuntary Termination Prior to Change in Control.

(i)General. Except as provided below, if the Executive voluntarily terminates Continuous Service or if the Company terminates the Executive's Continuous Service during the Performance Period, in either case before a Change in Control, all Performance Shares will be immediately forfeited. If Executive remains in Continuous Service throughout the Performance Period, the Performance Shares shall vest and be earned as stated in Section 2.3 - 2.7 above based on the relative TSR of the Company.

(ii)Termination without Cause; Resignation for Good Reason prior to a Change in Control. Notwithstanding the foregoing, in the event that prior to a Change in Control Executive’s Continuous Service is terminated by the Company without “Cause” or by Executive for “Good Reason” (each as defined in the Company severance Plan in which Executive is a participant), then the Executive may be eligible to receive payment of all or a portion of the Performance Shares, if any, that Executive would have received at the end of the Performance Period (based on achievement of the Performance Metric) had Executive not terminated Continuous Service (the “Potential Shares”). Within forty-five days of the date of termination, the Committee shall determine, in its sole and absolute discretion, the portion, if any, of the Potential Shares that Executive shall be entitled to receive, which determination shall be based on such factors as the Committee deems relevant, including, but not limited to, the length of Executive’s Continuous Service during the Performance Period and the circumstances surrounding Executive’s termination. Notwithstanding the foregoing, the Committee shall maintain discretion at any time prior to payment to reduce or eliminate the payment to which Executive is otherwise due based on Executive’s failure to comply with any post-termination restrictive covenants.][ALTERNATIVE 2 - FOR EXECUTIVES IN THE SEVERANCE PLAN.]

(b)    Death or Disability. Notwithstanding Section 2.8(a), in the event of the death or Disability of the Executive during the Performance Period, in either case before a Change in Control, the Executive (or Executive’s estate) will receive a pro-rata payment (based on the number of completed months during the Performance Period compared to the total number of months in the Performance Period) based on actual results at the end of the Performance Period. Notwithstanding the foregoing, if the triggering event is due to a death that occurs during the first two (2) years of the Performance Period, such pro-rata payment will be based on actual results through the date of death with the Performance Metric calculated with reference to the Average Share Price for the twenty (20) business days prior to the date of death.

(c)    Change in Control. In the event of a Change in Control:

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(1)If less than one-half of the Performance Period has elapsed with respect to the Performance Shares, then one hundred percent (100%) of the Target Award for the Performance Period will be paid to the Executive.

(2)If at least one-half of the Performance Period has elapsed with respect to the Performance Shares, then the Executive will receive the greater of (A) one hundred percent (100%) of the Target Award or (B) the percentage corresponding to the actual performance level achieved as of the date of the Change in Control.

(d)    Continuous Service. For purposes of this Agreement, the term “Continuous Service” shall mean Executive’s uninterrupted service to the Company or an Affiliate as an Employee, Non-Employee Director, or consultant. The Committee shall determine in its discretion whether and when Executive’s Continuous Service has ended (including as a result of any leave of absence); provided, however, that Executive’s Continuous Service shall not be deemed to have ended in the event Executive retires or otherwise terminates as an Employee but continues to perform services as a Non-Employee Director or consultant.

2.9    Payment of Performance Shares.

(a)    Performance Shares earned for the Performance Period will be issued to the Executive only following the Committee's formal review and certification of the actual TSR performance results for the Performance Period.

(b)    Performance Shares payable to an Executive pursuant to Section 2.3 following the close of the Performance Period will be paid in a lump sum distribution of Shares to the Executive within seventy-four (74) days following the close of the Performance Period.

(c)    Performance Shares payable to an Executive pursuant to Section 2.8(b) will be paid in a lump sum distribution of Shares to the Executive within seventy-four (74) days following the close of the Performance Period, except in the case of a death during the first two (2) years of the Performance Period, in which case payment will be made within seventy-four (74) days following the date of death.

(d)    Performance Shares payable to an Executive pursuant to Section 2.8(c) following a Change in Control will be paid in a lump sum distribution of Shares to the Executive within seventy-four (74) days following the date of the Change in Control.

2.10    Tax Withholding. Executive shall make arrangements with the Company to satisfy all applicable income and employment tax withholdings that may result from the issuance of Shares hereunder, which withholdings may be satisfied (at the election of Executive made prior to the payment date): (i) by Executive paying to the Company directly in cash the amount of such withholdings, (ii) by having the Company withhold from Shares paid to Executive a number of Shares necessary to satisfy such tax withholding obligations, or (iii) by a combination of the foregoing methods; provided, however, that in the absence of an affirmative election by Executive prior to the payment date, the Company shall satisfy such tax obligations pursuant to subsection (ii), above.

2.11    Dividend Equivalents. Executive shall be entitled to a cash payment with respect to each Performance Share earned and payable under this Agreement in an amount equal to the ordinary cash dividends that would have been payable to Executive had Executive been the owner of an actual Share of stock (as opposed to a Performance Share) from the first date of the Performance Period through the date

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EXHIBIT VERSION

the Performance Share is paid. Such cash payment shall be made in a single lump sum on the date on which payment is made in respect of the related Performance Share pursuant to Section 2.9.

2.12    Stockholder Rights. An Executive will not have any voting or other stockholder rights with respect to any Performance Shares. Executive shall have full stockholder rights with respect to Shares issued as payment for Performance Shares pursuant to Section 2.9.

2.13    Fractional Shares. The Company will not be required to issue any fractional Shares pursuant to this Agreement. The Committee may provide for the elimination of fractions or for the settlement of fractions in cash.

ARTICLE 3

GENERAL

3.1Capitalized Terms. All capitalized terms shall have the meeting ascribed to them under this Agreement or, if not otherwise defined in this Agreement, then such capitalized terms will have the meaning ascribed to them under the Plan.

3.2Construction. The provisions of this Agreement will be construed in a manner consistent with the Plan. In the event of any inconsistency between the terms of the Agreement and the terms of the Plan, the terms of the Plan will control.

3.3Compliance with Section 409A of the Internal Revenue Code. This Agreement and all payments made hereunder are intended to be exempt from or to comply with the requirements of Section 409A of the Code and this Agreement shall be interpreted accordingly.

3.4Consent Relating to Personal Data. Executive voluntarily acknowledges and consents to the collection, use, processing and transfer of personal data as described in this Section even though Executive is not obliged to consent to such collection, use, processing and transfer of personal data. The Company and its subsidiaries hold, for the purpose of managing and administering the Plan, certain personal information about Executive, including Executive’s name, home address and telephone number, date of birth, social security number or other employee identification number, salary, nationality, job title, any Shares or directorships held in the Company, details of all equity awards or any other entitlement to Shares awarded, canceled, purchased, vested, unvested or outstanding in Executive’s favor (“Data”). The Company and/or its subsidiaries will transfer Data among themselves as necessary for the purpose of implementation, administration and management of Executive’s participation in the Plan and the Company and/or any of its subsidiaries may each further transfer Data to any third parties assisting the Company in the implementation, administration and management of the Plan. These recipients may be located throughout the world, including the United States. Executive authorizes them to receive, possess, use, retain and transfer the Data, in electronic or other form, for the purposes of implementing, administering and managing Executive’s participation in the Plan, including any requisite transfer of such Data as may be required for the administration of the Plan and/or the subsequent holding of Shares on Executive’s behalf to a broker or other third party with whom Executive may elect to deposit any Shares acquired pursuant to the Plan. Executive may, at any time, review Data, require any necessary amendments to it or withdraw the consents herein in writing by contacting the Company.

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EXHIBIT VERSION

3.5Other Employee Benefits. Except as specifically provided otherwise in any relevant employee benefit plan, program, or arrangement, any amounts payable hereunder are not part of normal or expected compensation for purposes of calculating any severance, resignation, redundancy, end of service payments, bonuses, long-service awards, pension or retirement benefits or similar payments.

3.6Electronic Delivery. EXECUTIVE HEREBY CONSENTS TO ELECTRONIC DELIVERY OF THE PLAN, AND ANY DISCLOSURE OR OTHER DOCUMENTS RELATED TO THE PLAN, INCLUDING FUTURE GRANT DOCUMENTS (COLLECTIVELY, THE “PLAN DOCUMENTS”). THE COMPANY WILL DELIVER THE PLAN DOCUMENTS ELECTRONICALLY TO EXECUTIVE BY E-MAIL, BY POSTING SUCH DOCUMENTS ON ITS INTRANET WEBSITE OR BY ANOTHER MODE OF ELECTRONIC DELIVERY AS DETERMINED BY THE COMPANY IN ITS SOLE DISCRETION. EXECUTIVE ACKNOWLEDGES THAT HE OR SHE IS ABLE TO ACCESS, VIEW AND RETAIN AN E-MAIL ANNOUNCEMENT INFORMING EXECUTIVE THAT THE PLAN DOCUMENTS ARE AVAILABLE IN EITHER HTML, PDF OR SUCH OTHER FORMAT AS THE COMPANY DETERMINES IN ITS SOLE DISCRETION.

3.7Notices. Any notice required or permitted to be given hereunder shall be in writing and shall be given by hand delivery, by e-mail, by facsimile, or by first class registered or certified mail, postage prepaid, addressed, if to the Company, to its Corporate Secretary, and if to Executive, to Executive’s address now on file with the Company, or to such other address as either may designate in writing. Any notice shall be deemed to be duly given as of the date delivered in the case of personal delivery, e-mail, or facsimile, or as of the second day after enclosed in a properly sealed envelope and deposited, postage prepaid, in a United States post office, in the case of mailed notice.

3.8Amendment. This Agreement may be amended by the Committee at any time without Executive’s consent if such amendment does not reduce the benefits to which Executive was entitled. In all other cases, this Agreement may not be amended or otherwise modified unless evidenced in writing and signed by the Company and Executive.

3.9Construction; Severability. The section headings contained herein are for reference purposes only and shall not in any way affect the meaning or interpretation of this Agreement. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision hereof, and each other provision hereof shall be severable and enforceable to the extent permitted by law.

3.10Waiver. Any provision contained in this Agreement may be waived, either generally or in any particular instance, by the Committee appointed under the Plan, but only to the extent permitted under the Plan.

3.11Binding Effect. This Agreement shall be binding upon and inure to the benefit of the Company and to Executive and their respective heirs, executors, administrators, legal representatives, successors and assigns.

3.12Rights to Employment. Nothing contained in this Agreement shall be construed as giving Executive any right to be retained in the employ of the Company and this Agreement is limited solely to governing the parties’ rights and obligations with respect to the Performance Shares.

3.13Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Colorado, without regard to the choice of law principles thereof.

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EXHIBIT VERSION

3.14Company Policies to Apply. The sale of any Shares received as payment hereunder is subject to the Company’s policies regulating securities trading by employees, all relevant federal and state securities laws and the listing requirements of any stock exchange on which the shares of the Company’s Common Stock are then traded. In addition, Executive’s participation in the Plan and receipt of remuneration as a result of the Performance Shares is subject in all respects to any Company compensation clawback policies that may be in effect from time to time.

.

IN WITNESS WHEREOF, the Company and Executive hereby execute this Agreement to be effective as of the day and year first above written.

ATTEST:

[Corporate Seal]PDC ENERGY, INC.

By:

Sue Sander__________________________

Date:_____________________________________

EXECUTIVE

WitnessSignature

Date:

Please sign, date and return the signed agreement immediately to Kara Ullrich. If you are not in the office, please fax or email by PDF immediately to Kara Ullrich.

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EXHIBIT VERSION

SCHEDULE A

PEER COMPANIES

The following 13 companies compromise the Peer Companies for the 2016 - 2018 Performance Period:

• Bill Barrett Corporation (BBG)

• Bonanza Creek Energy, Inc. (BCEI)

• Callon Petroleum Company (CPE)

• Carrizo Oil & Gas Inc. (CRZO)

• Energen Corp. (EGN)

• Gulfport Energy Corp. (GPOR)

• Laredo Petroleum Holdings, Inc. (LPI)

• Matador Resources Company (MTDR)

• Oasis Petroleum Inc. (OAS)

• Parsley Energy, Inc. (PE)

• SM Energy Company (SM)

• Synergy Resources Corporation (SYRG)

• WPX Energy, Inc. (WPX)

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EX-10.14

Exhibit 10.14

PDC ENERGY

CHANGE OF CONTROL

AND SEVERANCE PLAN

The PDC Energy Change of Control and Severance Plan (the “Plan”) is hereby effective as of January l, 2011 (the “Effective Date’’) pursuant to the authorization of the Board of Directors of Petroleum Development Corporation (the “Company”). The Plan has been established to provide financial security to the Company’s Executives (as defined below) in the event of a Change of Control (as defined below) and upon certain terminations of employment with the Company.

It is the intent that this Plan constitute a separate unfunded plan that meets the requirements of, and that is classified as a plan which is maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees within the meaning of Sections 201(2), 301(3), and 401(a)(1) of ERISA. As such, it is intended that the Plan be exempt from the relevant requirements of Title I of ERISA. In addition, this Plan is not intended to satisfy the qualification requirements of Code Section 401. However, the Plan is intended to comply with the requirements of Code Section 409A and the Treasury regulations and guidance issued thereunder.

I. DEFINITIONS AND CONSTRUCTION

1.1    Definitions. Where the following words and phrases appear in the Plan, they shall have the respective meanings set forth below, unless their context clearly indicates to the contrary.

(a)    “Base Salary” shall mean the annual base salary paid to the Executive from time to time in accordance with the ordinary payroll practices of the Company.

(b)    “Board” shall mean the Board of Directors of the Company or its successor.

(c)    “Cause” shall mean:

(i)    the Executive has failed to substantially perform his or her duties with the Company (other than a failure resulting from his or her incapacity due to physical or mental illness) after a written demand for substantial performance has been delivered to the Executive by the Company, which demand specifically identifies the manner in which the Company believes the Executive has not substantially performed his or her duties, and the Executive has failed to cure such deficiency within thirty (30) days after his or her receipt of such notice;

(ii)    the Executive has engaged in conduct, the consequences of which are materially adverse to the Company, monetarily or otherwise;

(iii)    the Executive has pleaded guilty to or been convicted of a felony or a crime involving moral turpitude or dishonesty;

(iv)    the Executive has engaged in conduct which demonstrates Executive’s gross unfitness to serve the Company; or

(v)    the Executive has materially breached the terms of this Plan.

(d)    “Change of Control” shall be deemed to have occurred for purposes of the Plan if the event set forth in any one of the following paragraphs shall have occurred:

(i)Change in Ownership: A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of additional stock by a person or more than one person acting as a group who is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company.

(ii)Change in Effective Control:     A change in effective control of the Company occurs on the date that either:

(A)Any one person, or more than one person acting as a group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company; or

(B)A majority of the members of the Board is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Board prior to the date of the appointment or election; provided, that this paragraph (B) will apply only to the Company if no other corporation is a majority shareholder.

(iii)Change in Ownership of Substantial Assets: A change in the ownership of a substantial portion of the Company’s assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 90% of the total gross fair market value of the assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, “gross fair market value” means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.

It is the intent that this definition be construed consistent with the definition of “Change of Control” as defined under Code Section 409A and the applicable Treasury Regulations, as amended from time to time.

(e)    “Change of Control Period” shall mean the 6-month period preceding and the 24-month period following the date that a Change of Control occurs.

(f)    “Code” shall mean the Internal Revenue Code of J 986, as amended.

(g)    “Committee” shall mean the Compensation Committee of the Board.

(h)    “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended.

(i)    “Executive” shall mean any individual who is part of a select group of management or highly compensated employees within the meaning of Sections 201(2), 301(3) and 401(a)(1) of ERISA, including but not limited to either a Vice President or the Chief Accounting Officer of the Company, who is chosen by the Committee to participate in the Plan.

(j)    “Good Reason” shall mean the occurrence of any of the following events without the Executive’s prior express written consent:

(i)    A material diminution in the Executive’s Base Salary;

(ii)    A material diminution of the annual bonus (but not if a majority of the other Executives are also similarly impacted);

(iii)    A material diminution in the Executive’s authority, duties, or responsibilities: or

(iv)    A change in the geographic location at which the Executive must perform his or her services in excess of fifty (50) miles.

The Executive must provide notice to the Company of the applicable condition described above within ninety (90) days after such occurrence, upon the notice of which the Company will have a period of thirty (30) days during which it may remedy the condition. In the event the Company fails to timely remedy the condition, the Executive may terminate his or her employment for Good Reason in the seven (7) day period following the Company’s failure to remedy.

(k)    “Involuntary Termination” shall mean termination of the Executive’s employment by the Company other than by death, Disability or for Cause.

(l)    “Release” shall mean a general release, substantially in the form attached hereto as Exhibit A, by the Executive that releases the Company and its affiliates (and other persons specified in the release) from employment-related claims.

(m)    “Target Bonus” shall mean the target performance bonus established by the Company for an Executive for the year.

(n)    “Termination Date” shall mean the date that an Executive ceases his or her employment with the Company.

1.2    Number. Wherever appropriate herein, words used in the singular shall be considered to include the plural and the plural to include the singular.

1.3    Headings. The headings of Articles and Sections herein arc included solely for convenience and if there is any conflict between such headings and the text of the Plan, the text will control.

II. CHANGE OF CONTROL AND SEVERANCE BENEFITS

2.1    Benefits for Involuntary Termination Outside of Change of Control Period. Subject to the provisions of this Article II, if there is an Involuntary Termination of an Executive outside of a Change of Control Period, the Executive shall receive the following severance benefits:

(a)    With regard to those Executives receiving written notification of entitlement to enhanced severance benefits if an Involuntary Termination occurs before January l, 2012, beginning on the first day of the month following sixty (60) days after the Termination Date, a monthly severance payment for twelve (12) months equal to one-twelfth (1/12th) of two (2) times the sum of (i) the Executive’s Base Salary. plus (ii) the Executive’s Target Bonus, or if there is no Target Bonus specified for the year of termination, then the Executive’s most recent annual bonus; and

(b)    With regard to those Executives not entitled to enhanced severance benefits if they incur an Involuntary Termination during 2011 and with regard to all Executives who incur an Involuntary Termination after December 31, 2011, beginning on the first day of the month following sixty (60) days after the Termination Date, a monthly severance payment for twelve (12) months equal to one-twelfth (1/12) of the sum of (i) the Executive’s Base Salary, plus (ii) the Executive’s Target Bonus, or if there is no Target Bonus specified for the year of termination, then the Executive’s most recent annual bonus; and

(c)    Continued coverage of the Executive and any dependents of the Executive covered at the time of the Executive’s termination under the Company’s group health plans on a subsidized basis for the lesser of (i) the period of time that the Executive is receiving severance payments, or (ii) the period of time that the Executive is eligible for federal COBRA health continuation coverage. For this purpose, the subsidized basis shall mean that the Executive shall be charged the same premium rate as a similarly-situated active employee; and

(d)    Full vesting of all restricted stock, to the extent permitted under the related plan.

2.2    Benefits for Involuntary Termination or Good Reason Termination Within Change of Control Period. Subject to the provisions of this Article II, if there is an Involuntary Termination of an Executive within the Change of Control Period or if an Executive terminates employment for Good Reason within the Change of Control Period, the Executive shall receive the following severance benefits:

(a)    On the first day of the month following sixty (60) days after the Termination Date, a lump sum severance payment equal to two (2) times the sum of (i) the Executive’s Base Salary, plus (ii) the Executive’s Target Bonus, or if there is no Target Bonus specified for the year of termination, then the Executive’s most recent annual bonus; and

(b)    Continued coverage of the Executive and any dependents of the Executive covered at the time of termination under the Company’s group health plans on a subsidized basis for the period of time that the Executive is eligible for federal COBRA health continuation coverage. For this purpose, the subsidized basis shall mean that the Executive shall be charged the same premium rate as a similarly-situated active employee; and

(c)    Full vesting of all restricted stock, to the extent permitted under the related plan.

2.3    Release. As a condition to the payment by the Company of the amounts due under Sections 2.1 and 2.2 above, the Executive shall execute the Release within twenty-one (21) days following the Termination Date and shall not revoke it within the subsequent seven (7) day revocation period; provided, however, if the Executive is being terminated as part of an exit incentive or other group termination program, then the Executive shall execute a Release substantially similar to the Release (except that the period for consideration of the Release shall be modified) within forty-five (45) days following the Termination Date and shall not revoke it within the subsequent seven (7) day revocation period.

2.4    No Mitigation. An Executive shall not be required to mitigate the amount of any payment or benefit provided for in this Article II by seeking other employment or otherwise. nor shall the amount of any payment or benefit provided for in this Article II be reduced by any compensation or benefit earned by the Executive as the result of employment by another employer or by retirement benefits, except as provided in Sections 2.1(h) and 2.2(h) with respect to Federal COBRA health continuation coverage and in Section 2.5 with respect to the coordination of severance benefits hereunder with other agreements providing severance benefits. Subject to the foregoing, the benefits under the Plan are in addition to any other benefits to which an Executive is otherwise entitled.

2.5    Coordination with Other Arrangements. Any Executive who is a party to an individual employment or severance agreement or covered by another similar Change of Control or severance plan (“Other Plan”) of the Company and who becomes eligible for severance payments and benefits as provided in Section 2.1 or 2.2 of the Plan, shall receive such severance payments and benefits as provided under Section 2.1 or 2.2 of the Plan, hut such payments and benefits shall be “offset” or reduced by any severance payments or benefits provided to such Executive under any such Other Plan.

2.6    Code Section 280G.

(a)    If any of the payments or benefits received or to be received by the Executive in connection with the Executive’s termination of employment in respect of a Change of Control, whether pursuant to the terms of this Plan or any other plan, arrangement or agreement with the Company (all such payments and benefits, being hereinafter referred to as the “Total Payments”) would be subject to the excise tax (the “Excise Tax”) imposed under Section 4999 of the Code, the Executive shall receive the Total Payments and be solely responsible for the Excise Tax; provided, however, that the Executive shall not receive the Total Payments and the Total Payments shall be reduced to the Safe Harbor Amount if (1) the net amount of such Total Payments, as so reduced (and after subtracting the net amount of federal, state and local income taxes on such reduced Total Payments) is greater than or equal to (2) the net amount of such Total Payment without such reduction (but after subtracting the net amount of federal, state and local income taxes on such Total Payments and the amount of Excise Tax to which the Executive would he subject in respect of such unreduced Total Payments). The “Safe Harbor Amount” is the amount to which the Total Payments would hypothetically have to be reduced so that no portion of the Total Payments would be subject to the Excise Tax.

(b)    For purposes of determining whether any of the Total Payments will be subject to the Excise Tax and the amount of such Excise Tax, (i) all of the Total Payments shall be treated as “parachute payments” (within the meaning of Section 280G(b)(2) of the Code) unless, in the opinion of tax counsel (“Tax Counsel”) selected by the accounting firm which was, immediately prior to the Change in Control, the Company’s independent auditor (the “Auditor”), such payments or benefits (in whole or in part) do not constitute parachute payments, including by reason of Section 280G(b)(4)(A) of the Code, (ii) all “excess parachute payments” within the meaning of Section 280G(b)(l) of the Code shall be treated as subject to the Excise Tax unless, in the opinion of Tax Counsel, such excess parachute payments (in whole or in part) represent reasonable compensation for services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the base amount (within the meaning of Section 280G(b)(3) of the Code) allocable to such reasonable compensation, or are otherwise not subject to the Excise Tax, and (iii) the value of any noncash benefits or any deferred payment or benefit shall be determined by the Auditor in accordance with the principles of Sections 280G(d)(3) and (4) of the Code. If the Auditor is prohibited by applicable law or regulation from performing the duties assigned to it hereunder, then a different auditor, acceptable to both the Company and the Executive, shall be selected. The fees and expenses of Tax Counsel and the Auditor shall be paid by the Company.

(c)    In the event it is determined that the Safe Harbor Amount is payable to the Executive, then the severance payments provided under Section 2.6(a) which are cash shall first be reduced on a pro rata basis, among the different types of cash payments until the Safe Harbor Amount is reached; provided, however, in the event further reduction is needed to reach the Safe Harbor Amount after reducing all cash payments to zero, then the non-cash severance payments shall thereafter be reduced among the different types of non-cash payments on a pro rata basis, to the extent necessary so that no portion of the Total Payments is subject to the Excise Tax.

2.7    Terminations for Cause. If an Executive’s employment is terminated for Cause, the Executive shall not be entitled to any severance benefits under the Plan without regard to whether the Termination Date occurred within or outside of a Change of Control Period.

III. ADMINISTRATION OF PLAN

3.1    Committee’s Powers and Duties. The Company shall be the named fiduciary and shall have full power to administer the Plan in all of its details, subject to applicable requirements of law. The duties of the Company shall be performed by the Committee, provided that the Committee (i) delegates to the Chief Executive Officer the power to reduce or terminate the coverage of an Executive under the Plan as provided in Section 4.4 (a), and (ii) may delegate all or any portion of the duties to an Executive Officer of the Company. It shall be a principal duty of the Committee to see that the Plan is carried out, in accordance with its terms for the exclusive benefit of persons entitled to participate in the Plan. For this purpose, the Committee’s powers shall include, but not be limited to, the following authority, in addition to all other powers provided by the Plan:

(a)    to make and enforce such rules and regulations as it deems necessary or proper for the efficient administration of the Plan;

(b)    to interpret the Plan and all facts with respect to a claim for payment or benefits. Where such claim is made prior to a Change of Control, the Committee’s interpretation thereof shall be final and conclusive on all persons claiming payment or benefits under the Plan;

(c)    to decide all questions concerning the Plan and the eligibility of any person to participate in the Plan;

(d)    to make a determination as to the right of any person to a payment or benefit under the Plan (including, without limitation, to determine whether and when there has been a termination of an Executive’s employment and the cause of such termination and the amount of such payment or benefit);

(e)    to appoint such agents, counsel, accountants, consultants, claims administrators and other persons as may be required to assist in administering the Plan;

(f)    to allocate and delegate its responsibilities under the Plan and to designate other persons to carry out any of its responsibilities under the Plan, any such allocation, delegation or designation to be in writing except the committee shall not delegate any of its powers or authority under paragraphs (a)-(d) of this section 3.1;

(g)    to sue or cause suit to be brought in the name of the Plan; and

(h)    to obtain from the Company and from Executives such information as is necessary for the proper administration of the Plan.

3.2    Indemnification. The Company shall indemnify and hold harmless each member of the Committee in the performance of his or her duties under the plan against any and all expenses and liabilities arising out of his or her administrative functions or fiduciary responsibilities under the plan, including any expenses and liabilities that are caused by or result from an act or omission constituting the negligence of such member in the performance of such functions or responsibilities, but excluding expenses and liabilities that are caused by or result from such member’s own gross negligence or willful misconduct. Expenses against which such member shall be indemnified hereunder shall include, without limitation, the amounts of any settlement or judgment, costs, counsel fees, and related charges reasonably incurred in connection with a claim asserted or a proceeding brought or settlement thereof.

3.3    Compensation, Bond and Expenses. The members of the Committee shall not receive compensation with respect to their services for the Committee. To the extent required by applicable law, but not otherwise, Committee members shall furnish bond or security for the performance of their duties hereunder. Any expenses properly incurred by the Committee incident to the administration, termination or protection of the Plan, including the cost of furnishing bond, shall be paid by the Company.

3.4    Claims Procedure. Any Executive that the Committee determines is entitled to a benefit under the Plan is not required to file a claim for benefits. Any Executive who is not paid a benefit and who believes that he or she is entitled to a benefit or who has been paid a benefit and who believes that he or she is entitled to a greater benefit may file a claim for benefits under the Plan in writing with the Committee. In any case in which a claim for Plan benefits by an Executive is denied or modified, the Committee shall furnish written notice to the claimant within 90 days after receipt of such claim for Plan benefits (or within 180 days if additional information requested by the Committee necessitates an extension of the 90-day period and the claimant is informed of such extension in writing within the original 90-day period), which notice shall:

(a)    state the specific reason or reasons for the denial or modification;

(b)    provide specific reference to pertinent Plan provisions on which the denial or modification is based;

(c)    provide a description of any additional material or information necessary for the Executive or his representative to perfect the claim, and an explanation of why such material or information is necessary; and

(d)    explain the Plan’s claim review procedure as contained herein and describe the Executive’s right to bring an action under Section 502(a) of ERISA following a denial or modification on review.

In the event a claim for Plan benefits is denied or modified, if the Executive or his or her representative desires to have such denial or modification reviewed, he or she must, within 60 days following receipt of the notice of such denial or modification, submit a written request for review by the Committee of its initial decision. In connection with such request, the Executive or his or her representative may review any pertinent documents upon which such denial or modification was based and may submit issues and comments in writing. Within 60 days following such request for review the Committee shall, after providing a full and fair review,

render its final decision in writing to the Executive and his or her representative, if any, stating specific reasons for such decision and making specific references to pertinent Plan provisions upon which the decision is based. If special circumstances require an extension of such 60-day period, the Committee’s decision shall be rendered as soon as possible, but not later than 120 days after receipt of the request for review. If an extension of time for review is required, written notice of the extension shall be furnished to the Executive and his representative, if any, prior to the commencement of the extension period. The Committee shall give written notice of its decision on review to the Executive. In the event a claim for Plan benefits is denied or modified on review, such notice shall set forth the specific reasons for such denial or modification and provide specific references to the Plan provisions on which the denial or modification is based. The notice shall also provide that the Executive is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the Executive’s claim for benefits, including (i) documents, records or other information relied upon for the benefit determination, (ii) documents, records or other information submitted, considered or generated without regard to whether such documents, records or other information were relied upon in making the benefit determination, and (iii) documents, records or other information that demonstrates compliance with the standard claims procedure. The notice shall also contain a statement describing the Executive’s right to bring an action under Section 502(a) of ERISA. Any legal action with respect to a claim for Plan benefits must be filed no later than one year after the later of (1) the date the claim is denied by the Committee or (2) if a review of such denial is requested pursuant to the provisions above, the date of the final decision by the Committee with respect to such request.

IV. GENERAL PROVISIONS

4.1    Funding. The benefits provided herein shall be unfunded and shall be provided from the Company’s general assets.

4.2    Cost of Plan. The entire cost of the Plan shall be borne by the Company and no contributions shall be required of the Executives.

4.3    Plan Year. The Plan shall operate on a calendar year basis.

4.4    Amendment and Termination.

(a)    The Plan may be amended from time to time or terminated at the discretion of the Board. Notwithstanding anything to the contrary herein, the Committee, in its sole discretion, may reduce or terminate the coverage of any Executive under the Plan by giving prior written notice to the Executive at least one (1) year in advance of such termination of coverage; provided that, in the event of a Change of Control during the existence of the Plan, the Plan shall remain in full force and effect and benefits may not be reduced during the Change of Control Period.

(b)    The provisions set forth in Section 4.4(a) that otherwise restrict amendments to the Plan shall not apply to (i) an amendment to the administrative provisions of the Plan that is required pursuant to applicable law, (ii) an amendment that increases the benefits payable under the Plan or otherwise constitutes a bona fide improvement of an Executive’s rights under the Plan or (iii) an amendment which decreases the benefits of an Executive that is consented to in writing by such Executive.

4.5    Not a Contract of Employment. The adoption and maintenance of the Plan shall not be deemed to be a contract of employment between the Company and any person or to be consideration for the employment of any person. Nothing herein contained shall he deemed to give any person the right to be retained in the employ of the Company or to restrict the right of the Company to discharge any person at any time nor shall the Plan be deemed to give the Company the right to require any person to remain in the employ of the Company or to restrict any person’s right to terminate his or her employment at any time.

4.6    Severability. Any provision in the Plan that is prohibited or unenforceable in any jurisdiction by reason of applicable law shall, as to such jurisdiction, be ineffective only to the extent of such prohibition or unenforceability without invalidating or affecting the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

4.7    Nonalienation. Executives shall not have any right to pledge, hypothecate. anticipate or assign benefits or rights under the Plan, except by will or the laws of descent and distribution.

4.8    Effect of Plan. The Plan is intended to supersede all prior oral or written policies of the Company and all prior oral or written communications to Executives with respect to the subject matter hereof including any employment agreements with an Executive, and all such prior policies or communications are hereby null and void and of no further force and effect. Further, the Plan shall be binding upon the Company and any successor of the Company, by merger or otherwise, and shall inure to the benefit of and be enforceable by the Company’s Executives.

4.9    Taxes. The Company or its successor may withhold from any amounts payable to an Executive under the Plan such federal, state or local taxes as shall he required to be withheld pursuant to any applicable law or regulation.

4.10    Governing Law. The Plan will be construed and enforced pursuant to the laws of the State of Colorado giving effect to its conflict of laws.

4.11    Section 409A. Notwithstanding any provision of the Plan to the contrary, if on the date of the Executive’s separation from service the Executive is a “specified employee,” as defined in Section 409A of the Code, then all or such portion of any

severance payments, benefits, or reimbursements under the Plan that would be subject to the additional tax provided by Section 409A(a)(1)(B) of the Code if not delayed as required by Section 409A(a)(2)(B)(i) of the Code shall be delayed until the date that is six (6) months after the date of the Executive’s separation from service date (or, if earlier, the Executive’s date of death) and hall be paid as a lump sum (without interest) on such date. No payment shall be made under the Plan prior to the date the Executive incurs a “separation from service,” within the meaning of Section 409A of the Code and the regulations thereunder.

4.12    Notices. For the purposes of this Plan, notices and all other communications provided for in the Agreement shall be in writing and will be deemed to have been duly given when personally delivered, by facsimile transmission or sent by certified mail, return receipt requested, postage prepaid, or by expedited (overnight) courier with established national reputation, shipping prepaid or billed to sender, in either case addressed to the respective addresses last given by each party to the other (provided that all notices to the Company must he directed to the attention of the Secretary of the Company) or to such other address as either party may have furnished to the other in writing in accordance herewith. All notices and communication will be deemed to have been received on the date of delivery thereof, or on the second day after deposit thereof with an expedited courier service, except that notice of change of address will be effective only upon receipt.

IN WITNESS WHEREOF, the authorized representative of the Company has signed this document on June 9, 2011.

Petroleum Development Corporation

By: /s/Richard McCullough

Its: Chairman and CEO

Attest:

By: Daniel W. Amidon

Its: General Counsel and Secretary

A-5

A-1

EXHIBIT A

GENERAL RELEASE OF CLAIMS

This General Release (“Release”) is entered into as of this ____ day of ____________, 20__, by and between Petroleum Development Corporation (the “Company”), and ______________, an employee of the Company (the “Executive”) (collectively, the “Parties”).

WHEREAS, pursuant to the terms of the PDC Energy Change of Control and Severance Plan (the “Plan”), the Company has agreed to provide Executive certain benefits and payments under the terms and conditions specified therein, provided that Executive has executed and not revoked a general release of claims in favor of the Company;

WHEREAS, Executive’s employment with the Company is being terminated effective _____________, 20__; and

WHEREAS, the Patties wish to terminate their relationship amicably and to resolve, fully and finally, all actual and potential claims and disputes relating to Executive’s employment with and termination from the Company and all other relationships between Executive and the Company, up to and including the date of execution of this Release.

NOW, THEREFORE, in consideration of these Recitals and the promises and mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are expressly acknowledged, the Parties, intending to be legally bound, agree as follows:

1. Termination of Employment. Executive’s employment with the Company shall terminate on _____________, 20__ (the “Termination Date”).

2. Severance Benefits. Pursuant to the terms of the Plan, and in consideration of Executive’s release of claims and the other covenants and agreements contained herein and therein, and provided that Executive has signed this Release and delivered it to the Company and has not exercised any revocation rights as provided in Section 6 below, the Company shall provide the severance benefits described in Article II of the Plan (the “Benefits”) in the time and manner provided therein; provided, however, that the Company’s obligations will be excused if Executive breaches any of the provisions of the Release including, without limitation, Sections 7, 8 and 10 hereof. Executive acknowledges and agrees that the Benefits constitute consideration beyond that which, but for the mutual covenants set forth in this Release and the

covenants contained in the Plan, the Company otherwise would not be obligated to provide, nor would Executive otherwise he entitled to receive.

3. Release Effective Date. Provided that it has not been revoked pursuant to Section 6 hereof, this Release will become effective on the eighth (8th) day after the date of its execution by Executive (the “Release Effective Date”).

4. Effect of Revocation. Executive acknowledges and agrees that if Executive revokes this Release pursuant to Section 6 hereof, Executive will have no right to receive the Benefits.

5. General Release. In consideration of the Company’s obligations, Executive hereby releases, acquits and forever discharges Company and each of its subsidiaries and affiliates and each of their respective officers, employees. directors, successors and assigns from any and all claims, actions or causes of action in any way related to Executive’s employment with the Company or the termination thereof, whether arising from tort, statute or contract, including but not limited to, claims of defamation, claims arising under the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act of 1990, Title VII of the Civil Rights Act of 1964, as amended, the Americans with Disabilities Act, the Family and Medical Leave Act, the discrimination and wage payment laws of Colorado and West Virginia and any other federal, state or local statutes or ordinances of the United States, it being Executive’s intention and the intention of the Company to make this release as broad and as general as the law permits. Executive understands that this Agreement does not waive any rights or claims that may arise after Executive’s execution of it and does not apply to claims arising under the terms of this Agreement.

6. Review and Revocation Period. Executive acknowledges that the Company has advised Executive that Executive may consult with an attorney of Executive’s own choosing (and at Executive’s expense) prior to signing this Release and that Executive has been given at least twenty-one (21) days during which to consider the provisions of this Release, although Executive may sign and return it sooner. Executive further acknowledges that Executive has been advised by the Company that after executing this Release and delivering it to the Company, Executive will have seven (7) days to revoke this Release, and that this Release shall not become effective or enforceable until such seven (7) day revocation period has expired. Executive acknowledges and agrees that if Employee wishes to revoke this Release, Executive must do so in writing, and that such revocation must be signed by Executive and received by the Chairman of the Board of the Company (or the Chair of the Compensation Committee) no later than 5:00 p.m. Mountain Time on the seventh (7th) day after Executive has executed and delivered this Release. Executive acknowledges and agrees that, in the event that Executive revokes this Release, Executive will have no right to receive any benefits hereunder, including the Benefits. Executive represents that Executive has read this Release and understands its terms and enters into this Release freely, voluntarily and without coercion.

7. Non-Solicitation. The Executive shall not, directly or indirectly, for a period of two (2) years after the Termination Date (i) solicit, directly or indirectly, the services of any person who was a full-time employee of the Company, its subsidiaries, divisions, or affiliates, or otherwise induce such employee to terminate or reduce employment with the Company, or (ii) solicit the business of any person who was a client or customer of the Company, its subsidiaries, divisions, or affiliates, in each case at any time during the last year of the Term. For purposes of this Agreement, the term “person” includes natural persons, corporations, business trusts, associations, sole proprietorships, unincorporated organizations, partnerships, joint ventures, limited liability companies or partnerships, and governments, or any agencies, instrumentalities, or political subdivisions thereof.

8. Cooperation in Litigation. At the Company’s reasonable request, Executive shall use his good faith efforts to cooperate with the Company, its Affiliates, and each of its and their respective attorneys or other legal representatives (“Attorneys”) in connection with any claim, litigation or judicial or arbitral proceeding which is material to the Company and is now pending or may hereinafter be brought against the Released Parties by any third party; provided, that, Executive’s cooperation is essential, in the opinion of the Company, to the Company’s case. Executive’s duty of cooperation will include, but not be limited to (a) meeting with the Company’s and/or its Affiliates’ Attorneys by telephone or in person at mutually convenient times and places in order to state truthfully Executive’s knowledge of matters at issue and recollection of events; (b) appearing at the Company’s, its Affiliates’ and/or their Attorneys’ request (and, to the extent possible, at a time convenient to Executive that does not conflict with the needs or requirements of Executive’s then-current employer) as a witness at depositions or trials, without necessity of a subpoena, in order to state truthfully Executive’s knowledge of matters at issue; and (c) signing at the Company’s, its Affiliates’ and/or their Attorneys’ request declarations or affidavits that truthfully state matters of which Executive has knowledge. The Company shall reimburse Executive for the reasonable expenses incurred by him or her in the course of his or her cooperation hereunder and shall pay to Executive per diem compensation in an amount equal to the daily prorated portion of the Executive’s base salary immediately prior to the Termination Date. The obligations set forth in this Section 8 shall survive any termination or revocation of this Release.

9. Non-Admission of Liability. Nothing in this Release will be construed as an admission of liability by Executive or the Released Parties; rather, Executive and the Released Patties arc resolving all matters arising out of the employer­employee relationship between Executive and the Company and all other relationships between Executive and the Released Patties.

10. Nondisparagement. Executive agrees not to make negative comments or otherwise disparage the Company or its officers, directors, employees, shareholders or agents, in any manner likely to be harmful to them or their business, business reputation or personal reputation. The Company agrees that the members of the Board of Directors and officers of the Company as of the date hereof will not, while employed by the Company or serving as a director of the Company, as the case may be, make negative comments about the Executive or otherwise disparage the Executive in any manner that is likely to be harmful to the Executive’s business or personal reputation. The foregoing shall not be violated by truthful statements in response to legal process or required governmental testimony or filings, and the foregoing limitation on the

Company’s directors and officers will not be violated by statements that they in good faith believe are necessary or appropriate to make in connection with performing their duties for or on behalf of the Company.

11. Binding Effect. This Release will be binding upon the Parties and their respective heirs, administrators, representatives, executors, successors and assigns, and will inure to the benefit of the Parties and their respective heirs, administrators, representatives, executors, successors and assigns.

12. Governing Law. This Release will be governed by and construed and enforced in accordance with the laws of the State of Colorado applicable to agreements negotiated, entered into and wholly to be performed therein.

13. Severability. Each of the respective rights and obligations of the Parties hereunder will be deemed independent and may be enforced independently irrespective of any of the other rights and obligations set forth herein. If any provision of this Release should be held illegal or invalid, such illegality or in validity will not affect in any way other provisions hereof, all of which will continue, nevertheless, in full force and effect.

14. Counterparts. This Release may be signed in counterparts and each counterpart will be deemed to be an original but together all such counterparts will be deemed a single agreement.

15. Entire Agreement; Modification. This Release constitutes the entire understanding between the Parties with respect to the subject matter hereof and may not be modified without the express written consent of both Parties. This Release supersedes all prior written and/or oral and all contemporaneous oral agreements, understandings and negotiations regarding its subject matter. This Release may not be modified or canceled in any manner except by a writing signed by both Parties.

16. Acceptance. Executive may confirm his acceptance of the terms and conditions of this Release by signing and returning two (2) original copies of this Release to the Chairman of the Board of the Company, no later than 5:00 p.m. Mountain Time twenty-one (21) days after Executive’s receipt of notice of termination.

EXECUTIVE ACKNOWLEDGES AND REPRESENTS THAT EXECUTIVE HAS FULLY AND CAREFULLY READ THIS RELEASE PRIOR TO SIGNING IT AND UNDERSTANDS ITS TERMS. EXECUTIVE FURTHER ACKNOWLEDGES AND AGREES THAT EXECUTIVE HAS BEEN, OR HAS HAD THE OPPORTUNITY TO BE, ADVISED BY INDEPENDENT LEGAL COUNSEL OF EXECUTIVE’S OWN CHOICE AS TO THE LEGAL EFFECT AND MEANING OF EACH OF THE TERMS AND CONDITIONS OF THIS RELEASE, AND IS ENTERING INTO THIS RELEASE FREELY AND VOLUNTARILY AND NOT IN RELIANCE ON ANY PROMISES OR REPRESENTATIONS OTHER THAN AS SET FORTH IN THIS RELEASE.

IN WITNESS WHEREOF, the Company and the Executive have duly executed this Release as of the date first above written.

Company                        [Name of Executive]

Petroleum Development Corporation

By:                                                

Its:                    

EX-10.14.1

Exhibit 10.14.1

FINAL SIGNED

AMENDMENT TO THE PDC ENERGY

CHANGE OF CONTROL AND SEVERANCE PLAN

WHEREAS, Petroleum Development Corporation (the ‘‘Company”) adopted the PDC Energy Change of Control and Severance Plan (the “Plan”) effective as of January 1, 2011 primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees within the meaning of Sections 201(2), 301(3) and 40l(a) of ERISA; and

WHEREAS, the Company desires to amend the Plan, effective as of January 1, 2012.

NOW, THEREFORE, the Plan is amended effective as of January 1, 2012 as follows:

SECTION 1. The definition of “Executive” in Section 1.1(i) is amended to read as follows:

(i)“Executive” shall mean any individual who is part of a select group of management or highly compensated employees within the meaning of Sections 201(2), 301(3) and 401(a) of ERISA, including but not limited to either a Vice President or the Chief Accounting Officer of the Company, who is chosen by the Committee to participate in the Plan. Effective January 1, 2012: (A) With respect to an individual who is first employed as a Vice President of the Company on or after such date, such individual shall automatically be considered an Executive as of his or her date of hire, and (B) with respect to any other individual who is part of a select group of management or highly compensated employees within the meaning of Sections 201(2), 301(3) and 40l(a) of ERISA, such individual will initially participate in the Plan if and when selected as a participant by the Committee; provided that such Executive may be designated as a “CIC Protected Executive.” Such CIC Protected Executive will be entitled solely to those benefits provided under Section 2.2 of the Plan and shall not be entitled to those benefits provided under Section 2.1 of the Plan. An Executive who first becomes eligible to participate in the Plan on or after January 1, 2012, shall be deemed a CIC Protected Executive only if such individual is notified by the Committee in writing of such status during such Executive’s initial year of participation in the Plan. CIC Protected Executives shall be listed on Exhibit B which may be amended from time to time.

SECTION 2. The first paragraph of Section 3.1 is amended to read as follows:

3.1Committee’s Powers and Duties. The Company shall be the named fiduciary and shall have full power to administer the Plan in all of its details, subject to applicable requirements of law. The duties of the Company shall be performed by the Committee, provided that the Committee (i) delegates to the Chief Executive Officer the power to reduce or terminate the coverage of an Executive under the Plan as provided in Section 4.4(a) and to add CIC Protected Executives as participants in the Plan, provided, however, that the Chief Executive Officer shall be required to obtain the approval by the Committee if the added CIC Protected Executive would cause the number of Executives participating in the Plan to exceed twenty (20) at any point in time and provided further that the Chief Executive Officer shall report annually to the Committee the total number of CIC Protected Executives as reflected on Exhibit B, as amended from time to time, and (ii) may delegate all or any portion of the duties to an Executive Officer of the Company. It shall be a principal duty of the Committee to see that the Plan is carried out, in accordance with its terms, for the exclusive benefit of persons entitled to participate in the Plan. For this purpose, the Committee’s powers shall include, but not be limited to, the following authority, in addition to all other powers provided by the Plan:

SECTION 3. Section 4.4(a) is amended to read as follows:

(a)The Plan may be amended from time to time or terminated at the discretion of the Board; provided, however, the Board may delegate the power to amend or terminate the Plan to the Committee. Notwithstanding anything to the contrary herein, the Committee, in its sole discretion, may reduce or terminate the coverage of any Executive under the Plan by giving prior written notice to the executive at least one (1) year in advance of such reduction or termination of coverage; provided that in the event of a Change of Control during the existence of the Plan, the Plan shall remain in full force and effect and benefits may not be reduced during the Change of Control Period.

SECTION 4. Exhibit B, attached hereto, listing CIC Protected Executives, shall be added to the Plan.

IN WITNESS WHEREOF, the authorized representative of the Company has signed this

Amendment on December 22, 2011.

Petroleum Development Corporation

By: James M. Trimble

Its: President and CEO

Attest:

By: Sue Sander

Its: Assistant Corporate Secretary

EX-12.1

Exhibit No. 12.1

PDC ENERGY, INC.
Statement of Computation of Ratio of Earnings to Fixed Charges
	Year Ended December 31,
	2016				2015				2014			2013			2012
	(dollars in thousands)
Earnings:
Income (loss) from continuing operations before income taxes	$	(393,123	)		$	(106,588	)		$	177,228		(32,963	)		$	(30,688	)
Fixed charges (see below)	69,840				55,844				53,512			54,002			50,228
Amortization of capitalized interest	3,463				2,486				1,379			1,096			871
Interest capitalized	(4,489		)		(5,060		)		(3,468		)	(1,709	)		(896		)
Total adjusted earnings (loss) available for fixed charges	$	(324,309	)		$	(53,318	)		$	228,651		20,426			$	19,515
Fixed Charges:
Interest and debt expense (a)	$	61,972			$	47,571			$	47,842		50,143			$	47,505
Interest capitalized	4,489				5,060				3,468			1,709			896
Interest component of rental expense (b)	3,379				3,213				2,202			2,150			1,827
Total fixed charges	$	69,840			$	55,844			$	53,512		54,002			$	50,228
Ratio of Earnings to Fixed Charges	—			(c)	—			(c)	4.3		x	—		(c)	—			(c)

__________

(a) Represents interest expense on long-term debt and amortization of debt discount and issuance costs.

(b) Represents the portion of rental expense which we believe represents an interest component.

(c) For the years ended December 31, 2016, 2015, 2013, and 2012, earnings were insufficient to cover total fixed charges by $394.1 million, $109.2 million, $33.6 million, and $30.7 million, respectively.

EX-21.1

Exhibit No. 21.1

Subsidiaries of PDC Energy, Inc.

PDC Permian, Inc., a Delaware corporation, doing business as PDC Energy.

EX-23.1

Exhibit No. 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on FormS‑3 of PDC Energy, Inc. (No. 333-202853 and No. 333-215422) and to the incorporation by reference in the Registration Statements on Form S-8 of PDC Energy, Inc. (No. 333-189685, No. 333-167945, No. 333-137836, No. 333-118222 and No. 333-118215), of our report dated February 28, 2017, relating to the consolidated financial statements, financial statement schedule, and the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

February 28, 2017

EX-23.2

Exhibit No. 23.2

Consent of Independent Petroleum Engineers

We hereby consent to the incorporation by reference in the Registration Statement on Form S‑3 of PDC Energy, Inc. (No. 333-202853 and No. 333-215422) and to the incorporation by reference in the Registration Statements on Form S-8 of PDC Energy, Inc. (No. 333-189685, No. 333-167945, No. 333-137836, No. 333-118222 and No. 333-118215), of all references to our firm and information from our reserves report dated January 17, 2017, included in or made a part of PDC Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2016, and our summary report attached as Exhibit 99.1 to the Annual Report on Form 10-K.

	/s/ Ryder Scott Company, L.P.
	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F-1580
Denver, CO
February 28, 2017

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 of PDC Energy, Inc. (No. 333-202853 and No. 333-215422) and to the incorporation by reference in the Registration Statements on Form S-8 of PDC Energy, Inc. (No. 333-189685, No. 333-167945, No. 333-137836, No. 333-118222 and No. 333-118215), of all references to our firm and information from our reserves report dated January 19, 2017, included in or made a part of PDC Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2016, and our summary report attached as Exhibit 99.2 to the Annual Report on Form 10-K.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	s/ J. Carter Henson, Jr.
	J. Carter Henson, Jr., P.E.
	Senior Vice President

Houston, Texas

February 28, 2017

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Barton R. Brookman, certify that:

1. I have reviewed this Annual Report on Form 10-K of PDC Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 28, 2017
	/s/ Barton R. Brookman
	Barton R. Brookman
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, David W. Honeyfield, certify that:

1. I have reviewed this Annual Report on Form 10-K of PDC Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 28, 2017
	/s/ David W. Honeyfield
	David W. Honeyfield
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION

In connection with the Annual Report of PDC Energy, Inc. (the "Company") on Form 10-K for the period ended December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned certify pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Barton R. Brookman	February 28, 2017
Barton R. Brookman
President and Chief Executive Officer
/s/ David W. Honeyfield	February 28, 2017
David W. Honeyfield
Senior Vice President and Chief Financial Officer (Principal Financial Officer)

EX-99.1

Exhibit No. 99.1

January 17, 2016

PDC Energy

120 Genesis Boulevard

Bridgeport, West Virginia 26330

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of PDC Energy (PDC) as of December 31, 2016. The subject properties are located in the states of Colorado and Ohio. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 17, 2017 and presented herein, was prepared for public disclosure by PDC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of PDC's total net proved reserves as of December 31, 2016. Based on information provided by PDC, the third party estimate conducted by Ryder Scott addresses 90.8 percent of the total proved developed net liquid hydrocarbon reserves, 94.4 percent of the total proved developed net gas reserves, 88.4 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 91.4 percent of the total proved undeveloped net gas reserves of PDC.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2016 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

PDC Energy

Exhibit No. 99.1

As of December 31, 2016
	Proved
	Developed							Total
	Producing		Non-Producing			Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate - MBBL	26,660.2		—			76,595.9		103,256.1
Plant Products - MBBL	22,615.5		—			54,509.3		77,124.8
Gas - MMCF	250,578		—			520,562		771,140
Income Data (M$)
Future Gross Revenue	$	1,696,877	$	—		$	4,509,114	6,205,991
Deductions	578,679		51,006			2,635,148		3,264,833
Future Net Income (FNI)	$	1,118,198	$	(51,006	)	$	1,873,966	$	2,941,158
Discounted FNI @ 10%	$	791,948	$	(10,011	)	$	740,456	$	1,522,393

* The non-producing category includes shut-in wells waiting for abandonment.

PDC Energy

January 17, 2017

Page 3

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBBL). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton.The program was used at the request of PDC. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage which are shown as “Other Deductions.” The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 77 percent and gas reserves account for the remaining 23 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income - (M$)
	As of December 31, 2016
Discount Rate Percent		Total Proved
5		$	2,067,053
15		$	1,163,468
20		$	915,931
25		$	738,712

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PDC Energy

January 17, 2017

Page 4

reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At PDC’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward”. The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

PDC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which PDC ownsan interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PDC Energy

January 17, 2017

Page 5

that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods or analogy. One hundred percent of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include decline curve analysis which utilized extrapolations of historical production and pressure data available through December 2016 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by PDC and were considered sufficient for the purpose thereof.

One hundred percent of the proved developed non-producing and undeveloped reserves included herein were estimated by analogy methods. The data utilized from the existing producing wells to develop analogues were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

PDC has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by PDC with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by PDC. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PDC Energy

January 17, 2017

Page 6

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PDC. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

PDCfurnished us with the above mentioned average prices in effect on December 31, 2015. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by PDC. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by PDC to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$42.75/Bbl	$38.57/Bbl
	NGLs	WTI Cushing	$42.75/Bbl	$11.73/Bbl
	Gas	Henry Hub	$2.48/MMBTU	$1.90/MCF

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PDC Energy

January 17, 2017

Page 7

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by PDC and are based on the operating expense reports of PDC and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PDC. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by PDC and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by PDC were accepted without independent verification.

The proved undeveloped reserves in this report have been incorporated herein in accordance with PDC’s plans to develop these reserves as of December 31, 2016. The implementation of PDC’s development plans as presented to us and incorporated herein is subject to the approval process adopted by PDC’s management. As the result of our inquiries during the course of preparing this report, PDC has informed us that the development activities included herein have been subjected to and received the internal approvals required by PDC’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to PDC. Additionally, PDC has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by PDC were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PDC Energy

January 17, 2017

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We are independent petroleum engineers with respect to PDC. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by PDC Energy.

PDC Energy makes periodic filings on Form 10-K with the SEC under the Securities Exchange Act of 1934. Furthermore, PDC Energy has filed certain registration statements with the SEC under the Securities Act of 1933 into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of PDC Energy of the references to our name as well as to the references to our third party report for PDC Energy, which appears in the December 31, 2016 annual report on Form 10-K of PDC Energy. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by PDC Energy.

We have provided PDC Energy with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by PDC Energy and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Richard J. Marshall was the primary technical person responsible for overseeing the estimate of the future net reserves and income.

Mr. Marshall, an employee of Ryder Scott Company L.P. (Ryder Scott) beginning in 1981, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Mr. Marshall served in a number of engineering positions with Texaco, Phillips Petroleum, and others. For more information regarding Mr. Marshall’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Marshall earned a B.S. in Geology from the University of Missouri in 1974 and a M.S. in Geological Engineering from the University of Missouri at Rolla in 1976. Mr. Marshall is a registered Professional Engineer in the State of Colorado. He is a member of the Society of Petroleum Engineers, Wyoming Geological Association, Rocky Mountain Association of Geologists and the Society of Petroleum Evaluation Engineers.

Based on Mr. Marshall’s educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Marshall has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-99.2

January 19, 2017

Mr. Jim Lillo

PDC Energy, Inc.

1775 Sherman Street, Suite 3000

Denver, Colorado 80203

Dear Mr. Lillo:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2016, to the PDC Energy, Inc. (PDC) interest in certain oil and gas properties located in Culberson and Reeves Counties, Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 10 percent of all proved reserves owned by PDC. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for PDC's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the PDC interest in these properties, as of December 31, 2016, to be:

	Net Reserves			Future Net Revenue (M$)
Category	Oil (MMBL)	NGL (MMBL)	Gas (MMCF)	Total	Present Worth at 10%
Proved Developed Producing	3,353.2	1,580.9	13,873.8	102,034.3	70,390.2
Proved Undeveloped	11,559.5	5,583.6	48,682.9	235,251.9	82,083.4
Total Proved	14,912.7	7,164.5	62,556.7	337,286.2	152,473.6
Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing and proved undeveloped reserves. There are no proved developed non-producing reserves at the price and cost parameters used in this report. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is PDC's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for PDC's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue

has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2016. For oil and NGL volumes, the average West Texas Intermediate spot price of $42.75 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.48 per MMBTU is adjusted by gas purchaser for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $39.33 per barrel of oil, $14.53 per barrel of NGL, and $1.306 per MCF of gas.

Operating costs used in this report are based on operating expense records of PDC. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of PDC are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by PDC and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are PDC's estimates of the costs to abandon the wells and production facilities, net of any salvage value, and, as requested, are included for economic wells only. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the PDC interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on PDC receiving its net revenue interest share of estimated future gross production. Additionally, we have made no investigation of any firm transportation contracts that may be in place for these properties; no adjustments have been made to our estimates of future revenue to account for such contracts.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by PDC, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience

methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from PDC, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Neil H. Little, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2011 and has over 9 years of prior industry experience. Mike K. Norton, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

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Document and Entity Information Document Document - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 15, 2017	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	PDC ENERGY, INC.
Entity Central Index Key	0000077877
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		65,763,315
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,694,921,137

XML

Consolidated Balance Sheets (Audited) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 244,100	$ 850
Accounts receivable, net	143,392	104,274
Derivative Instruments and Hedges, Assets	8,791	221,659
Prepaid expenses and other current assets	3,542	5,266
Total current assets	399,825	332,049
Properties and equipment, net	4,008,266	1,940,552
Fair value of derivatives	2,386	44,387
Goodwill	62,041	0
Other assets	13,324	53,555
Total Assets	4,485,842	2,370,543
Current liabilities:
Accounts payable	66,322	92,613
Production tax liability	24,767	26,524
Fair value of derivatives	53,595	1,595
Funds held for distribution	71,339	29,894
Current portion of long-term debt	0	112,940
Accrued interest payable	15,930	9,057
Other accrued expenses	38,625	28,709
Total current liabilities	270,578	301,332
Long-term debt	1,043,954	529,437
Deferred income taxes	400,867	143,452
Asset retirement obligations	82,612	84,032
Fair value of derivatives	27,595	695
Other liabilities	37,482	24,398
Total liabilities	1,863,088	1,083,346
Shareholders' Equity:
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,704,568 and 40,174,776 issued as of December 31, 2016 and 2015, respectively	657	402
Additional paid-in capital	2,489,557	907,382
Retained earnings	134,208	380,422
Treasury shares - at cost, 28,763 and 20,220 as of December 31, 2016 and 2015, respectively	(1,668)	(1,009)
Total shareholders' equity	2,622,754	1,287,197
Total Liabilities and Shareholders' Equity	$ 4,485,842	$ 2,370,543

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Balance Sheet Parentheticals (Parentheticals) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Balance Sheet Parentheticals [Abstract]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	150,000,000	150,000,000
Common Stock, Shares, Issued	65,704,568	40,174,776
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	50,000,000	50,000,000
Preferred Stock, Shares Issued	0	0
Treasury Stock, Shares	28,763	20,220

XML

Consolidated Statements of Operations (Audited) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Natural gas, NGL and crude oil sales	$ 497,353	$ 378,713	$ 471,413
Sales from natural gas marketing	8,725	10,920	71,571
Commodity price risk management gain (loss), net	(125,681)	203,183	310,304
Well operations, pipeline income and other	2,518	2,510	2,919
Total revenues	382,915	595,326	856,207
Costs, expenses and other:
Lease operating expenses	59,950	56,992	42,402
Production taxes	31,410	18,443	25,615
Transportation, gathering and processing expenses	18,415	10,151	4,592
Cost of natural gas marketing	10,193	11,717	72,015
Exploration expense	4,669	1,102	947
Impairment of natural gas and crude oil properties	9,973	161,620	166,847
General and administrative expense	112,470	89,959	123,559
Depreciation, depletion and amortization from continuing operations	416,874	303,258	192,528
Provision for uncollectible notes receivable	44,038	0	0
Accretion of asset retirement obligations	7,080	6,293	3,415
(Gain) loss on sale of Leaseholds	(43)	(385)	507
Total cost, expenses and other	715,029	659,150	632,427
Income from operations	(332,114)	(63,824)	223,780
Interest expense	(61,972)	(47,571)	(47,842)
Interest income	963	4,807	1,290
Income (loss) from continuing operations before income taxes	(393,123)	(106,588)	177,228
Provision for income taxes	147,195	38,308	(69,967)
Income (loss) from continuing operations	(245,928)	(68,280)	107,261
Income (loss) from discontinued operations, net of tax	0	0	48,174
Net income (loss)	$ (245,928)	$ (68,280)	$ 155,435
Basic
Income (loss) from continuing operations	$ (5.01)	$ (1.74)	$ 3.00
Income (loss) from discontinued operations	0.00	0.00	1.34
Net income (loss) attributable to shareholders	(5.01)	(1.74)	4.34
Diluted
Income (loss) from continuing operations	(5.01)	(1.74)	2.93
Income (loss) from discontinued operations	0.00	0.00	1.31
Net income (loss) attributable to shareholders	$ (5.01)	$ (1.74)	$ 4.24
Weighted-average common shares outstanding:
Basic	49,052	39,153	35,784
Diluted	49,052	39,153	36,678

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Consolidated Statements of Cash Flows (Audited) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (245,928,000)	$ (68,280,000)	$ 155,435,000
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Net change in fair value of unsettled derivatives	333,770,000	35,791,000	(311,281,000)
Depreciation, depletion and amortization	416,874,000	303,258,000	201,656,000
Provision for uncollectible notes receivable	44,038,000	0	0
Impairment of natural gas and crude oil properties	9,973,000	161,620,000	167,280,000
Accretion of asset retirement obligations	7,080,000	6,293,000	3,455,000
Stock-based compensation	19,502,000	20,068,000	17,518,000
Excess tax benefits from stock-based compensation	0	(1,361,000)	(1,999,000)
(Gain) loss from sale of properties and equipment	43,000	385,000	75,972,000
Amortization of debt discount and issuance costs	16,167,000	7,040,000	6,938,000
Deferred income taxes	(137,249,000)	(41,415,000)	88,474,000
Inventory adjustment and other	2,603,000	(1,855,000)	(1,329,000)
Total adjustments to net income (loss) to reconcile to net cash provided by operating activities:	712,715,000	489,054,000	94,740,000
Changes in current assets and liabilities:
Accounts receivable	(32,627,000)	24,769,000	(34,598,000)
Other assets	2,303,000	(2,264,000)	(3,296,000)
Restricted cash	0	46,000	2,214,000
Production tax liability	9,223,000	(1,629,000)	3,358,000
Accounts payable and accrued expenses	(162,000)	(30,310,000)	21,453,000
Funds held for distribution	36,510,000	2,699,000	(4,372,000)
Other liabilities	4,229,000	(3,012,000)	1,755,000
Total changes in current assets and liabilities	19,476,000	(9,701,000)	(13,486,000)
Net cash provided by operating activities	486,263,000	411,073,000	236,689,000
Cash flows from investing activities:
Capital expenditures	(436,884,000)	(599,546,000)	(623,750,000)
Capital expenditures for other properties and equipment	(3,464,000)	(5,122,000)	(4,842,000)
Acquisition of natural gas and crude oil properties, net of cash acquired	(1,073,723,000)	0	0
Proceeds from sale of properties and equipment	4,945,000	405,000	154,457,000
Net cash used in investing activities	(1,509,126,000)	(604,263,000)	(474,135,000)
Cash flows from financing activities:
Proceeds from credit facility	85,000,000	397,000,000	263,750,000
Payment of credit facility	122,000,000	416,000,000	200,000,000
Redemption of convertible notes	(115,000,000)	0	0
Payment of debt issuance costs	(15,556,000)	(974,000)	(88,000)
Proceeds from sale of equity, net of issuance costs	855,074,000	202,851,000	0
Proceeds from senior notes, net of issuance costs	392,172,000	0	0
Proceeds from Convertible Debt	193,935,000	0	0
Excess tax benefits from stock-based compensation	0	1,361,000	1,999,000
Purchase of treasury stock	(6,935,000)	(6,056,000)	(5,392,000)
Proceeds from (Payments for) Other Financing Activities	(577,000)	(208,000)	0
Net cash provided by (used in) financing activities	1,266,113,000	177,974,000	60,269,000
Net increase (decrease) in cash and cash equivalents	243,250,000	(15,216,000)	(177,177,000)
Cash and cash equivalents, beginning of year	850,000	16,066,000	193,243,000
Cash and cash equivalents, end of year	244,100,000	850,000	16,066,000
Cash payments (receipts) for:
Interest, net of capitalized interest	43,406,000	45,642,000	46,809,000
Income taxes	167,000	10,049,000	1,800,000
Non-cash investing activities:
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	690,702,000	0	0
Change in accounts payable related to purchases of properties and equipment	(40,448,000)	(45,230,000)	39,667,000
Change in asset retirement obligation, with a corresponding increase to natural gas and crude oil properties, net of disposals	4,894,000	14,030,000	33,250,000
Change in other assets related to disposition of properties and equipment	0	0	39,048,000
Purchase of properties and equipment under capital leases	$ 1,404,000	$ 1,601,000	$ 0

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Consolidated Statement of Equity (Statement) - USD ($)	Total	Parent [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued			35,675,656			(5,508)
Issuance of stock awards, net of forfeitures			253,032
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Retirement of treasury shares			(703)			703
Purchase of treasury shares						(97,646)
Issuance of treasury shares						83,208
Non-employee directors' deferred compensation plan						(2,400)
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2013		$ 967,594,000	$ 357,000	$ 674,211,000	$ 293,267,000	$ (241,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Purchase of treasury shares		(5,392,000)				(5,392,000)
Issuance of stock awards, net of forfeitures		2,000	2,000
Share-based Compensation expense	$ 17,518,000	19,850,000		19,850,000
Issuance of treasury shares		0		(4,817,000)		4,817,000
Retirement of treasury shares		0		(35,000)		35,000
Non-employee directors' deferred compensation plan		(130,000)				(130,000)
Net income (Loss) attributable to shareholders	155,435,000	155,435,000			155,435,000
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2014		1,137,359,000	$ 359,000	689,209,000	448,702,000	$ (911,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued			35,927,985			(21,643)
Shares issued pursuant to sale of equity			4,002,000
Exercise of stock options			7,720
Issuance of stock awards, net of forfeitures			237,071
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Purchase of treasury shares						(120,864)
Issuance of treasury shares			0			127,159
Non-employee directors' deferred compensation plan						(4,872)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to sale of equity		202,851,000	$ 40,000	202,811,000
Purchase of treasury shares		(6,055,000)				$ (6,055,000)
Issuance of stock awards, net of forfeitures		3,000	3,000
Share-based Compensation expense	20,068,000	21,568,000		21,568,000
Issuance of treasury shares		0		(6,206,000)		6,206,000
Non-employee directors' deferred compensation plan		(249,000)				(249,000)
Net income (Loss) attributable to shareholders	(68,280,000)	(68,280,000)			(68,280,000)
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2015		1,287,197,000	$ 402,000	907,382,000	380,422,000	$ (1,009,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued			40,174,776			(20,220)
Shares issued pursuant to sale of equity			15,007,500
Exercise of stock options			46,084
Issuance of stock awards, net of forfeitures			411,731
Stock Issued During Period, Value, Conversion of Convertible Securities			792,406
Stock Issued During Period, Value, Acquisitions			9,386,768
Treasury Stock Transactions, Excluding Value of Shares Reissued [Abstract]
Purchase of treasury shares						(116,085)
Issuance of treasury shares			(114,697)			114,697
Non-employee directors' deferred compensation plan						(7,155)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to sale of equity		855,083,000	$ 150,000	854,933,000
Purchase of treasury shares		(6,935,000)				$ (6,935,000)
Issuance of stock awards, net of forfeitures		0	3,000	(3,000)
Share-based Compensation expense	19,502,000	19,502,000		19,502,000
Issuance of treasury shares		0		(6,661,000)		6,661,000
Non-employee directors' deferred compensation plan		(385,000)				(385,000)
Net income (Loss) attributable to shareholders	(245,928,000)	(245,928,000)			(245,928,000)
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	286,000
Cumulative Effect on Retained Earnings, Net of Tax	$ (286,000)
Stock Issued During Period, Value, Conversion of Convertible Securities		0	8,000	(8,000)
Stock Issued During Period, Value, Acquisitions		690,702,000	94,000	690,608,000
Adjustments to Additional Paid in Capital, Convertible Debt with Conversion Feature		23,518,000		23,518,000
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2016		$ 2,622,754,000	$ 657,000	$ 2,489,557,000	$ 134,208,000	$ (1,668,000)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued			65,704,568			(28,763)

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NATURE OF OPERATIONS AND BASIS OF PRESENTATION

12 Months Ended

Dec. 31, 2016

NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract]

Nature of Operations [Text Block]

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 acquires, produces, develops, and explores for crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and, beginning in December 2016, the Delaware Basin in Reeves and Culberson Counties, Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays, our Delaware Basin operations are currently focused in the Wolfcamp zones, and our Ohio operations are focused in the Utica Shale play. As of December 31, 2016, we owned an interest in approximately 2,900 productive gross wells. We are engaged in two business segments: The Oil and Gas Exploration and Production Segment and the Gas Marketing Segment. In October 2014, we sold our entire 50 percent ownership interest in our joint venture, PDCM, to an unrelated third-party.

The audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries PDC Permian, Inc. and Riley Natural Gas ("RNG"), our proportionate share of our four affiliated partnerships and, for the information presented covering the year ended December 31, 2014, our proportionate share of PDCM. All material intercompany accounts and transactions have been eliminated in consolidation.

The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas, and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; impairment of proved and unproved properties; valuation and allocations of purchased businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets.

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RECENT ACCOUNTING STANDARDS

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.

Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas, and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes.

All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose for issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of gas marketing. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows.

The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below.

Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have three units-of-production fields which are the Wattenberg Field, the Delaware Basin, and the Utica Shale. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations, and common cost environments in these areas. We calculate quarterly depreciation, depletion, and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statements of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A.

Exploration costs, including geological and geophysical expenses, seismic costs on unproved leasehold, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability, or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded.

Proved Property Impairment. Upon a triggering event and when general industry conditions warrant review, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas, and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices, or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A.

Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates, and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.

Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment.

The following table presents the estimated useful lives of our other property and equipment:

Transportation, pipeline, and other equipment	2 - 30 years
Buildings	20 - 40 years

Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $3.8 million, $4.5 million, and $4.1 million in 2016, 2015, and 2014, respectively.

Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $4.5 million, $5.1 million, and $3.5 million in 2016, 2015, and 2014, respectively.

Goodwill. Goodwill represents the residual value of purchase price over net tangible and identifiable intangible assets of an acquired business and is stated at cost. Goodwill is not amortized; rather it is assessed annually for impairment, or more frequently if any event indicates that the carrying amount of goodwill may be impaired.

Assets Held for Sale and Discontinued Operations. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. Assets held for sale of $5.3 million as of December 31, 2016, represents the fair value of field office facilities and a parcel of land. Assets held for sale of $2.9 million as of December 31, 2015, represents the fair value of a parcel of land. These amounts are included in properties and equipment, net on our consolidated balance sheets.

For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations.

Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem, and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas, and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed and included in the statement of operations line item production taxes. Affiliated partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $29.0 million and $19.0 million in December 31, 2016 and 2015, respectively.

Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2016 and 2015, we had no valuation allowance.

Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes, and the 2022 Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving credit facility are included in other accrued expenses on the consolidated balance sheets.

Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations.

Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.

Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below.

Crude oil, natural gas, and NGLs sales. Crude oil, natural gas, and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred, and collection of revenue is reasonably assured. Our crude oil, natural gas, and NGLs sales are recorded under either the "net-back" or "gross" method of accounting, depending upon the transportation, gathering or processing method used. We use the net-back method of accounting for a portion of our crude oil production in the Wattenberg Field and for substantially all crude oil production in the Delaware Basin and the Utica Shale, as well as natural gas and NGLs from the Delaware Basin and the Wattenberg Field as the majority of the purchasers of these commodities also provide transportation, gathering, and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the gross method of accounting for Wattenberg Field crude oil delivered through the White Cliffs and Saddle Butte pipelines 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. Under this method, we recognize revenues based on the gross selling price.

Gas marketing. Gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our gas marketing subsidiary, RNG, suppliers, and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled commodity derivatives of the RNG commodity-based derivative transactions for gas marketing are included in sales from or cost of gas marketing, as applicable.

Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses and assets. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices, and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.

In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value.

We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2016, 2015, or 2014.

Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas, and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs, and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations.

Recently Adopted Accounting Standards.

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

In March 2016, the FASB issued an accounting update on stock-based compensation that is intended to simplify several aspects of the accounting for employee share-based payment award transactions. Areas of simplification include income tax consequences, classification of the awards as either equity or liabilities and the classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. We early adopted this standard in the fourth quarter of 2016.

• The primary impact of the adoption was the recognition of excess tax benefits in our provision for income taxes rather than additional paid-in capital, as well as the adjustment in stock-based compensation expense as a result of our changes in forfeiture policy. The new guidance eliminates the requirement to delay the recognition of excess tax benefits until it reduces current taxes payable. We adopted this change on a prospective basis, and recorded unrecognized excess tax benefits amounting to $1.5 million, which increased retained earnings in the fourth quarter of 2016.

• The new guidance also requires us to record, subsequent to the adoption, excess tax benefits and tax deficiencies in the period they occur. Prior to the adoption, the excess tax benefits would have been recorded as APIC. This change could create future volatility in our effective tax rate depending upon the amount of exercise or vesting activity from our stock awards. Under the new guidance, we have elected to change our policy and have started to recognize forfeitures of awards as they occur. The change in forfeiture policy was adopted using a modified retrospective transition method. We recorded a cumulative-effect adjustment to decrease retained earnings by $0.3 million upon transition on January 1, 2016, and an increase of stock-based compensation of $0.1 million during the fourth quarter of 2016. Per the guidance in the accounting standard update, the adjustment to stock-based compensation should be recorded on a retrospective basis. Our adjustment was not material to our condensed consolidated financial statements, therefore, we recorded the entire adjustment in the fourth quarter of 2016.

• The amendment to the minimum statutory withholding tax requirements was adopted on a modified retrospective basis. The adoption had no impact on retained earnings.

• In addition, we adopted the presentation of taxes paid related to the net share settlement as a financing activity on the statement of cash flows on a retrospective basis. Adoption had no impact to any of the periods presented in our consolidated cash flows statements since such cash flows have historically been presented as a financing activity.

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 underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (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. In March 2016, the FASB issued an update to the standard intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations when recognizing revenue. In December 2016, the FASB issued technical corrections and improvements to the standard. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are in the process of assessing potential impacts of the new standard on our existing revenue recognition criteria, as well as on related revenue disclosures.

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 in the process of assessing 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. This is an expansive set of revisions to the cash flow presentation standards, but at this time we do not believe that these changes will impact our consolidated financial statements.

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BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Notes)

12 Months Ended

Dec. 31, 2016

Business Acquisition [Line Items]

Business Combination Disclosure [Text Block]

BUSINESS COMBINATION

Delaware Basin Acquisition completed December 6, 2016. On December 6, 2016, we closed on an acquisition which has been accounted for as a business combination. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion, comprised of approximately $952.1 million in cash, including the repayment of $40.0 million of debt from the seller 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 details of the purchase price and the preliminary allocation of the purchase price for the first transaction are presented below (in thousands):

	Year Ended December 31, 2016
Acquisition costs:
Cash, net of cash acquired	$	912,142
Retirement of seller's debt	40,000
Total cash consideration	952,142
Common stock, 9.4 million shares	690,702
Other purchase price adjustments	1,026
Total acquisition costs	$	1,643,870
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	8,201
Crude oil and natural gas properties - proved	216,000
Crude oil and natural gas properties - unproved	1,721,334
Infrastructure, pipeline, and other	32,590
Construction in progress	12,148
Goodwill	62,041
Total assets acquired	2,052,314
Liabilities assumed:
Current liabilities	(24,844		)
Asset retirement obligations	(3,705		)
Deferred tax liabilities, net	(379,895		)
Total liabilities assumed	(408,444		)
Total identifiable net assets acquired	$	1,643,870

The estimated fair value of assets acquired and liabilities assumed in the acquisition presented above are preliminary and subject to post-closing adjustments as more detailed analysis associated with the acquired properties are completed. As of the date of this report, we expect that it may take into mid-2017 until all post-closing adjustments are finalized.

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, and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are 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 is calculated as the excess of the purchase price over the fair value of net assets acquired 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. Goodwill related to the Delaware Basin acquisition was recorded in our oil and gas exploration and production segment. Any value assigned to goodwill is not expected to be deductible for income tax purposes.

Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total revenue and $1.7 million of loss from operations. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2016 and December 31, 2015, assuming the acquisition had been completed as of January 1, 2015. This pro forma financial information includes the Securities Issuances in September 2016, the shares issued to the sellers, and other acquisition costs. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.

	Years Ended December 31,
	2016			2015
	(in thousands, except per share amounts)
Total revenue	$	412,746		$	598,932
Net loss	$	(270,942	)	$	(138,904	)
Earnings (loss) per share:
Basic and diluted	$	(4.22	)	$	(2.41	)

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PROPERTIES AND EQUIPMENT

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure [Text Block]

PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net of accumulated DD&A:

	As of December 31,
	2016			2015
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	3,499,718		$	2,881,189
Unproved	1,874,671			60,498
Total crude oil and natural gas properties	5,374,389			2,941,687
Infrastructure, pipeline, and other	62,093			30,098
Land and buildings	12,165			12,667
Construction in progress	122,591			113,115
Properties and equipment, at cost	5,571,238			3,097,567
Accumulated DD&A	(1,562,972		)	(1,157,015		)
Properties and equipment, net	$	4,008,266		$	1,940,552

Delaware Basin Acreage Acquisition. On December 30, 2016, we closed the purchase of approximately an additional 4,600 net bolt-on acres in Reeves and Culberson Counties, Texas, for consideration to the sellers of approximately $120.6 million, in cash, subject to post-closing adjustments. The transaction was accounted for as an acquisition of assets.

Acreage Exchange. In September 2016, we closed on an acreage exchange transaction with Noble Energy, Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The assets exchanged were all in the same unit of production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged.

The following table presents impairment charges recorded for properties and equipment:

	Year Ended December 31,
	2016		2015		2014
	(in thousands)
Impairment of proved and unproved properties	$	5,562	$	154,608	$	161,604
Amortization of individually insignificant unproved properties	1,379		7,012		4,465
Land and buildings	3,032		—		778
Impairment of properties and equipment	9,973		161,620		166,847
Discontinued operations:
Impairment of proved and unproved properties	—		—		433
Total discontinued operations	—		—		433
Total impairment of properties and equipment	$	9,973	$	161,620	$	167,280

Due to a significant decline in commodity prices and decreases in our net realized sales prices, we experienced triggering events during 2015 and 2014 that required us to assess our crude oil and natural gas properties for possible impairment.  As a result of our assessments, we recorded impairment charges of $150.3 million and $158.3 million in 2015 and 2014, respectively, to write-down our Utica Shale proved and unproved properties.  Of these impairment charges, $24.7 million and $112.6 million were recorded in 2015 and 2014, respectively, to write-down certain capitalized well costs on our Utica Shale proved producing properties. In 2015 and 2014, we also recorded impairment charges of $125.6 million and $45.7 million to write-down our Utica Shale lease acquisition costs.  The impairment charges, which are included in the consolidated statements of operations line item impairment of properties and equipment, represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair values.  We continued to monitor whether any further impairments were triggered and required measurement throughout 2016 given the continued volatility of commodity prices and the continued capital investment in the development and acquisition of oil and gas properties. No such triggering events occurred during 2016. Impairment charges in 2016 relate to the write-off of certain leases that were no longer part of our development plan and to reflect the fair value of other land and buildings that is held for sale as of December 31, 2016.

Suspended Well Costs

As of December 31, 2016 and 2015, there were no suspended well costs or wells pending determination.

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DERIVATIVE FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2016, we had derivative instruments, which were comprised of collars, fixed-price commodity swaps, basis protection swaps, and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 81,720 BBtu of natural gas and 13,342 MBbls of crude oil. The commodity derivative contracts were entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices.

As of December 31, 2016, our derivative instruments were comprised of collars, fixed-price commodity swaps, basis protection swaps, and physical sales and purchases.

• Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty;

• Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty;

• Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of 2016, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and

• Physical sales and purchases are commodity derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical commodity derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale.

We have elected not to designate any of our derivative instruments as cash flow hedges, and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of gas marketing.

The following table presents the balance sheet location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2016 and 2015:

Derivative instruments:		Consolidated Balance sheet line item	2016		2015
			(in thousands)
Derivative assets:	Current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	$	8,239	$	221,161
	Related to gas marketing	Fair value of derivatives	251		441
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	301		57
			8,791		221,659
	Non-current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	1,104		44,292
	Related to gas marketing	Fair value of derivatives	19		51
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	1,263		44
			2,386		44,387
Total derivative assets			$	11,177	$	266,046
Derivative liabilities:	Current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	$	53,353	$	—
	Related to gas marketing	Fair value of derivatives	212		417
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	30		1,178
			53,595		1,595
	Non-current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	27,581		275
	Related to gas marketing	Fair value of derivatives	14		46
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	—		374
			27,595		695
Total derivative liabilities			$	81,190	$	2,290

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

	Year Ended December 31,
Consolidated statements of operations line item	2016			2015			2014
	(in thousands)
Commodity price risk management gain (loss), net -
Net settlements	$	208,103		$	238,935		$	(837	)
Net change in fair value of unsettled derivatives	(333,784		)	(35,752		)	311,141
Total commodity price risk management gain (loss), net	$	(125,681	)	$	203,183		$	310,304
Sales from gas marketing -
Net settlements	$	543		$	778		$	(208	)
Net change in fair value of unsettled derivatives	(676		)	(318		)	364
Total sales from gas marketing	$	(133	)	$	460		$	156
Cost of gas marketing -
Net settlements	$	(483	)	$	(745	)	$	346
Net change in fair value of unsettled derivatives	690			279			(451		)
Total cost of gas marketing	$	207		$	(466	)	$	(105	)

All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets.

The following table reflects the impact of netting agreements on gross derivative assets and liabilities:

As of December 31, 2016	Derivative instruments, recorded in 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

As of December 31, 2015	Derivative instruments, recorded in consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	266,046	$	(1,921	)	$	264,125
Liability derivatives:
Derivative instruments, at fair value	$	2,290	$	(1,921	)	$	369

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FAIR VALUE MEASUREMENTS AND DISCLOSURES

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value, Measurement Inputs, Disclosure [Text Block]

FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

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

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

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

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

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

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

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

	As of December 31,
	2016									2015
	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)
Total assets	$	6,350		$	4,827		$	11,177		$	174,758	$	91,288	$	266,046
Total liabilities	66,789			14,401			81,190			2,290		—		2,290
Net asset (liability)	$	(60,439	)	$	(9,574	)	$	(70,013	)	$	172,468	$	91,288	$	263,756

The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value:

	2016			2015			2014
	(in thousands)
Fair value of Level 3 instruments, net asset beginning of period	$	91,288		$	62,356		$	1,111
Changes in fair value included in consolidated statement of operations line item:
Commodity price risk management gain (loss), net	(28,530		)	65,018			62,003
Sales from gas marketing	(20		)	146			(22		)
Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net	(72,242		)	(36,169		)	(737		)
Sales from gas marketing	(70		)	(63		)	1
Fair value of Level 3 instruments, net asset (liability) end of period	$	(9,574	)	$	91,288		$	62,356
Net change in fair value of Level 3 unsettled derivatives included in statement of operations line item:
Commodity price risk management gain (loss), net	$	(12,905	)	$	43,540		$	15,632
Sales from gas marketing	—			—			3
Total	$	(12,905	)	$	43,540		$	15,635

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 the financial statements.

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 for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. 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, natural gas and NGLs will be sold.

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 or convertible 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 December 31, 2016:

	Estimated Fair Value		% of Par
	(in millions)
Senior notes:
2021 Convertible Notes	$	220.2	110.1	%
2024 Senior Notes	408.0		102.0	%
2022 Senior Notes	535.0		107.0	%

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 vehicle lease.

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CONCENTRATION OF RISK

12 Months Ended

Dec. 31, 2016

Concentration Risks, Types, No Concentration Percentage [Abstract]

Concentration Risk Disclosure [Text Block]

CONCENTRATION OF RISK

Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts:

	As of December 31,
	2016			2015
	(in thousands)
Crude oil, natural gas and NGLs sales	$	97,520		$	41,873
Joint interest billings	20,118			35,017
Derivative counterparties	10,266			24,437
Income tax receivable	11,505			—
Insurance reimbursement	—			879
Other	6,173			4,077
Allowance for doubtful accounts	(2,190		)	(2,009		)
Accounts receivable, net	$	143,392		$	104,274

Our accounts receivable primarily relate to sales of our crude oil, natural gas, and NGLs production, receivable balances from other third parties that own working interests in the properties we operate, and derivative counterparties. For the years ended December 31, 2016 and 2015, amounts written off to allowance for doubtful accounts were not material. As of December 31, 2016, we had no customers representing 10 percent or greater of our accounts receivable balance. As of December 31, 2015, we had one customer representing 10 percent or greater of our accounts receivable balance.

Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues:

	Year Ended December 31,
Customer	2016		2015		2014
Suncor Energy Marketing, Inc.	22.3	%	14.3	%	19.7	%
DCP Midstream, LP	20.2	%	13.2	%	15.1	%
Aka Energy Group, LLC	13.4	%	—	%	—	%
Concord Energy, LLC	13.4	%	23.2	%	18.3	%
Bridger Energy, LLC	11.5	%	—	%	—	%
Shell Trading Company	—	%	13.8	%	—	%
Teppco Crude Oil, LLC	—	%	—	%	12.9	%

The concentration of revenue represented by the customers noted above relate to our oil and gas exploration and production segment.

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; however, 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 December 31, 2016, taking into account the estimated likelihood of nonperformance.

Note Receivable

The following table presents information regarding our note receivable outstanding:

	As of December 31,
	2016			2015
	(in thousands)
Principal and PIK Interest outstanding at beginning of period	$	43,069		$	39,707
PIK Interest	969			3,362
Principal and PIK Interest outstanding at end of period	44,038			43,069
Allowance for uncollectible notes receivable	(44,038		)	—
Note receivable, net	$	—		$	43,069

In October 2014, we sold our entire 50 percent ownership interest in PDCM to an unrelated third-party as described in the footnote titled Divestiture and Discontinued Operations. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million, bearing varying interest rates beginning at eight percent and increasing annually. Pursuant to the Note agreement, interest shall be paid quarterly, in arrears, commencing December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. Through December 31, 2016, the issuer of the Note had elected the PIK Interest option for each quarterly period since inception. The principal and any unpaid interest shall be due and payable in full in September 2020 and can be prepaid in whole or in part at any time, and in certain circumstances must be repaid prior to maturity. Any such prepayment will be made without premium or penalty. Legally, the Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets; however, we believe that the collection of the Note is not reasonably assured.

We examine the Note for evidence of collectability, evaluating factors such as the creditworthiness of the issuer of the Note and the value of the underlying assets that secure the Note. We performed our evaluation and cash flow analysis during the first quarter of 2016 and, based upon the year-end financial statements for 2015, the crude oil and natural gas reserve report of the issuer of the Note, and existing market conditions, determined that collection of the Note and PIK Interest was not reasonably assured. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million outstanding balance as of March 31, 2016, which was included in the consolidated balance sheet line item other assets. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Note and began accounting for the interest on the Note under the cash basis method. To date, we have not received any interest payments. As of December 31, 2016, there has been no change to our assessment of the collectibility of the Note or related interest, and continue to believe collection is not reasonably assured. Under the effective interest method, we previously recognized $4.5 million of interest income for the year ended December 31, 2015, of which $3.4 million was PIK Interest. As of December 2015, the $43.1 million outstanding balance on the Note was included in the consolidated balance sheet line item other assets.

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

	As of December 31,
	2016		2015
	(in thousands)
Employee benefits	$	22,282	$	17,774
Asset retirement obligations	9,775		5,460
Environmental expenses	3,238		4,143
Other	3,330		1,332
Other accrued expenses	$	38,625	$	28,709

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INCOME TAXES

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

The table below presents the components of our provision for income taxes from continuing operations for the years presented:

	Year Ended December 31,
	2016		2015			2014
	(in thousands)
Current:
Federal	$	9,646	$	(2,944	)	$	(1,514	)
State	300		(163		)	966
Total current income tax benefit (expense)	9,946		(3,107		)	(548		)
Deferred:
Federal	118,427		37,352			(60,698		)
State	18,822		4,063			(8,721		)
Total deferred income tax benefit (expense)	137,249		41,415			(69,419		)
Income tax benefit (expense) from continuing operations	$	147,195	$	38,308		$	(69,967	)

The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations:

	Year Ended December, 31,
	2016		2015		2014
Statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net	2.6		2.7		2.8
Effect of state income tax rate changes	0.6		(0.3	)	—
Percentage depletion	—		0.3		(0.3	)
Non-deductible compensation	(0.5	)	(1.2	)	0.7
Excess tax benefits from stock-based compensation	0.4		—		—
Other	(0.7	)	(0.6	)	1.3
Effective tax rate	37.4	%	35.9	%	39.5	%

Amendments related to accounting for excess tax benefits of stock-based compensation have been adopted prospectively, resulting in recognition of excess tax benefits against income tax expenses rather than APIC of $1.5 million for the year ended December 31, 2016. Excess tax benefits in the amount of $1.4 million were recognized as APIC during the year ended December 31, 2015, resulting from the vesting of stock-based compensation.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2016 and 2015 are presented below. Of note, the table includes the $403.7 million effect of including the deferred tax liability for the difference in the book and tax basis of the oil and gas properties acquired in the December 6, 2016, business combination and a $23.8 million of acquired deferred tax assets:

	As of December 31,
	2016		2015
	(in thousands)
Deferred tax assets:
Deferred compensation	$	9,338	$	13,104
Asset retirement obligations	34,359		34,101
Federal NOL carryforward	29,988		—
State NOL and tax credit carryforwards, net	5,189		3,376
Alternative minimum tax - credit carryforward	5,184		2,812
Allowance for note receivable	17,292		—
Net change in fair value of unsettled derivatives	26,262		—
Other	4,716		3,412
Total gross deferred tax assets	132,328		56,805
Deferred tax liabilities:
Properties and equipment	518,964		99,191
Net change in fair value of unsettled derivatives	—		100,369
Convertible debt	14,231		697
Total gross deferred tax liabilities	533,195		200,257
Net deferred tax liability	$	400,867	$	143,452

Deferred tax assets increased in 2016, primarily due to the allowance for a note receivable, acquired federal NOL from the stock acquisition component of the Delaware Basin acquisition, current year generated NOL and the reduced fair value of unsettled derivatives.

Deferred tax liabilities increased in 2016, primarily due to the deferred tax liability arising from the excess book basis versus tax carryover basis of the properties and equipment relating to the stock acquisition component of the Delaware Basin acquisition. Deferred tax liabilities also increased due to the 2021 Convertible Notes and accelerated deductions on properties and equipment. These were partially offset by the settlement of commodity derivatives and the decrease in fair value of unsettled commodity derivatives.

During the year ending December 31, 2016, we generated a federal NOL of $55.4 million of which $32.2 million will be utilized as a carryback leaving a federal NOL carryforward of $23.1 million that will begin to expire in 2036, and we have alternative minimum tax credits of $5.2 million that may be carried forward indefinitely. Also, we acquired a federal NOL of $62.5 million as a component of the Delaware Basin acquisition that will begin to expire in 2034 which is subject to an annual limitation of $15.1 millionas a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382.

As of December 31, 2016, we have state NOL carryforwards of $130.5 million that begin to expire in 2030 and state credit carryforwards of $1.8 million that begin to expire in 2022.

Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2016. The total amount of unrecognized tax benefits that would affect the effective tax rate decreased to zero in the current year due to a settlement with the IRS on a tax filing position related to our 2014 federal tax return. The statutes of limitations for most of our state tax jurisdictions are open from 2012 forward.

The IRS fully accepted our recently filed 2015 return, with minor agreed-upon adjustments, after the IRS CAP post-filing review process was completed in early January 2017. We are currently participating in the CAP Program for the review of our 2016 and 2017 tax years. Participation in the CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings.

There has been increased discussion by the federal government of a potential reduction of the corporate income tax rate and corresponding changes to the tax code. In the event of a change in federal or state income tax rates, the impact of the rate change will be required to be recorded through deferred income tax expense. Should statutory income tax rates decrease, our deferred tax liability will decrease, resulting in deferred tax benefit for the period. If the statutory income tax rates increase, our deferred tax liability would increase resulting in a deferred tax expense.

As of December 31, 2016, we were current with our income tax filings in all applicable state jurisdictions.

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2016

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

LONG-TERM DEBT

Long-term debt consists of the following:

	As of December 31,
	2016			2015
	(in thousands)
Senior notes:
1.125% Convertible Notes due 2021:
Principal amount	$	200,000		$	—
Unamortized discount	(37,475		)	—
Unamortized debt issuance costs	(4,584		)	—
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs	157,941			—
6.125% Senior Notes due 2024:
Principal amount	400,000			—
Unamortized debt issuance costs	(7,544		)	—
6.125% Senior Notes due 2024, net of unamortized debt issuance costs	392,456			—
7.75% Senior notes due 2022:
Principal amount	500,000			500,000
Unamortized debt issuance costs	(6,443		)	(7,563		)
7.75% Senior notes due 2022, net of unamortized debt issuance costs	493,557			492,437
3.25% Convertible senior notes due 2016:
Principal amount	—			115,000
Unamortized discount	—			(1,852		)
Unamortized debt issuance costs	—			(208		)
3.25% Convertible senior notes due 2016, net of unamortized discount and debt issuance costs	—			112,940
Total senior notes	1,043,954			605,377
Revolving credit facility	—			37,000
Total debt, net of unamortized discount and debt issuance costs	1,043,954			642,377
Less current portion of long-term debt	—			112,940
Long-term debt	$	1,043,954		$	529,437

Senior Notes

2021 Convertible Notes.  In September 2016, we issued $200.0 million of 1.125% convertible senior notes due 2021 in a public offering. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016 between us and the U.S. Bank National Association, as trustee. 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, commencing on March 15, 2017. The 2021 Convertible Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the 2021 Convertible Notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The proceeds from the issuance of the 2021 Convertible Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin, to pay related fees and expenses, and for general corporate purposes.

The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. 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, as well as cash in lieu of fractional shares.

We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible.

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 for similar terms and priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of 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 and are being amortized as interest expense over the life of the notes using the effective interest method. As of December 31, 2016, 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%. Based upon the December 31, 2016 stock price of $72.58 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount.

2024 Senior Notes. In September 2016, we issued $400.0 million aggregate principal amount of 6.125% senior notes due September 2024 in a private placement to qualified institutional buyers. In connection with the issuance of the 2024 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms. In addition, we have agreed, in certain circumstances, to file a shelf registration statement covering the resale of the 2024 Senior Notes by the holders. The proceeds from the issuance of the 2024 Senior Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin (see the footnotes titled Business Combination and Properties and Equipment),to pay related fees and expenses, and for general corporate purposes.

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, commencing on March 15, 2017. 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. The 2024 Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.

The 2024 Senior Notes are redeemable after September 15, 2019, at fixed redemption prices beginning at 104.594 percent of the principal amount redeemed. At any time prior to September 15, 2019, we may redeem all or part of the 2024 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at September 15, 2019, and remaining interest payments on the 2024 Senior Notes at the time of redemption.

At any time prior to September 15, 2019, we may redeem up to 35 percent of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.

Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase.

The indenture governing the 2024 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries.

2022 Senior Notes. In October 2012, we issued $500.0 million aggregate principal amount 7.75% senior notes due October 15, 2022 in a private placement to qualified institutional buyers. The 2022 Senior Notes have been registered. 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. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness and rank effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.

At any time prior to October 15, 2017, we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture. On or after October 15, 2017, we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption.

Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase.

The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company.

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

As of December 31, 2016, we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the foreseeable future.

2016 Convertible Senior Notes. In November 2010, we issued $115.0 million aggregate principal amount of 3.25% convertible senior notes due that were due in 2016 ("2016 Convertible Notes") in a private placement. The maturity for the payment of principal was May 15, 2016, and we paid the aggregate principal amount of the 2016 Convertible Notes, plus cash for the fractional shares, totaling approximately $115.0 million. Additionally, we issued 792,406 shares of common stock for the $47.9 million excess conversion value. See the footnote titled Common Stock for more information.

RevolvingCredit Facility

Revolving Credit Facility. Our revolving credit facility matures in May 2020. 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 provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base determination and subject to limitations under the 2022 Senior Notes. The amount available under the revolving credit facility is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size 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. The current borrowing base and aggregate commitments under the facility are $700 million.

    The weighted-average borrowing rate on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.7 percent and 2.6 percent per annum for the years ended December 31, 2016 and 2015, respectively. We capitalized $8.8 million and $3.6 million of debt issuance costs as of December 31, 2016 and 2015, respectively, related to our revolving credit facility which is included in other assets on the consolidated balance sheets.

We had no outstanding balance on our revolving credit facility as of December 31, 2016 compared to $37.0 million outstanding as of December 31, 2015. 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 greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus an applicable margin 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 December 31, 2016, the applicable margin is 1.25 percent, and the unused commitment fee is 0.50 percent. No principal payments are generally required until the credit agreement 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 1.00:1.00 and (b) not exceed a maximum leverage ratio of 4.00:1.00. Our borrowing base availability 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 the applicable indenture. As of December 31, 2016, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the foreseeable future. As of December 31, 2016, our calculated debt to EBITDAX ratio was 2.10 and our current ratio was 5.00.

The revolving credit facility contains restrictions as to when we can directly or indirectly retire, redeem, repurchase, or prepay in cash any part of the principal of the 2021 Convertible Notes, 2022 Senior Notes, or 2024 Senior Notes. Among other things, the restriction on redemption of the 2021 Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement, or prepayment, the aggregate commitment under the revolving credit facility must exceed the aggregate credit exposure under such facility by at least an amount equal to or greater than 20 percent of such aggregate commitment.

As of December 31, 2016, RNG had issued an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit currently expires in September 2017 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of December 31, 2016, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $688.3 million.

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CAPITAL LEASES (Notes)

12 Months Ended

Dec. 31, 2016

Capital Leases [Abstract]

Capital Leases in Financial Statements of Lessee Disclosure [Text Block]

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 leased vehicles under capital leases:

	As of December 31,
	2016			2015
	(in thousands)
Vehicles	$	2,975		$	1,601
Accumulated depreciation	(776		)	(211		)
	$	2,199		$	1,390

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 December 31,	Amount
	(in thousands)
2017	$	914
2018	1,099
2019	560
	2,573
Less executory cost	(96		)
Less amount representing interest	(263		)
Present value of minimum lease payments	$	2,214
Short-term capital lease obligations	$	699
Long-term capital lease obligations	1,515
	$	2,214

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

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

ASSET RETIREMENT OBLIGATIONS

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

	2016			2015
	(in thousands)
Balance at beginning of period	$	89,492		$	73,855
Obligations incurred with development activities and assumed with acquisitions	4,894			2,373
Accretion expense	7,080			6,293
Revisions in estimated cash flows	—			11,658
Obligations discharged with disposal of properties and asset retirements	(9,079		)	(4,687		)
Balance at end of period	92,387			89,492
Less current portion	(9,775		)	(5,460		)
Long-term portion	$	82,612		$	84,032

Our estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2016, 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.

The increase in the current portion of asset retirement obligations in 2016 is attributable to an increase in the number of wells to be plugged and abandoned to allow for the drilling of nearby horizontal wells. The revisions in estimated cash flows during 2015 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells.

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2016

Employee Benefits and Share-based Compensation [Abstract]

Compensation and Employee Benefit Plans [Text Block]

EMPLOYEE BENEFIT PLANS

We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was$4.8 million, $4.9 million, and $3.9 millionfor 2016, 2015, and 2014, respectively.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales, and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. Our statements of operations reflect our share of these firm transportation costs. These contracts require us to pay these transportation and processing charges, whether or not the required volumes are delivered. As natural gas prices remain depressed, certain third-party producers under our Gas Marketing Segment have continued to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, no counterparty default losses have been material to us. In 2016 and 2015, we recorded an allowance for doubtful accounts of approximately $1.3 million and $0.5 million, respectively. 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.

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

	Year Ending December 31,
Area	2017		2018		2019		2020		2021 and Through Expiration		Total		Expiration Date
Natural gas (MMcf)
Wattenberg Field (1)	—		2,300		17,125		18,300		86,700		124,425		September 30, 2025
Gas Marketing segment	7,117		7,117		7,117		7,136		11,550		40,037		August 31, 2022
Utica Shale	2,738		2,738		2,738		2,745		7,064		18,023		July 22, 2023
Total	9,855		12,155		26,980		28,181		105,314		182,485
Crude oil (MBbls)
Wattenberg Field	2,413		2,413		2,413		1,204		—		8,443		June 30, 2020
Dollar commitment (in thousands)	$	17,158	$	18,626	$	33,221	$	27,430	$	89,896	$	186,331

__________

(1) In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities.  The midstream provider is expected to construct a new 200 MMcfd cryogenic plant.  We will be bound to the volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which in the above table is estimated to be September 30, 2018.  The agreement requires a baseline volume commitment of current sales volumes to this midstream provider and an incremental volume commitment of 50 MMcfd for seven years, of which we may be required to pay a shortfall fee for any volumes under the 50 MMcfd incremental commitment.  Any shortfall of this volume commitment may be offset, in part, by additional third party producers’ volumes sold to the midstream provider when a certain total volume is achieved. We are also required for the first three years of the contract to guarantee a certain target profit margin to the midstream provider on these volumes sold.  Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments.  Using the NYMEX forward pricing strip at December 31, 2016, the target profit margin would be achieved without an additional payment from us.

During 2016, 2015, and 2014, long-term firm transportation costs for our Gas Marketing segment as shown above were $3.4 million in each year and were recorded in cost of gas marketing in our consolidated statements of operations. For the years 2016, 2015, and 2014, commitments for long-term transportation volumes for Utica Shale natural gas and Wattenberg Field crude oil were $10.0 million, $4.7 million, and $0.3 million, respectively, and were recorded in transportation, gathering and processing expense in our consolidated statements of operations.

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. 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.

Class Action Regarding 2010 and 2011 Partnership Purchases

We finalized a settlement associated with the repurchase of certain partnership purchases in 2015. All required amounts associated with this settlement had been expensed in 2014.

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. We are not aware of any environmental claims existing as of December 31, 2016, 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 consolidated balance sheets.

In August 2015, we received the Information Request from the 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. The Information Request focuses on historical operation and design information for 46 of our production facilities and asks that we conduct sampling and analyses at the identified 46 facilities. We responded to the the Information Request in January 2016. Throughout 2016, we continued to meet with the EPA, Department of Justice, and Colorado Department of Public Health and Environment, and in December we received a draft consent decree from the EPA.

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 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 operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. We are in the process of responding to the advisory, but cannot predict the outcome of this matter at this time.

Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space, and general office equipment.

The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2016:

	Year Ending December 31,
	2017		2018		2019		2020		2021		Thereafter		Total
	(in thousands)
Minimum Lease Payments	$	3,056	$	3,041	$	3,033	$	3,093	$	3,154	$	6,786	$	22,163

Operating lease expense for 2016, 2015, and 2014 was $10.2 million, $9.8 million, and $7.0 million, respectively.

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COMMON STOCK

12 Months Ended

Dec. 31, 2016

COMMON STOCK [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Text Block]

COMMON STOCK

Sale of Equity Securities

We issued 9.4 million shares of common stock as partial consideration for 100 percent of the common stock of Arris Petroleum and for the acquisition of certain Delaware Basin properties on December 6, 2016. These shares are restricted for sale until June 6, 2017, due to previously-disclosed lock up agreements. Accordingly, the value of the shares was discounted from the market price on the date of issuance by 6 percent.

The following table provides a summary of our public offerings of common stock in 2016 and 2015:

Date	Shares Issued	Price per Share		Net Proceeds
				(in millions)
September 2016	9,085,000	$	61.51	$	558.5
March 2016	5,922,500	50.11		296.6
March 2015	4,002,000	50.73		202.9

Stock-Based Compensation Plans

2010 Long-Term Equity Compensation Plan. In June 2010, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued 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 stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of SARs, restricted stock, restricted stock units ("RSUs"), performance shares, and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock, and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2016, 839,052 shares remain available for issuance pursuant to the 2010 Plan.

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:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Stock-based compensation expense	$	19,502		$	20,068		$	17,518
Income tax benefit	(7,296		)	(7,636		)	(5,955		)
Net stock-based compensation expense	$	12,206		$	12,432		$	11,563

Stock Appreciation Rights ("SARs")

The 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.

The Compensation Committee has awarded SARs to our executive officers in 2016, 2015, and 2014. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:

	Year Ended December 31,
	2016			2015			2014
Expected term of award	6.0 years			5.2 years			6.0 years
Risk-free interest rate	1.8		%	1.4		%	2.1		%
Expected volatility	54.5		%	58.0		%	65.6		%
Weighted-average grant date fair value per share	$	26.96		$	22.23		$	29.96

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 all periods presented:

	Year Ended December 31,
	2016							2015						2014
	Number of SARs		Weighted-Average Exercise Price		Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)		Number of SARs		Weighted-Average Exercise Price		Aggregate Intrinsic Value (in thousands)		Number of SARs	Weighted-Average Exercise Price		Aggregate Intrinsic Value (in thousands)
Outstanding beginning of year, January 1,	326,453		$	38.99	7.3	$	4,697	279,011		$	38.77	$	1,472	190,763	$	33.77	$	3,711
Awarded	58,709		51.63		—	—		68,274		39.63		—		88,248	49.57		—
Exercised	(141,084	)	40.16		—	2,770		(20,832	)	38.05		473		—	—		—
Outstanding at December 31,	244,078		41.36		6.9	7,620		326,453		38.99		4,697		279,011	38.77		1,472
Exercisable at December 31,	174,919		38.72		6.3	5,924		222,489		37.70		3,489		139,334	36.27		982

Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2016, was $1.5 million. The cost is expected to be recognized over a weighted-average period of 1.7 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 that a participant is continuously employed.

The following table presents the changes in non-vested time-based awards during 2016:

	Shares		Weighted-Average Grant Date Fair Value
Non-vested at December 31, 2015	525,081		$	50.23
Granted	290,010		58.52
Vested	(317,034	)	48.61
Forfeited	(18,415	)	56.10
Non-vested at December 31, 2016	479,642		56.09

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

	As of/Year Ended December 31,
	2016		2015		2014
	(in thousands, except per share data)
Total intrinsic value of time-based awards vested	$	18,973	$	17,077	$	18,278
Total intrinsic value of time-based awards non-vested	34,812		28,029		23,290
Market price per common share as of December 31,	72.58		53.38		41.27
Weighted-average grant date fair value per share	58.52		48.88		56.45

Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2016 was $17.5 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.

In January 2016, the Compensation Committee awarded a total of 24,280 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total stockholder return ("TSR"), which is essentially the Company’s 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, 2018 and can result in a payout between 0 percent and 200 percent of the total shares awarded. As of December 31, 2016, we had approximately 48,000 non-vested market based restricted shares that could result in a payout between 0 and approximately 96,000 shares of our common stock. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions:

	Year Ended December 31,
	2016			2015
Expected term of award	3 years			3 years
Risk-free interest rate	1.2		%	0.9		%
Expected volatility	52.3		%	53.0		%
Weighted-average grant date fair value per share	$	72.54		$	66.16

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 2016:

	Shares		Weighted-Average Grant Date Fair Value per Share
Non-vested at December 31, 2015	71,549		$	63.60
Granted	24,280		72.54
Vested	(47,409	)	66.78
Non-vested at December 31, 2016	48,420		64.97

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

	As of/Year Ended December 31,
	2016		2015		2014
	(in thousands, except per share data)
Total intrinsic value of market-based awards vested	$	6,562	$	4,293	$	1,260
Total intrinsic value of market-based awards non-vested	3,514		3,819		3,455
Market price per common share as of December 31,	72.58		53.38		41.27
Weighted-average grant date fair value per share	72.54		66.16		56.87

Total compensation cost related to non-vested market-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2016 was $1.7 million. This cost is expected to be recognized over a weighted-average period of 1.7 years.

Treasury Share Purchases

In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's 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 APIC. As of December 3, 2015, we had 9,009 shares remaining available for reissuance pursuant to our 2010 plan. Additionally, as of December 31, 2016 and 2015, we had 18,366 and 11,211, respectively, of shares of treasury stock related to a rabbi trust. During the year ended December 31, 2016, we acquired 116,085 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 114,697 shares were reissued and 10,397 shares are available for reissuance pursuant to our 2010 Plan.

Stockholders’ Rights Agreement

In 2007, we entered into a rights agreement designed to improve the ability of our Board to protect the interest of our stockholders in the event of an unsolicited takeover attempt.  The rights agreement and all rights were set to expire in September 2017.  In June 2016, we entered into an amendment to the rights agreement, which accelerated the expiration date from September 2017 to June 2016. Upon the expiration in June 2016, all of the rights distributed to holders of our common stock pursuant to the rights agreement expired. The amendment was entered into as a result of governance considerations and not in contemplation of any anticipated business combination or similar transaction.

Preferred stock

We are authorized, pursuant to stockholder approval in 2008, to issue 50,000,000 shares of preferred stock, par value $0.01, 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. As of December 31, 2016, no preferred shares had been issued

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2016

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Earnings Per Share [Text Block]

EARNINGS PER SHARE

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

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

	Year Ended December 31,
	2016	2015	2014
	(in thousands)
Weighted-average common shares outstanding - basic	49,052	39,153	35,784
Dilutive effect of:
Restricted stock	—	—	279
Convertible notes	—	—	564
Other equity-based awards	—	—	51
Weighted-average common shares and equivalents outstanding - diluted	49,052	39,153	36,678

For 2016 and 2015, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same 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:

	Year Ended December 31,
	2016	2015	2014
	(in thousands)
Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	689	831	8
Convertible notes	292	562	—
Other equity-based awards	109	101	26
Total anti-dilutive common share equivalents	1,090	1,494	34

In September 2016, we issued the 2021 Convertible Notes, which give the holders 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 would 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.

In November 2010, we issued the 2016 Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured and were redeemed in May 2016, as described more fully in the footnote titled Long Term Debt. Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeded the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2015 as the effect would have been anti-dilutive to our earnings per share. Shares issuable upon conversion of the 2016 Convertible Notes were included in the diluted earnings per share calculation for the year ended December 31, 2014 as the average market price during the period exceeded the conversion price.

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ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS

12 Months Ended

Dec. 31, 2016

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

DIVESTITURE AND DISCONTINUED OPERATIONS

In October 2014, we completed the sale of our entire 50 percent ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million, comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million. The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million. As the divestiture represented a strategic shift that had a major effect on our operations as our organization structure no longer has joint venture partners and we no longer have dry gas assets, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for the year ended December 31, 2014.

The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. The following table presents consolidated statements of operations data related to our discontinued operations:

Consolidated statements of operations - discontinued operations	Year Ended December 31, 2014
	(in thousands)
Revenues
Crude oil, natural gas and NGLs sales	$	24,149
Commodity price risk management loss, net	(1,085		)
Other income	48
Total revenues	23,112
Costs, expenses and other
Lease operating expenses	1,280
Production taxes	1,579
Transportation, gathering and processing expenses	3,536
Impairment of properties and equipment	433
Depreciation, depletion and amortization	9,128
Other	4,170
Gain on sale of properties and equipment	(76,479		)
Total costs, expenses and other	(56,353		)
Interest expense	(2,222		)
Interest income	194
Income from discontinued operations	77,437
Provision for income taxes	(29,263		)
Income from discontinued operations, net of tax	$	48,174

The following table presents supplemental cash flows information related to our 50 percent ownership interest in PDCM, which is classified as discontinued operations:

Supplemental cash flows information - discontinued operations	Year Ended December 31, 2014
	(in thousands)
Cash flows from investing activities:
Capital expenditures	$	(17,253	)
Significant non-cash investing items:
Change in accounts payable related to purchases of properties and equipment	(5,727		)

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TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES

12 Months Ended

Dec. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

TRANSACTIONS WITH AFFILIATES

PDCM. In 2014, our Gas Marketing segment marketed the natural gas produced by PDCM. Our cost of gas marketing includes $23.2 million in 2014 related to the marketing of this gas.

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BUSINESS SEGMENTS

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

BUSINESS SEGMENTS

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

Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas, and NGLs. Segment revenue includes crude oil, natural gas, and NGLs sales, commodity price risk management, net, and other income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of properties and equipment, direct general and administrative expense, and DD&A expense. Segment DD&A expense was$413.1 million, $298.8 million, and $188.5 million in 2016, 2015, and 2014, respectively.

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

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

The following tables present our segment information:

	2016			2015			—	2014
	(in thousands)
Year Ended December 31,
Segment revenues:
Oil and gas exploration and production	$	374,190		$	584,406			$	784,636
Gas marketing	8,725			10,920				71,571
Total revenues	$	382,915		$	595,326			$	856,207
Segment income (loss) before income taxes:
Oil and gas exploration and production	$	(170,370	)	$	31,429			$	344,149
Gas marketing	(1,468		)	(797		)		(445		)
Unallocated	(221,285		)	(137,220		)		(166,476		)
Income (loss) before income taxes	$	(393,123	)	$	(106,588	)		$	177,228
Expenditures for segment long-lived assets:
Oil and gas exploration and production	$	436,884		$	599,617			$	623,912
Acquisition of crude oil and natural gas properties, net of cash acquired	1,073,723			—				—
Unallocated	3,464			5,051				4,680
Total	$	1,514,071		$	604,668			$	628,592
As of December 31,
Segment assets:
Oil and gas exploration and production	$	4,451,510		$	2,294,288
Gas marketing	4,329			4,217
Unallocated	30,003			72,038
Total assets	$	4,485,842		$	2,370,543

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES

12 Months Ended

Dec. 31, 2016

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Information - Oil and Gas Exploration and Production Industries Disclosures [Text Block]

NATURAL GAS INFORMATION - UNAUDITED

Net Proved Reserves

All of our crude oil, natural gas, and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, and NGL reserves. As of December 31, 2016, 2015, and 2014, all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott and beginning in 2016, NSAI prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves are those quantities of crude oil, natural gas, and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial booking date.

The indicated index prices for our reserves, by commodity, are presented below.

	Average Benchmark Prices
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	42.75	$	2.48	$	42.75
2015	50.28		2.59		50.28
2014	94.99		4.35		94.99

The netted back price used to estimate our reserves, by commodity, are presented below.

	Price Used to Estimate Reserves*
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	38.67	$	1.85	$	11.97
2015	42.10		2.05		12.23
2014	84.65		3.92		32.27

___________

* These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.

The following tables present the changes in our estimated quantities of proved reserves:

	Crude Oil, Condensate (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)
Proved Reserves:
Proved reserves, January 1, 2014 (1)	93,830		739,640		48,671		265,774
Revisions of previous estimates	(29,777	)	(149,064	)	(10,204	)	(64,825	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	40,792		202,957		23,411		98,029
Acquisition of reserves	5		43		5		17
Dispositions	(13	)	(237,306	)	(8	)	(39,572	)
Production	(4,322	)	(19,298	)	(1,756	)	(9,294	)
Proved reserves, December 31, 2014	100,515		536,972		60,119		250,129
Revisions of previous estimates	(43,268	)	(154,775	)	(24,407	)	(93,471	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	48,707		311,709		30,835		131,494
Acquisition of reserves	17		215		23		76
Dispositions	(12	)	(82	)	(8	)	(34	)
Production	(6,984	)	(33,302	)	(2,835	)	(15,369	)
Proved reserves, December 31, 2015	98,975		660,737		63,727		272,825
Revisions of previous estimates	(22,097	)	(80,426	)	(7,130	)	(42,631	)
Extensions, discoveries and other additions	494		4,094		355		1,531
Acquisition of reserves	50,126		305,224		32,586		133,583
Dispositions	(601	)	(4,202	)	(424	)	(1,725	)
Production	(8,728	)	(51,730	)	(4,826	)	(22,176	)
Proved reserves, December 31, 2016	118,169		833,697		84,288		341,407

Proved Developed Reserves, as of:
December 31, 2014	26,798	186,633	17,002	74,905
December 31, 2015	26,257	175,367	15,011	70,496
December 31, 2016	30,013	264,452	24,196	98,284
Proved Undeveloped Reserves, as of:
December 31, 2014	73,717	350,339	43,117	175,224
December 31, 2015	72,718	485,370	48,716	202,329
December 31, 2016	88,156	569,245	60,092	243,122

2016 Activity. During 2016, we increased proved reserves by 25 percent or 68.6 MMBoe, relative to December 31, 2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped reserves in the Delaware Basin.

Extensions, discoveries and other additions for 2016 of 1.5 MMBoe includes the addition of five wells in the Utica Shale.

Acquisitions of reserves of 133.6 MMBoe includes proved developed producing properties and proved undeveloped (“PUD”) locations acquired in our Delaware Basin acquisitions, and new proved locations obtained from an acreage exchange transaction. Because of the preferential economics of the more concentrated acreage in the Wattenberg Field, we rescheduled the timing of anticipated development in the field. This resulted in a downward revision to our proved reserves. The net downward revisions were 42.6 MMBoe. The revision was most notably attributed to a 61.0 MMBoe decrease in reserves due to 2015 PUD locations being removed from our five year development plan and being replaced by PUD locations reflected in purchases of reserves. Infill reserve additions of 16.8 MMBoe in the Wattenberg Field were included as a positive revision of previous estimates. Infill reserve additions for years prior to 2016 for the Wattenberg Field were reported in extensions, discoveries and other additions, including infill reserves in an existing proved field. Revisions also include a 0.5 MMBoe decrease on production due to pricing. The remaining 2.1 MMBoe in positive revisions of previous estimates includes performance revisions and other items.

We had minimal dispositions of 1.7 MMBoe related to acreage traded in the acreage exchange.

At December 31, 2015, we projected a PUD reserve conversion rate of 19 percent for 2016. As a result of revisions to our drilling plan during the last two months of 2016, our actual reserve conversion rate was 16 percent, resulting in 32.2 MMBoe of reserves recorded as PUDs at December 31, 2015, being converted to proved developed reserves as of December 31, 2016.

Based on economic conditions on December 31, 2016, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2016, our 2017 PUD reserve conversion rate is expected to be approximately 26 percent. The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities.

2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to December 31, 2014. In 2015, we produced 15.4 million MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16 percent for 2015. Our actual conversion rate was 17 percent, resulting in 29 MMBoe of reserves booked as PUDs at December 31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of proved reserves in 2015.

Extensions, discoveries, and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The reserve additions associated with these projects are largely the result of data generated from our downspacing testing. This led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally, due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling rig utilized during the course of the year. We have 791 gross PUD horizontal drilling locations at December 31, 2015, which is an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries, and other additions to our developed reserves related to wells drilled that were not related to reserves booked as of prior year-end.

We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. Also, contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to well performance and forecast adjustments.

Based on the economic conditions on December 31, 2015, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. The continued success of our increased well density tests in the Wattenberg Field in 2015 allowed for the additional increased well density of PUD locations as of December 31, 2015. Because we expect to continue to drill primarily proved Wattenberg Field locations in 2016 and as a result of additional newly-booked downspaced PUDs at December 31, 2015, our 2016 PUD conversion rate is expected to be approximately 19 percent. The balance of the locations are scheduled to be drilled over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities.

2014 Activity. Overall, our proved reserves decreased by 16 MMBoe as of December 31, 2014 as compared to December 31, 2013. In 2014, we produced 9.3 MMBoe. At December 31, 2013, we projected a PUD conversion rate of seven percent for 2014. Our actual conversion rate was seven percent, resulting in 13 MMBoe of reserves booked as PUDs at December 31, 2013 being converted to proved developed reserves during 2014. As shown, we acquired minimal proved reserves in 2014. We divested a total of 40 MMBoe in 2014, primarily from the sale of our Marcellus Shale assets.

Extensions, discoveries and other additions, including infill reserves, resulted in an increase of approximately 98 MMBoe in 2014, substantially all of which was added in the Wattenberg Field and primarily related to Niobrara and Codell projects. These reserve increases are primarily due to adding 78 MMBoe from new proved undeveloped reserves as a result of adjustments in well spacing, which extended the field by enabling us to book more reserves per section in the Niobrara and Codell formations. In addition, approximately 16 MMBoe of previously unbooked locations were developed in the current year and 2 MMBoe due to various other factors. Approximately 2 MMBoe was added in the Utica Shale.

We recorded a downward revision of our previous estimate of proved reserves of approximately 65 MMBoe. The revision was primarily related to decreases of approximately 55 MMBoe for adjustments to our development plans in the Wattenberg Field to focus on a more balanced commodity production mix and increased well density which delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. In addition, 8 MMBoe of Utica Shale PUDs are no longer in our drilling plans as we directed more capital to higher-return projects in the Wattenberg Field and 2 MMBoe that were due to various other factors.

Based on the economic conditions on December 31, 2014, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2014 drilling program focused on testing increased well density in the Wattenberg Field.

Results of Operations for Crude Oil and Natural Gas Producing Activities

The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to gas marketing and other income.

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Revenue:
Crude oil, natural gas and NGLs sales	$	497,353		$	378,713		$	495,562
Commodity price risk management gain (loss), net	(125,681		)	203,183			309,219
	371,672			581,896			804,781
Expenses:
Lease operating expenses	59,950			56,992			43,682
Production taxes	31,410			18,443			27,194
Transportation, gathering and processing expenses	18,415			10,151			8,128
Exploration expense	4,669			1,102			948
Impairment of properties and equipment	9,973			161,620			167,280
Depreciation, depletion, and amortization	413,105			298,760			201,656
Accretion of asset retirement obligations	7,080			6,293			3,455
Loss on sale of properties and equipment	(43		)	(385		)	(75,972		)
	544,559			552,976			376,371
Results of operations for crude oil and natural gas producing activities before provision for income taxes	(172,887		)	28,920			428,410
Provision for income taxes	64,733			(10,394		)	(166,930		)
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	(108,154	)	$	18,526		$	261,480

Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes, and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration, and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates.

Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration, and Development Activities

Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below.

	Year Ended December 31,
	2016		2015		2014
	(in thousands)
Acquisition of properties: (1)
Proved properties (2)	$	268,567	$	3,561	$	11,973
Unproved properties	1,843,985		15		45,999
Development costs (3)	383,336		552,104		608,176
Exploration costs: (4)
Exploratory drilling	—		—		—
Geological and geophysical	4,669		—		1
Total costs incurred	$	2,500,557	$	555,680	$	666,149

__________

(1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.

(2) Includes approximately $40.9 million of infrastructure and pipeline costs in 2016.

(3) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2016, 2015, and 2014, $204.6 million, $207.8 million, and $125.2 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end.

(4) Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs.

Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities

Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below:

	As of December 31,
	2016			2015
	(in thousands)
Proved crude oil and natural gas properties	$	3,499,718		$	2,881,189
Unproved crude oil and natural gas properties	1,874,671			60,498
Uncompleted wells, equipment and facilities	150,424			109,385
Capitalized costs	5,524,813			3,051,072
Less accumulated DD&A	(1,534,678		)	(1,131,705		)
Capitalized costs, net	$	3,990,135		$	1,919,367

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btucontent, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion, and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits, and allowances related to the properties.

The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves.

	As of December 31,
	2016			2015			2014
	(in thousands)
Future estimated cash flows	$	7,122,525		$	6,297,298		$	12,550,515
Future estimated production costs*	(1,624,167		)	(1,493,040		)	(2,746,811		)
Future estimated development costs	(2,219,914		)	(2,036,685		)	(2,528,755		)
Future estimated income tax expense	(597,476		)	(508,332		)	(2,336,510		)
Future net cash flows	2,680,968			2,259,241			4,938,439
10% annual discount for estimated timing of cash flows	(1,260,339		)	(1,162,377		)	(2,631,974		)
Standardized measure of discounted future estimated net cash flows	$	1,420,629		$	1,096,864		$	2,306,465

___________

* Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses.

The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Beginning of period	$	1,096,864		$	2,306,465		$	1,782,163
Sales of crude oil, natural gas and NGLs production, net of production costs	(387,576		)	(293,127		)	(387,789		)
Net changes in prices and production costs (1)	(205,760		)	(1,752,921		)	129,213
Extensions, discoveries, and improved recovery, less related costs	15,128			489,178			1,444,581
Sales of reserves	(3,745		)	(463		)	(402,595		)
Purchases of reserves	487,636			374			238
Development costs incurred during the period	268,672			368,840			161,404
Revisions of previous quantity estimates	(320,286		)	(1,286,462		)	(654,318		)
Changes in estimated income taxes	(13,630		)	902,994			(221,874		)
Net changes in future development costs	391,145			112,958			46,499
Accretion of discount	133,747			345,007			270,389
Timing and other	(41,566		)	(95,979		)	138,554
End of period	$	1,420,629		$	1,096,864		$	2,306,465

__________

(1) Our weighted-average price, net of production costs per Boe, in our 2016 reserve report decreased to $15.73 as compared to $17.30 for 2015 and $37.78 for 2014.

The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

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SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION

12 Months Ended

Dec. 31, 2016

Quarterly Financial Data [Abstract]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL INFORMATION - UNAUDITED

Quarterly financial data for the years ended December 31, 2016 and 2015 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year.

	2016
	Quarter Ended
	March 31			June 30			September 30			December 31
	(in thousands, except per share data)
Total revenues	$	90,831		$	20,097		$	163,890		$	108,097
Total cost, expenses and other	193,864			163,379			179,178			178,608
Loss from operations	(103,033		)	(143,282		)	(15,288		)	(70,511		)
Loss before income taxes	(113,369		)	(153,777		)	(35,341		)	(90,636		)
Net loss	$	(71,530	)	$	(95,450	)	$	(23,309	)	$	(55,639	)
Earnings per share:
Basic	$	(1.72	)	$	(2.04	)	$	(0.48	)	$	(0.94	)
Diluted	(1.72		)	(2.04		)	(0.48		)	(0.94		)

	2015
	Quarter Ended
	March 31		June 30			September 30			December 31
	(in thousands, except per share data)
Total revenues	$	144,632	$	50,960		$	231,100		$	168,634
Total costs, expenses and other	106,235		117,514			283,047			152,354
Income (loss) from operations	38,397		(66,554		)	(51,947		)	16,280
Income (loss) before income taxes	27,785		(76,986		)	(62,661		)	5,274
Net income (loss)	$	17,062	$	(46,870	)	$	(41,494	)	$	3,022
Earnings per share:
Basic	$	0.47	$	(1.17	)	$	(1.04	)	$	0.08
Diluted	0.46		(1.17		)	(1.04		)	0.07

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Goodwill [Line Items]

Goodwill Disclosure [Text Block]

Goodwill represents the residual value of purchase price over net tangible and identifiable intangible assets of an acquired business and is stated at cost. Goodwill is not amortized; rather it is assessed annually for impairment, or more frequently if any event indicates that the carrying amount of goodwill may be impaired.

Consolidation, Policy [Policy Text Block]

All material intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates, Policy [Policy Text Block]

The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas, and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; impairment of proved and unproved properties; valuation and allocations of purchased businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets

Cash and Cash Equivalents, Policy [Policy Text Block]

We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.

Derivative Financial Instruments, Policy [Policy Text Block]

All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose for issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of gas marketing. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows.

The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values

Natugal Gas and Crude Oil Properties, Policy [Policy Text Block]

We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have three units-of-production fields which are the Wattenberg Field, the Delaware Basin, and the Utica Shale. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations, and common cost environments in these areas. We calculate quarterly depreciation, depletion, and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statements of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A.

Exploration costs, including geological and geophysical expenses, seismic costs on unproved leasehold, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability, or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded

Proved and Unproved Property, Impairment [Policy Text Block]

e assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas, and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices, or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value

The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates, and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.

Property, Plant and Equipment, Policy [Policy Text Block]

Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income

Interest Capitalization, Policy [Policy Text Block]

Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset

Assets Held For Sale, Policy [Policy Text Block]

Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. Assets held for sale of $5.3 million as of December 31, 2016, represents the fair value of field office facilities and a parcel of land. Assets held for sale of $2.9 million as of December 31, 2015, represents the fair value of a parcel of land. These amounts are included in properties and equipment, net on our consolidated balance sheets.

For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations.

Production Tax Liability, Policy [Policy Text Block]

Production tax liability represents estimated taxes, primarily severance, ad valorem, and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas, and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed and included in the statement of operations line item production taxes. Affiliated partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets

Income Tax, Policy [Policy Text Block]

We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable

Debt Issuance Costs, Policy [Policy Text Block]

Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method

Asset Retirement Obligations, Policy [Policy Text Block]

We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations

Treasury Shares, Policy [Policy Text Block]

We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.

Revenue Recognition, Policy [Policy Text Block]

Crude oil, natural gas, and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred, and collection of revenue is reasonably assured. Our crude oil, natural gas, and NGLs sales are recorded under either the "net-back" or "gross" method of accounting, depending upon the transportation, gathering or processing method used. We use the net-back method of accounting for a portion of our crude oil production in the Wattenberg Field and for substantially all crude oil production in the Delaware Basin and the Utica Shale, as well as natural gas and NGLs from the Delaware Basin and the Wattenberg Field as the majority of the purchasers of these commodities also provide transportation, gathering, and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the gross method of accounting for Wattenberg Field crude oil delivered through the White Cliffs and Saddle Butte pipelines 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. Under this method, we recognize revenues based on the gross selling price.

Gas marketing. Gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our gas marketing subsidiary, RNG, suppliers, and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled commodity derivatives of the RNG commodity-based derivative transactions for gas marketing are included in sales from or cost of gas marketing, as applicable.

Accounting for Acquisitions using Purchase Accounting [Policy Text Block]

We utilize the purchase method to account for acquisitions of businesses and assets. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices, and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.

In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value.

We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Stock-Based Compensation, Policy [Policy Text Block]

Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations

Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]

We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs, and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations

New Accounting Pronouncements, Policy [Policy Text Block]

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 underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (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. In March 2016, the FASB issued an update to the standard intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations when recognizing revenue. In December 2016, the FASB issued technical corrections and improvements to the standard. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are in the process of assessing potential impacts of the new standard on our existing revenue recognition criteria, as well as on related revenue disclosures.

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 in the process of assessing 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. This is an expansive set of revisions to the cash flow presentation standards, but at this time we do not believe that these changes will impact our consolidated financial statements.

New Accounting Pronouncement, Early Adoption [Table Text Block]

Recently Adopted Accounting Standards.

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

In March 2016, the FASB issued an accounting update on stock-based compensation that is intended to simplify several aspects of the accounting for employee share-based payment award transactions. Areas of simplification include income tax consequences, classification of the awards as either equity or liabilities and the classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. We early adopted this standard in the fourth quarter of 2016.

• The primary impact of the adoption was the recognition of excess tax benefits in our provision for income taxes rather than additional paid-in capital, as well as the adjustment in stock-based compensation expense as a result of our changes in forfeiture policy. The new guidance eliminates the requirement to delay the recognition of excess tax benefits until it reduces current taxes payable. We adopted this change on a prospective basis, and recorded unrecognized excess tax benefits amounting to $1.5 million, which increased retained earnings in the fourth quarter of 2016.

• The new guidance also requires us to record, subsequent to the adoption, excess tax benefits and tax deficiencies in the period they occur. Prior to the adoption, the excess tax benefits would have been recorded as APIC. This change could create future volatility in our effective tax rate depending upon the amount of exercise or vesting activity from our stock awards. Under the new guidance, we have elected to change our policy and have started to recognize forfeitures of awards as they occur. The change in forfeiture policy was adopted using a modified retrospective transition method. We recorded a cumulative-effect adjustment to decrease retained earnings by $0.3 million upon transition on January 1, 2016, and an increase of stock-based compensation of $0.1 million during the fourth quarter of 2016. Per the guidance in the accounting standard update, the adjustment to stock-based compensation should be recorded on a retrospective basis. Our adjustment was not material to our condensed consolidated financial statements, therefore, we recorded the entire adjustment in the fourth quarter of 2016.

• The amendment to the minimum statutory withholding tax requirements was adopted on a modified retrospective basis. The adoption had no impact on retained earnings.

• In addition, we adopted the presentation of taxes paid related to the net share settlement as a financing activity on the statement of cash flows on a retrospective basis. Adoption had no impact to any of the periods presented in our consolidated cash flows statements since such cash flows have historically been presented as a financing activity.

Earnings Per Share, Policy [Policy Text Block]

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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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Property, Plant and Equipment, Estimated Useful Lives [Table Text Block]

Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment.

The following table presents the estimated useful lives of our other property and equipment:

Transportation, pipeline, and other equipment	2 - 30 years
Buildings	20 - 40 years

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BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Tables)

12 Months Ended

Dec. 31, 2016

Business Combinations Abstract [Abstract]

Business Combination, Segment Allocation [Table Text Block]

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

	Year Ended December 31, 2016
Acquisition costs:
Cash, net of cash acquired	$	912,142
Retirement of seller's debt	40,000
Total cash consideration	952,142
Common stock, 9.4 million shares	690,702
Other purchase price adjustments	1,026
Total acquisition costs	$	1,643,870
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	8,201
Crude oil and natural gas properties - proved	216,000
Crude oil and natural gas properties - unproved	1,721,334
Infrastructure, pipeline, and other	32,590
Construction in progress	12,148
Goodwill	62,041
Total assets acquired	2,052,314
Liabilities assumed:
Current liabilities	(24,844		)
Asset retirement obligations	(3,705		)
Deferred tax liabilities, net	(379,895		)
Total liabilities assumed	(408,444		)
Total identifiable net assets acquired	$	1,643,870

Business Acquisition, Pro Forma Information [Table Text Block]

Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total revenue and $1.7 million of loss from operations. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2016 and December 31, 2015, assuming the acquisition had been completed as of January 1, 2015. This pro forma financial information includes the Securities Issuances in September 2016, the shares issued to the sellers, and other acquisition costs. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.

	Years Ended December 31,
	2016			2015
	(in thousands, except per share amounts)
Total revenue	$	412,746		$	598,932
Net loss	$	(270,942	)	$	(138,904	)
Earnings (loss) per share:
Basic and diluted	$	(4.22	)	$	(2.41	)

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PROPERTIES AND EQUIPMENT Properties and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

The following table presents the components of properties and equipment, net of accumulated DD&A:

	As of December 31,
	2016			2015
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	3,499,718		$	2,881,189
Unproved	1,874,671			60,498
Total crude oil and natural gas properties	5,374,389			2,941,687
Infrastructure, pipeline, and other	62,093			30,098
Land and buildings	12,165			12,667
Construction in progress	122,591			113,115
Properties and equipment, at cost	5,571,238			3,097,567
Accumulated DD&A	(1,562,972		)	(1,157,015		)
Properties and equipment, net	$	4,008,266		$	1,940,552

Impairment of natural gas and crude oil properties [Table Text Block]

The following table presents impairment charges recorded for properties and equipment:

	Year Ended December 31,
	2016		2015		2014
	(in thousands)
Impairment of proved and unproved properties	$	5,562	$	154,608	$	161,604
Amortization of individually insignificant unproved properties	1,379		7,012		4,465
Land and buildings	3,032		—		778
Impairment of properties and equipment	9,973		161,620		166,847
Discontinued operations:
Impairment of proved and unproved properties	—		—		433
Total discontinued operations	—		—		433
Total impairment of properties and equipment	$	9,973	$	161,620	$	167,280

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DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments Not Designated as Hedging Instruments [Abstract]

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The following table presents the balance sheet location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2016 and 2015:

Derivative instruments:		Consolidated Balance sheet line item	2016		2015
			(in thousands)
Derivative assets:	Current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	$	8,239	$	221,161
	Related to gas marketing	Fair value of derivatives	251		441
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	301		57
			8,791		221,659
	Non-current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	1,104		44,292
	Related to gas marketing	Fair value of derivatives	19		51
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	1,263		44
			2,386		44,387
Total derivative assets			$	11,177	$	266,046
Derivative liabilities:	Current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	$	53,353	$	—
	Related to gas marketing	Fair value of derivatives	212		417
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	30		1,178
			53,595		1,595
	Non-current
	Commodity derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	27,581		275
	Related to gas marketing	Fair value of derivatives	14		46
	Basis protection derivative contracts -
	Related to crude oil and natural gas sales	Fair value of derivatives	—		374
			27,595		695
Total derivative liabilities			$	81,190	$	2,290

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

	Year Ended December 31,
Consolidated statements of operations line item	2016			2015			2014
	(in thousands)
Commodity price risk management gain (loss), net -
Net settlements	$	208,103		$	238,935		$	(837	)
Net change in fair value of unsettled derivatives	(333,784		)	(35,752		)	311,141
Total commodity price risk management gain (loss), net	$	(125,681	)	$	203,183		$	310,304
Sales from gas marketing -
Net settlements	$	543		$	778		$	(208	)
Net change in fair value of unsettled derivatives	(676		)	(318		)	364
Total sales from gas marketing	$	(133	)	$	460		$	156
Cost of gas marketing -
Net settlements	$	(483	)	$	(745	)	$	346
Net change in fair value of unsettled derivatives	690			279			(451		)
Total cost of gas marketing	$	207		$	(466	)	$	(105	)

All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets.

The following table reflects the impact of netting agreements on gross derivative assets and liabilities:

As of December 31, 2016	Derivative instruments, recorded in 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

As of December 31, 2015	Derivative instruments, recorded in consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	266,046	$	(1,921	)	$	264,125
Liability derivatives:
Derivative instruments, at fair value	$	2,290	$	(1,921	)	$	369

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FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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:

	As of December 31,
	2016									2015
	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)
Total assets	$	6,350		$	4,827		$	11,177		$	174,758	$	91,288	$	266,046
Total liabilities	66,789			14,401			81,190			2,290		—		2,290
Net asset (liability)	$	(60,439	)	$	(9,574	)	$	(70,013	)	$	172,468	$	91,288	$	263,756

Fair Value Assets and Liabilities Unobservable Input Reconciliation [Table Text Block]

The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value:

	2016			2015			2014
	(in thousands)
Fair value of Level 3 instruments, net asset beginning of period	$	91,288		$	62,356		$	1,111
Changes in fair value included in consolidated statement of operations line item:
Commodity price risk management gain (loss), net	(28,530		)	65,018			62,003
Sales from gas marketing	(20		)	146			(22		)
Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net	(72,242		)	(36,169		)	(737		)
Sales from gas marketing	(70		)	(63		)	1
Fair value of Level 3 instruments, net asset (liability) end of period	$	(9,574	)	$	91,288		$	62,356
Net change in fair value of Level 3 unsettled derivatives included in statement of operations line item:
Commodity price risk management gain (loss), net	$	(12,905	)	$	43,540		$	15,632
Sales from gas marketing	—			—			3
Total	$	(12,905	)	$	43,540		$	15,635

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]

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 or convertible 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 December 31, 2016:

	Estimated Fair Value		% of Par
	(in millions)
Senior notes:
2021 Convertible Notes	$	220.2	110.1	%
2024 Senior Notes	408.0		102.0	%
2022 Senior Notes	535.0		107.0	%

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CONCENTRATION OF RISK Accounts Receivable, net of Allowance for Doubtful Accounts (Tables)

12 Months Ended

Dec. 31, 2016

Concentration Risks, Types, No Concentration Percentage [Abstract]

Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block]

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

	As of December 31,
	2016		2015
	(in thousands)
Employee benefits	$	22,282	$	17,774
Asset retirement obligations	9,775		5,460
Environmental expenses	3,238		4,143
Other	3,330		1,332
Other accrued expenses	$	38,625	$	28,709

Accounts Receivable [Table Text Block]

Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts:

	As of December 31,
	2016			2015
	(in thousands)
Crude oil, natural gas and NGLs sales	$	97,520		$	41,873
Joint interest billings	20,118			35,017
Derivative counterparties	10,266			24,437
Income tax receivable	11,505			—
Insurance reimbursement	—			879
Other	6,173			4,077
Allowance for doubtful accounts	(2,190		)	(2,009		)
Accounts receivable, net	$	143,392		$	104,274

Individual Customers Constituting 10% or more of Total Revenue [Table Text Block]

Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues:

	Year Ended December 31,
Customer	2016		2015		2014
Suncor Energy Marketing, Inc.	22.3	%	14.3	%	19.7	%
DCP Midstream, LP	20.2	%	13.2	%	15.1	%
Aka Energy Group, LLC	13.4	%	—	%	—	%
Concord Energy, LLC	13.4	%	23.2	%	18.3	%
Bridger Energy, LLC	11.5	%	—	%	—	%
Shell Trading Company	—	%	13.8	%	—	%
Teppco Crude Oil, LLC	—	%	—	%	12.9	%

Notes Receivable [Table Text Block]

The following table presents information regarding our note receivable outstanding:

	As of December 31,
	2016			2015
	(in thousands)
Principal and PIK Interest outstanding at beginning of period	$	43,069		$	39,707
PIK Interest	969			3,362
Principal and PIK Interest outstanding at end of period	44,038			43,069
Allowance for uncollectible notes receivable	(44,038		)	—
Note receivable, net	$	—		$	43,069

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INCOME TAXES Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The table below presents the components of our provision for income taxes from continuing operations for the years presented:

	Year Ended December 31,
	2016		2015			2014
	(in thousands)
Current:
Federal	$	9,646	$	(2,944	)	$	(1,514	)
State	300		(163		)	966
Total current income tax benefit (expense)	9,946		(3,107		)	(548		)
Deferred:
Federal	118,427		37,352			(60,698		)
State	18,822		4,063			(8,721		)
Total deferred income tax benefit (expense)	137,249		41,415			(69,419		)
Income tax benefit (expense) from continuing operations	$	147,195	$	38,308		$	(69,967	)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations:

	Year Ended December, 31,
	2016		2015		2014
Statutory tax rate	35.0	%	35.0	%	35.0	%
State income tax, net	2.6		2.7		2.8
Effect of state income tax rate changes	0.6		(0.3	)	—
Percentage depletion	—		0.3		(0.3	)
Non-deductible compensation	(0.5	)	(1.2	)	0.7
Excess tax benefits from stock-based compensation	0.4		—		—
Other	(0.7	)	(0.6	)	1.3
Effective tax rate	37.4	%	35.9	%	39.5	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2016 and 2015 are presented below. Of note, the table includes the $403.7 million effect of including the deferred tax liability for the difference in the book and tax basis of the oil and gas properties acquired in the December 6, 2016, business combination and a $23.8 million of acquired deferred tax assets:

	As of December 31,
	2016		2015
	(in thousands)
Deferred tax assets:
Deferred compensation	$	9,338	$	13,104
Asset retirement obligations	34,359		34,101
Federal NOL carryforward	29,988		—
State NOL and tax credit carryforwards, net	5,189		3,376
Alternative minimum tax - credit carryforward	5,184		2,812
Allowance for note receivable	17,292		—
Net change in fair value of unsettled derivatives	26,262		—
Other	4,716		3,412
Total gross deferred tax assets	132,328		56,805
Deferred tax liabilities:
Properties and equipment	518,964		99,191
Net change in fair value of unsettled derivatives	—		100,369
Convertible debt	14,231		697
Total gross deferred tax liabilities	533,195		200,257
Net deferred tax liability	$	400,867	$	143,452

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LONG-TERM DEBT LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2016

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

Long-term debt consists of the following:

	As of December 31,
	2016			2015
	(in thousands)
Senior notes:
1.125% Convertible Notes due 2021:
Principal amount	$	200,000		$	—
Unamortized discount	(37,475		)	—
Unamortized debt issuance costs	(4,584		)	—
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs	157,941			—
6.125% Senior Notes due 2024:
Principal amount	400,000			—
Unamortized debt issuance costs	(7,544		)	—
6.125% Senior Notes due 2024, net of unamortized debt issuance costs	392,456			—
7.75% Senior notes due 2022:
Principal amount	500,000			500,000
Unamortized debt issuance costs	(6,443		)	(7,563		)
7.75% Senior notes due 2022, net of unamortized debt issuance costs	493,557			492,437
3.25% Convertible senior notes due 2016:
Principal amount	—			115,000
Unamortized discount	—			(1,852		)
Unamortized debt issuance costs	—			(208		)
3.25% Convertible senior notes due 2016, net of unamortized discount and debt issuance costs	—			112,940
Total senior notes	1,043,954			605,377
Revolving credit facility	—			37,000
Total debt, net of unamortized discount and debt issuance costs	1,043,954			642,377
Less current portion of long-term debt	—			112,940
Long-term debt	$	1,043,954		$	529,437

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CAPITAL LEASES (Tables)

12 Months Ended

Dec. 31, 2016

Capital Leases [Abstract]

Schedule of Capital Leased Assets [Table Text Block]

The following table presents leased vehicles under capital leases:

	As of December 31,
	2016			2015
	(in thousands)
Vehicles	$	2,975		$	1,601
Accumulated depreciation	(776		)	(211		)
	$	2,199		$	1,390

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

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 December 31,	Amount
	(in thousands)
2017	$	914
2018	1,099
2019	560
	2,573
Less executory cost	(96		)
Less amount representing interest	(263		)
Present value of minimum lease payments	$	2,214
Short-term capital lease obligations	$	699
Long-term capital lease obligations	1,515
	$	2,214

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

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

	2016			2015
	(in thousands)
Balance at beginning of period	$	89,492		$	73,855
Obligations incurred with development activities and assumed with acquisitions	4,894			2,373
Accretion expense	7,080			6,293
Revisions in estimated cash flows	—			11,658
Obligations discharged with disposal of properties and asset retirements	(9,079		)	(4,687		)
Balance at end of period	92,387			89,492
Less current portion	(9,775		)	(5,460		)
Long-term portion	$	82,612		$	84,032

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COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Supply Commitment [Table Text Block]

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

	Year Ending December 31,
Area	2017		2018		2019		2020		2021 and Through Expiration		Total		Expiration Date
Natural gas (MMcf)
Wattenberg Field (1)	—		2,300		17,125		18,300		86,700		124,425		September 30, 2025
Gas Marketing segment	7,117		7,117		7,117		7,136		11,550		40,037		August 31, 2022
Utica Shale	2,738		2,738		2,738		2,745		7,064		18,023		July 22, 2023
Total	9,855		12,155		26,980		28,181		105,314		182,485
Crude oil (MBbls)
Wattenberg Field	2,413		2,413		2,413		1,204		—		8,443		June 30, 2020
Dollar commitment (in thousands)	$	17,158	$	18,626	$	33,221	$	27,430	$	89,896	$	186,331

__________

(1) In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities.  The midstream provider is expected to construct a new 200 MMcfd cryogenic plant.  We will be bound to the volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which in the above table is estimated to be September 30, 2018.  The agreement requires a baseline volume commitment of current sales volumes to this midstream provider and an incremental volume commitment of 50 MMcfd for seven years, of which we may be required to pay a shortfall fee for any volumes under the 50 MMcfd incremental commitment.  Any shortfall of this volume commitment may be offset, in part, by additional third party producers’ volumes sold to the midstream provider when a certain total volume is achieved. We are also required for the first three years of the contract to guarantee a certain target profit margin to the midstream provider on these volumes sold.  Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments.  Using the NYMEX forward pricing strip at December 31, 2016, the target profit margin would be achieved without an additional payment from us.

Schedule of Minimum Future Lease Payments under the Non-cancelable Operating Leases [Table Text Block]

The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2016:

	Year Ending December 31,
	2017		2018		2019		2020		2021		Thereafter		Total
	(in thousands)
Minimum Lease Payments	$	3,056	$	3,041	$	3,033	$	3,093	$	3,154	$	6,786	$	22,163

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COMMON STOCK Common Stock (Tables)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Schedule of Stock by Class [Table Text Block]

The following table provides a summary of our public offerings of common stock in 2016 and 2015:

Date	Shares Issued	Price per Share		Net Proceeds
				(in millions)
September 2016	9,085,000	$	61.51	$	558.5
March 2016	5,922,500	50.11		296.6
March 2015	4,002,000	50.73		202.9

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]

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:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Stock-based compensation expense	$	19,502		$	20,068		$	17,518
Income tax benefit	(7,296		)	(7,636		)	(5,955		)
Net stock-based compensation expense	$	12,206		$	12,432		$	11,563

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

he Compensation Committee has awarded SARs to our executive officers in 2016, 2015, and 2014. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:

	Year Ended December 31,
	2016			2015			2014
Expected term of award	6.0 years			5.2 years			6.0 years
Risk-free interest rate	1.8		%	1.4		%	2.1		%
Expected volatility	54.5		%	58.0		%	65.6		%
Weighted-average grant date fair value per share	$	26.96		$	22.23		$	29.96

Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity [Table Text Block]

The following table presents the changes in our SARs for all periods presented:

	Year Ended December 31,
	2016							2015						2014
	Number of SARs		Weighted-Average Exercise Price		Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)		Number of SARs		Weighted-Average Exercise Price		Aggregate Intrinsic Value (in thousands)		Number of SARs	Weighted-Average Exercise Price		Aggregate Intrinsic Value (in thousands)
Outstanding beginning of year, January 1,	326,453		$	38.99	7.3	$	4,697	279,011		$	38.77	$	1,472	190,763	$	33.77	$	3,711
Awarded	58,709		51.63		—	—		68,274		39.63		—		88,248	49.57		—
Exercised	(141,084	)	40.16		—	2,770		(20,832	)	38.05		473		—	—		—
Outstanding at December 31,	244,078		41.36		6.9	7,620		326,453		38.99		4,697		279,011	38.77		1,472
Exercisable at December 31,	174,919		38.72		6.3	5,924		222,489		37.70		3,489		139,334	36.27		982

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

The following table presents the changes in non-vested time-based awards during 2016:

	Shares		Weighted-Average Grant Date Fair Value
Non-vested at December 31, 2015	525,081		$	50.23
Granted	290,010		58.52
Vested	(317,034	)	48.61
Forfeited	(18,415	)	56.10
Non-vested at December 31, 2016	479,642		56.09

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

	As of/Year Ended December 31,
	2016		2015		2014
	(in thousands, except per share data)
Total intrinsic value of time-based awards vested	$	18,973	$	17,077	$	18,278
Total intrinsic value of time-based awards non-vested	34,812		28,029		23,290
Market price per common share as of December 31,	72.58		53.38		41.27
Weighted-average grant date fair value per share	58.52		48.88		56.45

Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block]

he weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions:

	Year Ended December 31,
	2016			2015
Expected term of award	3 years			3 years
Risk-free interest rate	1.2		%	0.9		%
Expected volatility	52.3		%	53.0		%
Weighted-average grant date fair value per share	$	72.54		$	66.16

Schedule of Nonvested Performance-based Units Activity [Table Text Block]

The following table presents the change in non-vested market-based awards during 2016:

	Shares		Weighted-Average Grant Date Fair Value per Share
Non-vested at December 31, 2015	71,549		$	63.60
Granted	24,280		72.54
Vested	(47,409	)	66.78
Non-vested at December 31, 2016	48,420		64.97

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

	As of/Year Ended December 31,
	2016		2015		2014
	(in thousands, except per share data)
Total intrinsic value of market-based awards vested	$	6,562	$	4,293	$	1,260
Total intrinsic value of market-based awards non-vested	3,514		3,819		3,455
Market price per common share as of December 31,	72.58		53.38		41.27
Weighted-average grant date fair value per share	72.54		66.16		56.87

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation [Table Text Block]

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

	Year Ended December 31,
	2016	2015	2014
	(in thousands)
Weighted-average common shares outstanding - basic	49,052	39,153	35,784
Dilutive effect of:
Restricted stock	—	—	279
Convertible notes	—	—	564
Other equity-based awards	—	—	51
Weighted-average common shares and equivalents outstanding - diluted	49,052	39,153	36,678

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]

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:

	Year Ended December 31,
	2016	2015	2014
	(in thousands)
Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	689	831	8
Convertible notes	292	562	—
Other equity-based awards	109	101	26
Total anti-dilutive common share equivalents	1,090	1,494	34

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ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Assets Held for Sale, Divestitures and Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2016

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

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

Consolidated statements of operations - discontinued operations	Year Ended December 31, 2014
	(in thousands)
Revenues
Crude oil, natural gas and NGLs sales	$	24,149
Commodity price risk management loss, net	(1,085		)
Other income	48
Total revenues	23,112
Costs, expenses and other
Lease operating expenses	1,280
Production taxes	1,579
Transportation, gathering and processing expenses	3,536
Impairment of properties and equipment	433
Depreciation, depletion and amortization	9,128
Other	4,170
Gain on sale of properties and equipment	(76,479		)
Total costs, expenses and other	(56,353		)
Interest expense	(2,222		)
Interest income	194
Income from discontinued operations	77,437
Provision for income taxes	(29,263		)
Income from discontinued operations, net of tax	$	48,174

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BUSINESS SEGMENTS Business Segments (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Schedule of Segment Reporting Information [Table Text Block]

The following tables present our segment information:

	2016			2015			—	2014
	(in thousands)
Year Ended December 31,
Segment revenues:
Oil and gas exploration and production	$	374,190		$	584,406			$	784,636
Gas marketing	8,725			10,920				71,571
Total revenues	$	382,915		$	595,326			$	856,207
Segment income (loss) before income taxes:
Oil and gas exploration and production	$	(170,370	)	$	31,429			$	344,149
Gas marketing	(1,468		)	(797		)		(445		)
Unallocated	(221,285		)	(137,220		)		(166,476		)
Income (loss) before income taxes	$	(393,123	)	$	(106,588	)		$	177,228
Expenditures for segment long-lived assets:
Oil and gas exploration and production	$	436,884		$	599,617			$	623,912
Acquisition of crude oil and natural gas properties, net of cash acquired	1,073,723			—				—
Unallocated	3,464			5,051				4,680
Total	$	1,514,071		$	604,668			$	628,592
As of December 31,
Segment assets:
Oil and gas exploration and production	$	4,451,510		$	2,294,288
Gas marketing	4,329			4,217
Unallocated	30,003			72,038
Total assets	$	4,485,842		$	2,370,543

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Supplemental Information on Natural Gas and Crude Oil Exploration, Development and Production Activities (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities [Abstract]

Index price for reserves, by commodity [Table Text Block]

The indicated index prices for our reserves, by commodity, are presented below.

	Average Benchmark Prices
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	42.75	$	2.48	$	42.75
2015	50.28		2.59		50.28
2014	94.99		4.35		94.99

Schedule of Prices Used to Estimate Natural Gas and Crude Oil Reserves [Table Text Block]

The netted back price used to estimate our reserves, by commodity, are presented below.

	Price Used to Estimate Reserves*
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)
2016	$	38.67	$	1.85	$	11.97
2015	42.10		2.05		12.23
2014	84.65		3.92		32.27

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

The following tables present the changes in our estimated quantities of proved reserves:

	Crude Oil, Condensate (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)
Proved Reserves:
Proved reserves, January 1, 2014 (1)	93,830		739,640		48,671		265,774
Revisions of previous estimates	(29,777	)	(149,064	)	(10,204	)	(64,825	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	40,792		202,957		23,411		98,029
Acquisition of reserves	5		43		5		17
Dispositions	(13	)	(237,306	)	(8	)	(39,572	)
Production	(4,322	)	(19,298	)	(1,756	)	(9,294	)
Proved reserves, December 31, 2014	100,515		536,972		60,119		250,129
Revisions of previous estimates	(43,268	)	(154,775	)	(24,407	)	(93,471	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	48,707		311,709		30,835		131,494
Acquisition of reserves	17		215		23		76
Dispositions	(12	)	(82	)	(8	)	(34	)
Production	(6,984	)	(33,302	)	(2,835	)	(15,369	)
Proved reserves, December 31, 2015	98,975		660,737		63,727		272,825
Revisions of previous estimates	(22,097	)	(80,426	)	(7,130	)	(42,631	)
Extensions, discoveries and other additions	494		4,094		355		1,531
Acquisition of reserves	50,126		305,224		32,586		133,583
Dispositions	(601	)	(4,202	)	(424	)	(1,725	)
Production	(8,728	)	(51,730	)	(4,826	)	(22,176	)
Proved reserves, December 31, 2016	118,169		833,697		84,288		341,407

Proved Developed Reserves, as of:
December 31, 2014	26,798	186,633	17,002	74,905
December 31, 2015	26,257	175,367	15,011	70,496
December 31, 2016	30,013	264,452	24,196	98,284
Proved Undeveloped Reserves, as of:
December 31, 2014	73,717	350,339	43,117	175,224
December 31, 2015	72,718	485,370	48,716	202,329
December 31, 2016	88,156	569,245	60,092	243,122

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to gas marketing and other income.

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Revenue:
Crude oil, natural gas and NGLs sales	$	497,353		$	378,713		$	495,562
Commodity price risk management gain (loss), net	(125,681		)	203,183			309,219
	371,672			581,896			804,781
Expenses:
Lease operating expenses	59,950			56,992			43,682
Production taxes	31,410			18,443			27,194
Transportation, gathering and processing expenses	18,415			10,151			8,128
Exploration expense	4,669			1,102			948
Impairment of properties and equipment	9,973			161,620			167,280
Depreciation, depletion, and amortization	413,105			298,760			201,656
Accretion of asset retirement obligations	7,080			6,293			3,455
Loss on sale of properties and equipment	(43		)	(385		)	(75,972		)
	544,559			552,976			376,371
Results of operations for crude oil and natural gas producing activities before provision for income taxes	(172,887		)	28,920			428,410
Provision for income taxes	64,733			(10,394		)	(166,930		)
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	(108,154	)	$	18,526		$	261,480

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below.

	Year Ended December 31,
	2016		2015		2014
	(in thousands)
Acquisition of properties: (1)
Proved properties (2)	$	268,567	$	3,561	$	11,973
Unproved properties	1,843,985		15		45,999
Development costs (3)	383,336		552,104		608,176
Exploration costs: (4)
Exploratory drilling	—		—		—
Geological and geophysical	4,669		—		1
Total costs incurred	$	2,500,557	$	555,680	$	666,149

__________

(1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.

(2) Includes approximately $40.9 million of infrastructure and pipeline costs in 2016.

(3) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2016, 2015, and 2014, $204.6 million, $207.8 million, and $125.2 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end.

(4) Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below:

	As of December 31,
	2016			2015
	(in thousands)
Proved crude oil and natural gas properties	$	3,499,718		$	2,881,189
Unproved crude oil and natural gas properties	1,874,671			60,498
Uncompleted wells, equipment and facilities	150,424			109,385
Capitalized costs	5,524,813			3,051,072
Less accumulated DD&A	(1,534,678		)	(1,131,705		)
Capitalized costs, net	$	3,990,135		$	1,919,367

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves.

	As of December 31,
	2016			2015			2014
	(in thousands)
Future estimated cash flows	$	7,122,525		$	6,297,298		$	12,550,515
Future estimated production costs*	(1,624,167		)	(1,493,040		)	(2,746,811		)
Future estimated development costs	(2,219,914		)	(2,036,685		)	(2,528,755		)
Future estimated income tax expense	(597,476		)	(508,332		)	(2,336,510		)
Future net cash flows	2,680,968			2,259,241			4,938,439
10% annual discount for estimated timing of cash flows	(1,260,339		)	(1,162,377		)	(2,631,974		)
Standardized measure of discounted future estimated net cash flows	$	1,420,629		$	1,096,864		$	2,306,465

___________

* Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses.

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows:

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Beginning of period	$	1,096,864		$	2,306,465		$	1,782,163
Sales of crude oil, natural gas and NGLs production, net of production costs	(387,576		)	(293,127		)	(387,789		)
Net changes in prices and production costs (1)	(205,760		)	(1,752,921		)	129,213
Extensions, discoveries, and improved recovery, less related costs	15,128			489,178			1,444,581
Sales of reserves	(3,745		)	(463		)	(402,595		)
Purchases of reserves	487,636			374			238
Development costs incurred during the period	268,672			368,840			161,404
Revisions of previous quantity estimates	(320,286		)	(1,286,462		)	(654,318		)
Changes in estimated income taxes	(13,630		)	902,994			(221,874		)
Net changes in future development costs	391,145			112,958			46,499
Accretion of discount	133,747			345,007			270,389
Timing and other	(41,566		)	(95,979		)	138,554
End of period	$	1,420,629		$	1,096,864		$	2,306,465

__________

(1) Our weighted-average price, net of production costs per Boe, in our 2016 reserve report decreased to $15.73 as compared to $17.30 for 2015 and $37.78 for 2014.

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NATURE OF OPERATIONS AND BASIS OF PRESENTATION Additional Information (Details)	12 Months Ended
	Dec. 31, 2016 Wells
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Oil and gas producing wells, gross	2,900
Number of Operating Segments	2

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Detail (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Significant Accounting Plicies [Line Items]
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	$ 286,000
Cumulative Effect on Retained Earnings, Net of Tax	(286,000)
Assets Held-for-sale	5,300,000	$ 2,874,000
Non-Oil and gas Depreciation, Depletion and Amortization	3,800,000	4,500,000	$ 4,100,000
Capitalized Interest	4,500,000	5,100,000	3,500,000
Production Tax Liability	29,000,000	19,000,000
Allocated Share-based Compensation Expense	19,502,000	$ 20,068,000	17,518,000
Revolving Credit Facility [Member]
Significant Accounting Plicies [Line Items]
Amortization of Debt Issuance Costs	8,800,000		$ 3,600,000
cumulative-effect adjustment [Member]
Significant Accounting Plicies [Line Items]
Allocated Share-based Compensation Expense	$ 112,000

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BUSINESS COMBINATIONS BUSINESS COMBINATIONS (Details) $ in Thousands, shares in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($) a Wells shares	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Oil and gas producing wells, gross | Wells		2,900
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		$ 690,702	$ 0	$ 0
Delaware Basin Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 952,142	952,142
Payments for Deposits Applied to Debt Retirements		$ 40,000
Oil and gas producing wells, gross | Wells		30
Gas and Oil Area, Developed, Gross | a		57,900
Stock Issued During Period, Shares, Acquisitions | shares		9.4
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		$ 5,600
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual		(1,700)
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		$ 690,702
Delaware Basin Acquisition, Reeves and Culberson Counties, Texas [Member]
Business Acquisition [Line Items]
Gas and Oil Area, Developed, Gross | a		4,600
Payments to Acquire Oil and Gas Property		$ 120,600

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BUSINESS COMBINATIONS Pro Form Detail (Details) - Delaware Basin Acquisition [Member] - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	$ 5,600,000
Business Acquisition, Pro Forma Net Income (Loss)	$ (270,942)	$ (138,904)
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ (4.22)	$ (2.41)
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	$ (1,700,000)
Business Acquisition, Pro Forma Revenue	$ 412,746	$ 598,932

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BUSINESS COMBINATIONS Fair Value of Net Assets (Details) number in Thousands, $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Fair Value of Net Assets [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		$ 690,702	$ 0	$ 0
Goodwill		62,041	$ 0
Delaware Basin Acquisition [Member]
Fair Value of Net Assets [Line Items]
Payments to Acquire Business Two, Net of Cash Acquired		912,142
Payments for Deposits Applied to Debt Retirements		40,000
Payments to Acquire Businesses, Gross	$ 952,142	952,142
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		690,702
Goodwill, Purchase Accounting Adjustments		1,026
Business Combination, Consideration Transferred	$ (1,643,870)	1,643,870
Business Combination, Contingent Consideration, Asset, Current		$ 8,201
Business Acquisitions Purchase Price Allocation Proved Natural Gas Properties		216,000
business acquisition purchase price allocation unproved properties		$ 1,721,334
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Equipment		32,590
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		12,148
Goodwill		62,041
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets		2,052,314
Business Combination, Contingent Consideration, Liability, Current		(24,844)
Business Acquisition Purchase Price Allocation Asset Retirement Obligation		(3,705)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities		(379,895)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities		(408,444)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		$ 1,643,870

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PROPERTIES AND EQUIPMENT Properties and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Proved Natural Gas and Crude Oil Properties	$ 3,499,718	$ 2,881,189
Unproved Natural Gas and Crude Oil Properties	1,874,671	60,498
Total Natural Gas and Crude Oil Properties	5,374,389	2,941,687
Transportation and Other Equipment	62,093	30,098
Land and Buildings	12,165	12,667
Construction in Progress	122,591	113,115
Property and Equipment, at cost	5,571,238	3,097,567
Accumulated Depreciation, Depletion and Amortization	(1,562,972)	(1,157,015)
Property and Equipment, Net	$ 4,008,266	$ 1,940,552

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PROPERTIES AND EQUIPMENT Impairment of Natural Gas and Crude Oil Properties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Continuing Operations:
Impairment of proved and unproved properties	$ 5,562	$ 154,608	$ 161,604
Amortization of Individually Insignificant Unproved Properties	1,379	7,012	4,465
Impairment of Long-Lived Assets to be Disposed of	3,032	0	778
Results of Operations, Impairment of Oil and Gas Properties	9,973	161,620	166,847
Discontinued operations:
Impairment of individually significant unproved properties from discontinued operations	0	0	433
Total discontinued operations	0	0	433
Total impairment of natural gas and crude oil properties	$ 9,973	161,620	167,280
Capitalized Well Costs
Continuing Operations:
Impairment of proved and unproved properties		24,700
Lease Acquisition Costs
Continuing Operations:
Impairment of proved and unproved properties		150,300
Unproved Properties
Continuing Operations:
Impairment of proved and unproved properties		$ 125,600	45,700
Proved and unproved properties
Continuing Operations:
Impairment of proved and unproved properties			158,300
Proved Properties
Continuing Operations:
Impairment of proved and unproved properties			$ 112,600

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PROPERTIES AND EQUIPMENT Properties and Equipment Acreage exchange (Details)	Dec. 31, 2016 a
PDC acres transferred to Noble [Member] [Member]
Property, Plant and Equipment [Line Items]
Gas and Oil Area, Developed, Gross	13,500
PDC acres transferred to Noble [Member]
Property, Plant and Equipment [Line Items]
Gas and Oil Area, Developed, Gross	11,700

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DERIVATIVE FINANCIAL INSTRUMENTS Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 81,190	$ 2,290
Derivative Asset, Fair Value, Gross Asset	11,177	266,046
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8,791	221,659
Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,386	44,387
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	53,595	1,595
Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27,595	695
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	8,239	221,161
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	1,104	44,292
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	53,353	0
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	27,581	275
Commodity Contracts Related to Natural Gas Marketing [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	251	441
Commodity Contracts Related to Natural Gas Marketing [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	19	51
Commodity Contracts Related to Natural Gas Marketing [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	212	417
Commodity Contracts Related to Natural Gas Marketing [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	14	46
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	301	57
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	1,263	44
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	30	1,178
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives	$ 0	$ 374

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DERIVATIVE FINANCIAL INSTRUMENTS Impact of Derivative Instruments on Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commodity Price Risk Management, net
Derivative [Line Items]
Net settlements	$ 208,103	$ 238,935	$ (837)
Net change in fair value of unsettled derivatives	(333,784)	(35,752)	311,141
Total Derivative Gain (Loss)	(125,681)	203,183	310,304
Sales From Natural Gas Marketing
Derivative [Line Items]
Net settlements	543	778	(208)
Net change in fair value of unsettled derivatives	(676)	(318)	364
Total Derivative Gain (Loss)	(133)	460	156
Cost of Natural Gas Marketing
Derivative [Line Items]
Net settlements	(483)	(745)	346
Net change in fair value of unsettled derivatives	690	279	(451)
Total Derivative Gain (Loss)	$ 207	$ (466)	$ (105)

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DERIVATIVE FINANCIAL INSTRUMENTS Effect of Master Netting Agreements (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 11,177	$ 266,046
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(10,930)	(1,921)
Derivative Asset	247	264,125
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	81,190	2,290
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(10,930)	(1,921)
Derivative Liability	$ 70,260	$ 369

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DERIVATIVE FINANCIAL INSTRUMENTS Additional Information (Details) MMBTU in Thousands	Dec. 31, 2016 MMBTU MBbls
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Portion of Anticipated Natural Gas Production Hedged (MMBtu) | MMBTU	81,720
Portion of Future Oil and Gas Production Being Hedged (MBbls) | MBbls	13,342

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FAIR VALUE MEASUREMENTS AND DISCLOSURES Fair Value Measurements and Disclosures (Details) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2016	Dec. 31, 2015
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure		$ 6,350	$ 174,758
Liabilities, Fair Value Disclosure		66,789	2,290
Net Asset Fair Value		(60,439)	172,468
Fair Value | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure		4,827	91,288
Liabilities, Fair Value Disclosure		14,401	0
Net Asset Fair Value		(9,574)	91,288
Fair Value | Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value Disclosure		11,177	266,046
Liabilities, Fair Value Disclosure		81,190	2,290
Net Asset Fair Value		(70,013)	$ 263,756
1.125% Convertible Senior Notes due 2021 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.125%
7.75% senior notes fair value		$ 220,200
7.75% senior notes fair value as percentage of par		110.10%
6.125% Senior Notes due 2024 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.125%
7.75% senior notes fair value		$ 408,000
7.75% senior notes fair value as percentage of par		102.00%
7.75% Senior Notes due 2022 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.75%
7.75% senior notes fair value		$ 535,000
7.75% senior notes fair value as percentage of par		107.00%

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FAIR VALUE MEASUREMENTS AND DISCLOSURES Reconciliation of Level 3 Fair Value Measurements (Details) - Derivative Financial Instrument Net Assets [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value	$ (9,574)	$ 91,288	$ 62,356	$ 1,111
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	(12,905)	43,540	15,635
Commodity Price Risk Management, net
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings	(28,530)	65,018	62,003
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	(72,242)	(36,169)	(737)
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	(12,905)	43,540	15,632
Sales From Natural Gas Marketing
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings	(20)	146	(22)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	(70)	(63)	1
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	$ 0	$ 0	$ 3

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CONCENTRATION OF RISK Accounts Receivable, Net of Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Income Taxes Receivable	$ 11,505	$ 0
Allowance for Doubtful Accounts Receivable, Current	(2,190)	(2,009)
Accounts Receivable, Net, Current	143,392	104,274
Natural gas, NGLs and crude oil sales
Concentration Risk [Line Items]
Accounts Receivable, Gross	97,520	41,873
Joint interest billing
Concentration Risk [Line Items]
Accounts Receivable, Gross	20,118	35,017
Derivative Counterparties
Concentration Risk [Line Items]
Accounts Receivable, Gross	10,266	24,437
Insurance Reimbursement
Concentration Risk [Line Items]
Accounts Receivable, Gross	0	879
Other Accounts Receivable
Concentration Risk [Line Items]
Accounts Receivable, Gross	$ 6,173	$ 4,077

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CONCENTRATION OF RISK Customer Constituting 10% or more of Total Revenue (Details)	12 Months Ended
	Dec. 31, 2016 Rate	Dec. 31, 2015 Rate	Dec. 31, 2014 Rate
Suncor Energy Marketing, Inc.
Concentration Risk [Line Items]
Percentage of Revenue	22.30%	14.30%	19.70%
DCP Midstream, LP
Concentration Risk [Line Items]
Percentage of Revenue	20.20%	13.20%	15.10%
Aka Energy Group. LLC [Member]
Concentration Risk [Line Items]
Percentage of Revenue	13.40%	0.00%	0.00%
Concord Energy
Concentration Risk [Line Items]
Percentage of Revenue	13.40%	23.20%	18.30%
Bridger Energy, LLC [Member]
Concentration Risk [Line Items]
Percentage of Revenue	11.50%	0.00%	0.00%
Shell Trading Company
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	13.80%	0.00%
Teppco Crude Oil
Concentration Risk [Line Items]
Percentage of Revenue	0.00%	0.00%	12.90%

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CONCENTRATION OF RISK Notes Receivable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Oct. 14, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Note Receivable - Principal Outstanding	$ 43,069
Paid-in-Kind Interest	3,400
Note receivable - interest income	4,500
Provision for Doubtful Accounts	(44,038)	$ 0	$ 0
Notes Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Paid-in-Kind Interest	969	3,362
Notes, Loans and Financing Receivable, Gross, Noncurrent	$ 44,038	$ 43,069	$ 39,707	$ 39,000

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CONCENTRATION OF RISK Other accrued expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Accrued Employee Benefits	$ 22,282	$ 17,774
Asset Retirement Obligation, Current	9,775	5,460
Accrued Environmental Liabilities	3,238	4,143
Other Accrued Liabilities	3,330	1,332
Other Accrued Liabilities, Noncurrent	$ 38,625	$ 28,709

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INCOME TAXES Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current Federal Tax Benefit (Expense)	$ 9,646	$ (2,944)	$ (1,514)
Current State and Local Tax Benefit (Expense)	300	(163)	966
Current Income Tax Benefit (Expense)	9,946	(3,107)	(548)
Deferred Federal Income Tax Benefit (Expense)	118,427	37,352	(60,698)
Deferred State and Local Income Tax Benefit (Expense)	18,822	4,063	(8,721)
Deferred Income Tax Benefit (Expense)	137,249	41,415	(69,419)
Provision for income taxes	$ 147,195	$ 38,308	$ (69,967)

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INCOME TAXES Reconciliation of Statutory Rate to Effective Rate (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory tax rate	35.00%	35.00%	35.00%
State income tax, net	2.60%	2.70%	2.80%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ 0.006	$ (0.003)	$ 0.000
Percentage depletion	0.00%	0.30%	(0.30%)
Non-deductible compensation	(0.50%)	(1.20%)	0.70%
Income tax reconciliation, excess tax benefits from stock-based compensation	$ (0.004)	$ 0.000	$ 0.000
Other	(0.70%)	(0.60%)	(1.30%)
Effective Income Tax Rate Reconciliation, Percent	(37.40%)	35.90%	39.50%

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INCOME TAXES Tax Effects of Temporary differences that Give Rise to Significant Portions of the Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Components of Deferred Tax Assets [Abstract]
Deferred compensation	$ 9,338	$ 13,104
Asset retirement obligations	34,359	34,101
deferred tax assets, federal tax	29,988	0
State NOL and tax credit carryforwards, net	5,189	3,376
Alternative minimum tax - credit carryforward	5,184	2,812
Deferred tax assets, Allowance for note receivable	17,292	0
Deferred Tax Assets, Derivative Instruments	26,262	0
Other	4,716	3,412
Deferred tax assets	132,328	56,805
Components of Deferred Tax Liabilities [Abstract]
properties and equipment	518,964	99,191
Net change in fair value of unsettled derivatives	0	100,369
Convertible debt	14,231	697
Total gross deferred tax liabilities	533,195	200,257
Net deferred tax liability	$ 400,867	$ 143,452

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INCOME TAXES Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Unrecognized Tax Benefits:
Unrecognized Tax Benefits, Period Increase (Decrease)	$ 1.5
Unrecognized Tax Benefits		$ 1.4

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INCOME TAXES Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards:
Deferred Tax Assets, Operating Loss Carryforwards	$ 55,400,000
Deferred tax asset, operating loss carryforward, annual limitation	15,100,000
Deferred tax asset, NOL carryback	32,200,000
Operating Loss Carryforwards	23,100,000.0
Alternative minimum tax - credit carryforward	5,184,000	$ 2,812,000
State NOL Carryforwards
Operating Loss Carryforwards:
State NOL carryforwards	$ 130,500,000
Year Carryforwards Expire	Dec. 31, 2030
State Credit Carryforwards
Operating Loss Carryforwards:
State credit carryforwards	$ 1,800,000
Year Carryforwards Expire	Dec. 31, 2022
Delaware Basin Acquisition [Member]
Operating Loss Carryforwards:
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent	$ 403,700,000.0
Deferred Tax Assets, Net	23,800,000
Deferred Tax Assets, Operating Loss Carryforwards	$ 62,500,000

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LONG-TERM DEBT SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 14, 2016	Sep. 14, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total senior notes	$ 1,043,954			$ 605,377
Total debt, net of discount and unamortized debt issuance costs	1,043,954			642,377
Less current portion of long-term debt	0			112,940
Long-term debt	1,043,954			529,437
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Principal amount	(200,000)			0
Unamortized Discount	37,475			0
Unamortized Debt Issuance Costs	4,584	$ 4,800		0
3.25% Convertible senior notes due 2016, net of discount and unamortized debt issuance costs	157,941			0
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs	7,544		$ 7,800	0
Principal amount	(400,000)			0
7.75% Senior notes due 2022, net of unamortized debt issuance costs	392,456			0
3.25% Convertible Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Principal amount	0			(115,000)
Unamortized Discount	0			(1,852)
Unamortized Debt Issuance Costs	0			(208)
3.25% Convertible senior notes due 2016, net of discount and unamortized debt issuance costs	0			112,940
7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs	6,443			7,563
Principal amount	(500,000)			(500,000)
7.75% Senior notes due 2022, net of unamortized debt issuance costs	493,557			492,437
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 0			$ 37,000

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LONG-TERM DEBT ADDITIONAL INFORMATION (Details) - USD ($)											3 Months Ended	12 Months Ended
	Oct. 15, 2022	Sep. 15, 2021	Mar. 15, 2021	May 21, 2020	Sep. 15, 2019	Sep. 12, 2016	May 16, 2016	May 15, 2016	Oct. 03, 2012	Nov. 15, 2010	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2021	Dec. 14, 2016	Sep. 14, 2016
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage												1.25%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage												0.50%
Debt Instrument, Maturity Date		Sep. 15, 2021
3.25% Convertible Note, Conversion Price												$ 85.39
Debt Issuance Costs ($)												$ 15,556,000	$ 974,000	$ 88,000
3.25% Convertible Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Debt Conversion, Converted Instrument, Shares Issued							792,406
Debt Conversion, Converted Instrument, Amount							$ 47,900,000
Debt Instrument, Issuance Date										Nov. 15, 2010
Debt Instrument, Maturity Date								May 15, 2016
Debt Instrument, Interest Rate, Stated Percentage												3.25%
3.25% Convertible Note, Conversion Price										$ 42.40
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Issuance Date						Sep. 12, 2016
Debt Instrument, Interest Rate, Stated Percentage												6.125%
Debt Instrument, Redemption Period, End Date					Sep. 15, 2019
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Issuance Date											Sep. 12, 2016
Debt Instrument, Interest Rate, Stated Percentage															1.125%
Convertible Senior Note, Shares Issued Upon Conversion												1171.13%
Convertible Note Principal Amount			$ 1,000
3.25% Convertible Note, Conversion Price			$ 85.39
3.25% Convertible Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Call Date, Latest			Mar. 15, 2021
7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Issuance Date									Oct. 03, 2012
Debt Instrument, Maturity Date	Oct. 15, 2022
Debt Instrument, Interest Rate, Stated Percentage												7.75%
Debt Issuance Costs ($)									$ 11,000,000
Debt Instrument, Call Date, Latest									Oct. 15, 2017
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity ($)												$ 1,000,000,000
Line of Credit Facility, Expiration Date				May 21, 2020
Line of Credit Facility, Remaining Borrowing Capacity												$ 688,300,000
Credit Facility - Restrictive Covenants												The revolving credit facility contains restrictions as to when we can directly or indirectly retire, redeem, repurchase, or prepay in cash any part of the principal of the 2021 Convertible Notes, 2022 Senior Notes, or 2024 Senior Notes. Among other things, the restriction on redemption of the 2021 Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement, or prepayment, the aggregate commitment under the revolving credit facility must exceed the aggregate credit exposure under such facility by at least an amount equal to or greater than 20 percent of such aggregate commitment.
Credit Facility - Covenant Description												The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00:1.00 and (b) not exceed a maximum leverage ratio of 4.00:1.00
Amortization of Debt Issuance Costs												$ 8,800,000		$ 3,600,000
RNG Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount ($)												11,700,000
7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs												6,443,000	7,563,000
Senior Notes ($)												$ 500,000,000	$ 500,000,000
First Payment [Member] | 6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment												March 15
First Payment [Member] | 1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment												March 15
First Payment [Member] | 7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment												April 15
Second Payment [Member] | 6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment												September 15
Second Payment [Member] | 1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment												September 15
Second Payment [Member] | 7.75% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Frequency of Periodic Payment												October 15
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate												2.70%	2.60%
Maximum Borrowing Base [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity ($)												$ 700,000,000
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
3.25% convertible senior notes fair value												200,000,000	$ 0
Liability component of gross proceeds of Convertible Notes												160,500,000
Unamortized Debt Issuance Costs												$ 4,584,000	0			$ 4,800,000
Debt Instrument, Interest Rate, Effective Percentage												5.80%
Share Price												$ 72.58
3.25% Convertible Debt, Equity Component ($)												$ 39,500,000
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Costs												7,544,000	0				$ 7,800,000
Senior Notes ($)												$ 400,000,000	$ 0
2024 Senior notes redemption price, prior to September 15, 2019 [Member] | 6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage					104.594%
2024 Senior notes redemption price, after September 15, 2019. [Member] | 6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage					106.125%

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CAPITAL LEASES (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Capital Leased Assets [Line Items]
Vehicles	$ 2,975	$ 1,601
Accumulated depreciation	(776)	(211)
Total leased assets, Net	$ 2,199	$ 1,390

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CAPITAL LEASES Future Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	$ 2,573
Less Executory Costs	96
Less Amounts Representing Interest	263
Present Value of Minimum Lease Payments	2,214
Short-term Capital Lease Obligations	699
Long-term Capital Lease Obligations	1,515
Total Capital Lease Obligations	2,214
2017 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	914
2018 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	1,099
2019 [Member]
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due	$ 560

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ASSET RETIREMENT OBLIGATIONS Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance beginning of year, January 1	$ 89,492	$ 73,855
Revisions in estimated cash flows	0	11,658
Obligations incurred with development activities and assumed with acquisitions	4,894	2,373
Accretion of asset retirement obligations	7,080	6,293	$ 3,455
Obligations discharged with disposal of properties and asset retirements	(9,079)	(4,687)
Balance end of year, December 31	92,387	89,492	$ 73,855
Less: Current portion	(9,775)	(5,460)
Long-term portion	$ 82,612	$ 84,032

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EMPLOYEE BENEFIT PLANS Employee Benefit Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Postretirement Benefit Expense	$ 4.8	$ 4.9	$ 3.9

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COMMITMENTS AND CONTINGENCIES Commitments and Contigencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) MBbls MMcf
Supply Commitment [Line Items]
incremental volume commitment	50
Oil and Gas Delivery Commitments Volumes (MMcf)	182,485
Dollar Commitment ($ in thousands) | $	$ 186,331
First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,855
Dollar Commitment ($ in thousands) | $	$ 17,158
Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	12,155
Dollar Commitment ($ in thousands) | $	$ 18,626
Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	26,980
Dollar Commitment ($ in thousands) | $	$ 33,221
Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	28,181
Dollar Commitment ($ in thousands) | $	$ 27,430
commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	105,314
Dollar Commitment ($ in thousands) | $	$ 89,896
Appalachiain Basin
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	40,037
Appalachiain Basin | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,117
Appalachiain Basin | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,136
Appalachiain Basin | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	11,550
Appalachiain Basin | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Aug. 31, 2022
Utica Shale
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	18,023
Utica Shale | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,738
Utica Shale | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,738
Utica Shale | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,738
Utica Shale | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,745
Utica Shale | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	7,064
Utica Shale | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Jul. 22, 2023
Natural Gas (Mcf) | Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	124,425	[1]
Natural Gas (Mcf) | Wattenberg Field | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0	[1]
Natural Gas (Mcf) | Wattenberg Field | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,300	[1]
Natural Gas (Mcf) | Wattenberg Field | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	17,125	[1]
Natural Gas (Mcf) | Wattenberg Field | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	18,300	[1]
Natural Gas (Mcf) | Wattenberg Field | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	86,700	[1]
Natural Gas (Mcf) | Wattenberg Field | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Sep. 30, 2025
Crude Oil (Bbls) | Wattenberg Field
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,443
Crude Oil (Bbls) | Wattenberg Field | First Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	2,413
Crude Oil (Bbls) | Wattenberg Field | Second Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	2,413
Crude Oil (Bbls) | Wattenberg Field | Third Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	2,413
Crude Oil (Bbls) | Wattenberg Field | Fourth Year Commitment [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	1,204
Crude Oil (Bbls) | Wattenberg Field | commitments 5 years and beyond [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	0
Crude Oil (Bbls) | Wattenberg Field | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Jun. 30, 2020

[1] In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct a new 200 MMcfd cryogenic plant. We will be bound to the volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which in the above table is estimated to be September 30, 2018. The agreement requires a baseline volume commitment of current sales volumes to this midstream provider and an incremental volume commitment of 50 MMcfd for seven years, of which we may be required to pay a shortfall fee for any volumes under the 50 MMcfd incremental commitment. Any shortfall of this volume commitment may be offset, in part, by additional third party producers’ volumes sold to the midstream provider when a certain total volume is achieved. We are also required for the first three years of the contract to guarantee a certain target profit margin to the midstream provider on these volumes sold. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments. Using the NYMEX forward pricing strip at December 31, 2016, the target profit margin would be achieved without an additional payment from us.

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COMMITMENTS AND CONTINGENCIES Minimum Lease Payments (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Minimum Future Lease Payments under Non-cancelable Operating Leases [Line Items]
2016	$ 3,056
2017	3,041
2018	3,033
2019	3,093
2020	3,154
Thereafter	6,786
Total	$ 22,163

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COMMITMENTS AND CONTINGENCIES Additional information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Operating Lease Expense	$ 10.2	$ 9.8	$ 7.0
Gas Marketing Segment
Loss Contingencies [Line Items]
Allowance for Doubtful Accounts Receivable	$ 1.3	$ 0.5

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COMMITMENTS AND CONTINGENCIES Long-term fIrm transportation costs (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses		$ 18,415,000	$ 10,151,000	$ 4,592,000
Utica Shale natural gas and Wattenberg Field crude oil [Member]
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses	$ 4,700,000	10,000,000		300,000
Utica Shale natural gas and Wattenberg Field crude oil [Member]
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses		$ 3.4	$ 3.4	$ 3.4

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COMMON STOCK Stockholders' Equity Note (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Value, Issued	$ 657	$ 402
Additional paid-in capital	2,489,557	$ 907,382
March 2015 Common Stock Issuance
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues		4,002,000
Sale of Stock, Price Per Share		$ 50.73
Proceeds from Issuance of Common Stock	$ 296,600	$ 202,900

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COMMON STOCK Stock based compensation plans (Details) - shares	Dec. 31, 2016	Dec. 31, 2015	Jun. 29, 2010
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Common Stock, Shares Authorized	150,000,000	150,000,000	3,000,000
Common stock shares remain avaliable for issuance	839,052

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COMMON STOCK Stocked Based Compensation Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 19,502	$ 20,068	$ 17,518
Income tax benefit	(7,296)	(7,636)	(5,955)
Net stock-based compensation expense	$ 12,206	$ 12,432	$ 11,563

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COMMON STOCK SARs Fair Value Assumptions (Details) - Stock Appreciation Rights (SARs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	The 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.
Expected term of award	6 years	5 years 2 months 14 days	6 years
Risk-free interest rate	1.80%	1.40%	2.10%
Expected Volatility	54.50%	58.00%	65.60%
Weighted-average grant date fair value per share	$ 26.96	$ 22.23	$ 29.96

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COMMON STOCK Schedule of Changes in SARs (Details) - Stock Appreciation Rights (SARs) [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of SARs
Outstanding beginning of year, January 1,	326,453	279,011	190,763
Awarded	58,709	68,274	88,248
Exercised	(141,084)	(20,832)	0
Outstanding end of year, December 31,	244,078	326,453	279,011
Exercisable at December 31,				174,919	222,489	139,334
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding beginning of year, January 1,	$ 38.99	$ 38.77	$ 33.77
Awarded	51.63	39.63	49.57
Exercised	40.16	38.05	0
Outstanding end of year, December 31,	$ 41.36	$ 38.99	$ 38.77
Exercisable at December 31,				$ 38.72	$ 37.70	$ 36.27
Weighted-Average Remaining Contractual Term (in years)
Outstanding at December 31,	6 years 10 months 19 days	7 years 3 months 6 days
Exercisable at December 31,	6 years 3 months 10 days
Share based compesation aggregate intrinsic valu [Roll Forward]
Outstanding beginning of year, January 1,	$ 7,620	$ 4,697	$ 1,472	$ 7,620	$ 4,697	$ 1,472	$ 3,711
Awarded	0	0	0
Exercised	2,770	473	0
Outstanding end of year, December 31,	$ 7,620	$ 4,697	$ 1,472
Exercisable at December 31,				5,924	$ 3,489	$ 982
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized				$ 1,500
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 8 months 22 days

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COMMON STOCK Schedule of Changes in Restricted Stock - TIme Based Awards (Details) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	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 that a participant is continuously employed.
Number of Shares
Outstanding beginning of year, January 1,	525,081
Granted	290,010
Vested	(317,034)
Forfeited	(18,415)
Outstanding end of year, December 31,	479,642	525,081
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 50.23
Weighted-average grant date fair value per share	58.52	$ 48.88	$ 56.45
Vested	48.61
Forfeited	56.10
Outstanding at end of year, December 31,	$ 56.09	$ 50.23
Total intrinsic value of time based awards vested	$ 18,973	$ 17,077	$ 18,278
Total intrinsic value of time-based awards non-vested	$ 34,812	$ 28,029	$ 23,290
Market price per common share as of December 31,	$ 72.58	$ 53.38	$ 41.27
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 17,500
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 10 months 19 days

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COMMON STOCK Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - Restricted Stock - Market Based Awards [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 6,562	$ 4,293	$ 1,260
Expected term of award	3 years	3 years
Risk-free interest rate	1.20%	0.90%
Expected Volatility	52.30%	53.00%
Weighted-average grant date fair value per share	$ 72.54	$ 66.16	$ 56.87

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COMMON STOCK Schedule of Changes in Restricted Stock - Market Based Awards (Details) - Restricted Stock - Market Based Awards [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 6,562	$ 4,293	$ 1,260
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	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.
Time based shares granted to executives	24,280
Number of Shares
Outstanding beginning of year, January 1,	71,549
Granted	24,280
Vested	(47,409)
Outstanding end of year, December 31,	48,420	71,549
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 63.60
Weighted-average grant date fair value per share	72.54	$ 66.16	$ 56.87
Vested	66.78
Outstanding at end of year, December 31,	$ 64.97	$ 63.60
Total intrinsic value of market-based awards non-vested	$ 3,514	$ 3,819	$ 3,455
Market price per common share as of December 31,	$ 72.58	$ 53.38	$ 41.27
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 1,700
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 8 months 18 days

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COMMON STOCK Treasury Shares (Details) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury stock acquired, and available for reissuance		9,009
Common Stock, Shares Held in Employee Trust, Shares	18,366	11,211
Treasury Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Treasury Stock, Shares, Acquired	116,085
Treasury stock acquired and reissued	114,697
Treasury stock acquired, and available for reissuance	10,397

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COMMON STOCK Preferred Stock (Details) - shares	Dec. 31, 2016	Dec. 31, 2015	Jun. 23, 2008
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Shares Authorized	50,000,000	50,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Shares Authorized			50,000,000
Preferred Stock, Shares Issued	0

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COMMON STOCK Stock Issuance (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
September 2016 Common Stock Issuance [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	9,085,000
Sale of Stock, Price Per Share	$ 61.51
Proceeds from Issuance of Common Stock	$ 558.5
March 2016 Common Stock Issuance [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	5,922,500
Sale of Stock, Price Per Share	$ 50.11
March 2015 Common Stock Issuance
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues		4,002,000
Sale of Stock, Price Per Share		$ 50.73
Proceeds from Issuance of Common Stock	$ 296.6	$ 202.9

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EARNINGS PER SHARE Earnings Per Share (Details)		12 Months Ended
	Nov. 15, 2010 shares $ / shares	Dec. 31, 2016 shares $ / shares	Dec. 31, 2015 shares	Dec. 31, 2014 shares
Reconciliation of Weighted-Average Diluted Shares Outstanding
Weighted average common shares outstanding - basic		49,052,000	39,153,000	35,784,000
Weighted Average Number of Shares Outstanding - Diluted		49,052,000	39,153,000	36,678,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		1,090,000	1,494,000	34,000
Convertible Senior Note Due 2016
3.25% Convertible Note, Number of Shares Convertible		2,300,000
3.25% Convertible Note, Conversion Price | $ / shares		$ 85.39
Restricted Stock [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements		0	0	279,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		689,000	831,000	8,000
3.25% Convertible Note [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements		0	0	564,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		292,000	562,000	0
Other Equity-Based Awards
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Share-based Payment Arrangements		0	0	51,000
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		109,000	101,000	26,000
3.25% Convertible Senior Notes due 2016 [Member]
Convertible Senior Note Due 2016
3.25% Convertible Note, Number of Shares Convertible	2,700,000
3.25% Convertible Note, Conversion Price | $ / shares	$ 42.40

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ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Discontinued Operations and Disposal Groups (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Lease operating expenses	$ 59,950	$ 56,992	$ 42,402
Production taxes	31,410	18,443	25,615
Transportation, gathering and processing expenses	18,415	10,151	4,592
Impairment of Natural Gas and Crude Oil Properties	0	0	433
Income (loss) from discontinued operations, net of tax	0	0	48,174
Supplemental Cash Flows Information
Capital expenditures	(436,884)	(599,546)	(623,750)
Change in accounts payable related to purchases of properties and equipment	$ (40,448)	$ (45,230)	39,667
Net Assets Related to Discontinued Operations [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Natural gas, NGL and crude oil sales			24,149
Commodity price risk management gain (loss), net			(1,085)
Well operations, pipeline income and other			48
Disposal Group, Discontinued Operations, Total revenue			23,112
Lease operating expenses			1,280
Production taxes			1,579
Transportation, gathering and processing expenses			3,536
Impairment of Natural Gas and Crude Oil Properties			433
Depreciation, depletion and amortization			9,128
Accretion of ARO and other, Discontinued Operations			4,170
(Gain) loss on sale of properties and equipment			(76,479)
Total costs, expenses and other			(56,353)
Disposal Group, Including Discontinued Operation, Interest Expense			(2,222)
Disposal Group, Including Discontinued Operation, Interest Income			194
Income (loss) from discontinued operations			77,437
Income taxes (expense) benefit			(29,263)
Income (loss) from discontinued operations, net of tax			48,174
PDCM Divestiture [Member]
Supplemental Cash Flows Information
Capital expenditures			(17,253)
Change in accounts payable related to purchases of properties and equipment			$ (5,727)

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ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS Additional Information (Details) - USD ($) $ in Thousands		12 Months Ended
	Oct. 15, 2014	Dec. 31, 2014	Oct. 14, 2014
Segment, Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain/loss on sale		$ 76,479
PDCM Divestiture [Member] | PDCM Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership Interest in Joint Venture			50.00%
Divestiture Sale Price After Adjustment	$ 192,000
Cash proceeds from PDCM divestiture	153,000
Promissory note	39,000
Gain/loss on sale	$ 76,300

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TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES Transactions with Affiliates and Other Related Parties (Details) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($)
PDCM
Related Party Transaction [Line Items]
Related party transactions included in cost of natural gas marketing	$ 23.2

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BUSINESS SEGMENTS Business segments (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total revenues	$ 108,097	$ 163,890	$ 20,097	$ 90,831	$ 168,634	$ 231,100	$ 50,960	$ 144,632	$ 382,915	$ 595,326	$ 856,207
Segment income (loss) before income taxes	(90,636)	$ (35,341)	$ (153,777)	$ (113,369)	5,274	$ (62,661)	$ (76,986)	$ 27,785	(393,123)	(106,588)	177,228
Expenditures for segment long-lived assets									1,514,071	604,668	628,592
Payments to Acquire Businesses, Net of Cash Acquired									1,073,723	0	0
Segment assets	4,485,842				2,370,543				4,485,842	2,370,543
Oil and Gas Properties
Segment Reporting Information [Line Items]
Total revenues									374,190	584,406	784,636
Segment income (loss) before income taxes									(170,370)	31,429	344,149
Expenditures for segment long-lived assets									436,884	599,617	623,912
Payments to Acquire Businesses, Net of Cash Acquired									1,073,723	0	0
Segment assets	4,451,510				2,294,288				4,451,510	2,294,288
Marketing
Segment Reporting Information [Line Items]
Total revenues									8,725	10,920	71,571
Segment income (loss) before income taxes									(1,468)	(797)	(445)
Segment assets	4,329				4,217				4,329	4,217
Corporate and Other
Segment Reporting Information [Line Items]
Segment income (loss) before income taxes									(221,285)	(137,220)	(166,476)
Expenditures for segment long-lived assets									3,464	5,051	$ 4,680
Segment assets	$ 30,003				$ 72,038				$ 30,003	$ 72,038

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BUSINESS SEGMENTS Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Crude oil and natural gas segment
Depreciation, depletion and amortization from continuing operations	$ 416,874	$ 303,258	$ 192,528
Oil and Gas Properties
Crude oil and natural gas segment
Depreciation, depletion and amortization from continuing operations	$ 413,100	$ 298,800	$ 188,500

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Prices Used to Estimate Reserves (Unaudited) (Details) - USD ($)		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Crude Oil (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1]	$ 38.67	$ 42.10	$ 84.65
Natural Gas (Mcf)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1]	1.85	2.05	3.92
Natural Gas Liquids (Bbls)
Schedule of Prices Used to Estimate Reserves [Line Items]
prices used to estimate oil and gas reserves	[1]	$ 11.97	$ 12.23	$ 32.27

[1] These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Changes in Estimated Proved Reserves (Unaudited) (Details) Mcf in Thousands	12 Months Ended
	Dec. 31, 2016 Boe Rate Mcf bbl	Dec. 31, 2015 Boe Rate Mcf bbl	Dec. 31, 2014 Boe Rate Mcf bbl	Dec. 31, 2013 Mcf bbl
Crude Oil (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	118,169,000	98,975,000	100,515,000	93,830,000
Production	(8,728,000)	(6,984,000)	(4,322,000)
Purchases of Reserves	50,126,000	17,000	5,000
Dispositions	(601,000)	(12,000)	(13,000)
Extensions, Discoveries, and Other Additions	494,000	48,707,000	40,792,000
Revisions of Previous Estimates	(22,097,000)	(43,268,000)	(29,777,000)
Proved Developed Reserves	30,013,000	26,257,000	26,798,000
Proved Undeveloped Reserve	88,156,000	72,718,000	73,717,000
Natural Gas (Mcf)
Reserve Quantities [Line Items]
Proved Reserves | Mcf	833,697	660,737	536,972	739,640
Production | Mcf	(51,730)	(33,302)	(19,298)
Purchases of Reserves | Mcf	305,224	215	43
Dispositions | Mcf	(4,202)	(82)	(237,306)
Extensions, Discoveries, and Other Additions | Mcf	4,094	311,709	202,957
Revisions of Previous Estimates | Mcf	(80,426)	(154,775)	(149,064)
Proved Developed Reserves | Mcf	264,452	175,367	186,633
Proved Undeveloped Reserve | Mcf	569,245	485,370	350,339
Natural Gas Liquids (Bbls)
Reserve Quantities [Line Items]
Proved Reserves	84,288,000	63,727,000	60,119,000	48,671,000
Production	(4,826,000)	(2,835,000)	(1,756,000)
Purchases of Reserves	32,586,000	23,000	5,000
Dispositions	(424,000)	(8,000)	(8,000)
Extensions, Discoveries, and Other Additions	355,000	30,835,000	23,411,000
Revisions of Previous Estimates	(7,130,000)	(24,407,000)	(10,204,000)
Proved Developed Reserves	24,196,000	15,011,000	17,002,000
Proved Undeveloped Reserve	60,092,000	48,716,000	43,117,000
Crude Oil Equivalent (Boe)
Reserve Quantities [Line Items]
Proved Reserves	341,407,000	272,825,000	250,129,000	265,774,000
Production	(22,176,000)	(15,369,000)	(9,294,000)
Purchases of Reserves	133,583,000	76,000	17,000
Dispositions	(1,725,000)	(34,000)	(39,572,000)
Extensions, Discoveries, and Other Additions	1,531,000	131,494,000	98,029,000
Revisions of Previous Estimates	(42,631,000)	(93,471,000)	(64,825,000)
Proved Developed Reserves	98,284,000	70,496,000	74,905,000
Proved Undeveloped Reserve	243,122,000	202,329,000	175,224,000
Year-over-Year Activity [Domain]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves percent increase or decrease | Rate	25.13773%
Increase (decrease) in proved reserves | Boe	68,582,000	23,000,000	(16,000,000)
Production	500,000
Proved developed and undeveloped reserves performance revisions	2,100,000
Undeveloped Reserves Converted to Developed	32,200,000.0	29,000,000	13,000,000
Estimated PUD conversion rate for following year | Rate	26.00%
Dispositions			(40,000,000)
Extensions, Discoveries, and Other Additions	16,800,000.0	131,000,000	98,000,000
Revisions of Previous Estimates		93,000,000	(65,000,000)
Estimated PUD conversion rate | Rate	19.00%	16.00%	7.00%
Actual PUD conversion rate | Rate	16.00%	17.00%	7.00%
2015 PUD Reserves [Member] | Year-over-Year Activity [Domain]
Reserve Quantities [Line Items]
Increase (decrease) in proved reserves | Boe	61,000,000.0

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Schedule of Developed and Undeveloped Reserves (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2016 Boe Rate bbl	Dec. 31, 2015 Boe Rate bbl	Dec. 31, 2014 Boe Rate bbl	Dec. 31, 2013 bbl
Crude Oil Equivalent (Boe)
Schedule of Developed and Undeveloped Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Net	341,407,000	272,825,000	250,129,000	265,774,000
Revisions of Previous Estimates	(42,631,000)	(93,471,000)	(64,825,000)
Extensions, Discoveries, and Other Additions	1,531,000	131,494,000	98,029,000
Purchases of Reserves	133,583,000	76,000	17,000
Dispositions	(1,725,000)	(34,000)	(39,572,000)
Production	(22,176,000)	(15,369,000)	(9,294,000)
Year-over-Year Activity [Domain]
Schedule of Developed and Undeveloped Reserves [Line Items]
Undeveloped Reserves Converted to Developed	32,200,000.0	29,000,000	13,000,000
Revisions of Previous Estimates		93,000,000	(65,000,000)
Extensions, Discoveries, and Other Additions	16,800,000.0	131,000,000	98,000,000
Wells Per Section		16
Gross PUD horizontal locations		791	774
Dispositions			(40,000,000)
Production	500,000
Increase (decrease) in proved reserves | Boe	68,582,000	23,000,000	(16,000,000)
Estimated PUD conversion rate | Rate	19.00%	16.00%	7.00%
Actual PUD conversion rate | Rate	16.00%	17.00%	7.00%
Change in drilling plans		(56,000,000)	(55,000,000)
Upward (Downward) Revision due to change in SEC pricing		(33,000,000)
Upward (Downward) Revision due to removal of re-fracs		(11,000,000)
Upward (downward) revision due to geological findings		(22,000,000)
Downward revisions due to adjustments in previous PUD well spacing plans			(2,000,000)
Downward revisions Wattenberg Field related to PUDs that are no longer in our core drilling area			(8,000,000)
Reserve discoveries from non-PUD drilling			16,000,000
Extension and discoveries due to adjustments in wells spacing in Wattenberg Field and Marcellus Shale			78,000,000
Extension and discoveries in the Utica Shale			2,000,000
Reserve discoveries, refracs not added in prior year report			2,000,000

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Results of Operations for Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Lease operating expenses	$ 59,950	$ 56,992	$ 42,402
Production taxes	31,410	18,443	25,615
Transportation, gathering and processing expenses	18,415	10,151	4,592
Results of Operations for Crude Oil and Natural Gas Producing Activities
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Natural gas, NGL and crude oil sales	497,353	378,713	495,562
Commodity price risk management	(125,681)	203,183	309,219
Total Revenues from Oil and Gas Producing Activities	371,672	581,896	804,781
Lease operating expenses	59,950	56,992	43,682
Production taxes	31,410	18,443	27,194
Transportation, gathering and processing expenses	18,415	10,151	8,128
Exploration Expense	4,669	1,102	948
Impairment of Oil and Gas Properties	9,973	161,620	167,280
Depreciation, Depletion and Amortization	413,105	298,760	201,656
Accretion of Asset Retirement Obligations	7,080	6,293	3,455
(Gain) loss on Sale of Properties and Equipment	(43)	(385)	(75,972)
Total Expense from Oil and Gas Producing Activities	544,559	552,976	376,371
Results of Operations of Natural Gas and Crude Oil Producing Activities, Income before Income Taxes	(172,887)	28,920	428,410
Provision for Income Taxes	64,733	(10,394)	(166,930)
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs	$ (108,154)	$ 18,526	$ 261,480

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities (Unadited) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved Properties	[1],[2]	$ 268,567	$ 3,561	$ 11,973
Unproved Properties	[2]	1,843,985	15	45,999
Development Costs	[3]	383,336	552,104	608,176
Exploratory drilling	[4]	0	0	0
Geological and geophysical	[4]	4,669	0	1
Total Costs Incurred		2,500,557	555,680	666,149
Cost Incurred to Convert PUDs to PDNP		$ 204,600	$ 207,800	$ 125,200

[1] Includes approximately $40.9 million of infrastructure and pipeline costs in 2016.

[2] Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.

[3] Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2016, 2015, and 2014, $204.6 million, $207.8 million, and $125.2 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end

[4] Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved natural gas and crude oil properties	$ 3,499,718	$ 2,881,189
Unproved natural gas and crude oil properties	1,874,671	60,498
Uncompleted Wells, Equipment and Facilities	150,424	109,385
Capitalized Costs	5,524,813	3,051,072
Less accumulated DD&A	(1,534,678)	(1,131,705)
Capitalized Costs, Net	$ 3,990,135	$ 1,919,367

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves (Unaudited) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Estimated Cash Flows	$ 7,122,525	$ 6,297,298	$ 12,550,515
Future Estimated Production Costs	(1,624,167)	(1,493,040)	(2,746,811)
Future Estimated Development Costs	(2,219,914)	(2,036,685)	(2,528,755)
Future Estimated Income Tax Expense	(597,476)	(508,332)	(2,336,510)
Future Net Cash Flows	2,680,968	2,259,241	4,938,439
10% Annual Discount for Estimated Timing of Cash Flows	(1,260,339)	(1,162,377)	(2,631,974)
Standardized Measure of Disconted Future Estimated Net Cash Flows	$ 1,420,629	$ 1,096,864	$ 2,306,465

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Unuadited) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Principal Sources of Change:
Sales of natural gas, NGL and crude oil production, net of production costs		$ (387,576,000)	$ (293,127,000)	$ (387,789,000)
Net changes in prices and production costs	[1]	(205,760,000)	(1,752,921,000)	129,213,000
Extensions, discoveries and improved recovery, less related costs		15,128,000	489,178,000	1,444,581,000
Sales of reserves		(3,745,000)	(463,000)	(402,595,000)
Purchases of reserves		487,636,000	374,000	238,000
Development costs incurred during the period		268,672,000	368,840,000	161,404,000
Revisions of previous quantity estimates		(320,286,000)	(1,286,462,000)	(654,318,000)
Changes in estimated income taxes		(13,630,000)	902,994,000	(221,874,000)
Net change in future development costs		391,145,000	112,958,000	46,499,000
Accretion of discount		133,747,000	345,007,000	270,389,000
Timing and other		(41,566,000)	(95,979,000)	138,554,000
Total		1,420,629,000	1,096,864,000	2,306,465,000	$ 1,782,163,000
Notes to Changes in SMOG [Abstract]
Weighted-Average price, net of production cost		$ 15.73	$ 17.30	$ 37.78

[1] Our weighted-average price, net of production costs per Boe, in our 2016 reserve report decreased to $15.73 as compared to $17.30 for 2015 and $37.78 for 2014

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SUPPLEMENTAL INFORMATION - NATURAL GAS AND CRUDE OIL PROPERTIES Index price of reserves (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
oil and gas index price for reserves [Line Items]
Effective Income Tax Rate Reconciliation, Percent	(37.40%)	35.90%	39.50%
Crude Oil (Bbls)
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	$ 42.75	$ 50.28	$ 94.99
Natural Gas Liquids (Bbls)
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	42.75	50.28	94.99
Natural Gas (Mcf)
oil and gas index price for reserves [Line Items]
oil and gas index price for reserves	$ 2.48	$ 2.59	$ 4.35

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SUPPLEMENTAL INFORMATION - QUARTERLY FINANCIAL INFORMATION QUARTERLY FINANCIAL INFORMATION (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Total revenues	$ 108,097	$ 163,890	$ 20,097	$ 90,831	$ 168,634	$ 231,100	$ 50,960	$ 144,632	$ 382,915	$ 595,326	$ 856,207
Costs, expenses and other:
Total cost, expenses and other	178,608	179,178	163,379	193,864	152,354	283,047	117,514	106,235	715,029	659,150	632,427
Income from operations	(70,511)	(15,288)	(143,282)	(103,033)	16,280	(51,947)	(66,554)	38,397	(332,114)	(63,824)	223,780
Income (loss) from continuing operations before income taxes	(90,636)	(35,341)	(153,777)	(113,369)	5,274	(62,661)	(76,986)	27,785	(393,123)	(106,588)	177,228
Net income (loss)	$ (55,639)	$ (23,309)	$ (95,450)	$ (71,530)	$ 3,022	$ (41,494)	$ (46,870)	$ 17,062	$ (245,928)	$ (68,280)	$ 155,435
Basic
Net income (loss) attributable to shareholders	$ (0.94)	$ (0.48)	$ (2.04)	$ (1.72)	$ 0.08	$ (1.04)	$ (1.17)	$ 0.47	$ (5.01)	$ (1.74)	$ 4.34
Diluted
Net income (loss) attributable to shareholders	$ (0.94)	$ (0.48)	$ (2.04)	$ (1.72)	$ 0.07	$ (1.04)	$ (1.17)	$ 0.46	$ (5.01)	$ (1.74)	$ 4.24

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SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
allowance for uncollectible notes [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1		$ 0
Charged to Cost and Expense		44,038
Deductions	[1]	0
Ending Balance, December 31		44,038	$ 0
Allowance for Doubtful Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1		2,009	486	$ 896
Charged to Cost and Expense		1,309	1,700	78
Deductions	[1]	1,128	177	488
Ending Balance, December 31		2,190	2,009	486
Valuation Allowance for Unproved Natural Gas and Crude Oil Properties [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Beginning Balance, January 1		144	9,293	5,142
Charged to Cost and Expense		215	7,012	4,465
Deductions	[1]	0	16,161	314
Ending Balance, December 31		$ 359	$ 144	$ 9,293

[1] For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.