Attached files

file filename
EX-99.1 - REPORT OF INDEPENDENT PETROLEUM CONSULTANTS - RYDER SCOTTCOMPANY, L.P. - PDC ENERGY, INC.a2015_10kxexx991.htm
EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS LLP. - PDC ENERGY, INC.a2015_10kxexx231.htm
EX-23.2 - CONSENT OF RYDER SCOTT COMPANY, L.P., PETROLEUM CONSULTANTS. - PDC ENERGY, INC.a2015_10kxexx232.htm
EX-31.1 - 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - PDC ENERGY, INC.a2015_10kxexx311.htm
EX-12.1 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES. - PDC ENERGY, INC.a2015_10kxexx121.htm
EX-32.1 - 906 CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - PDC ENERGY, INC.a2015_10kxexx321.htm
EX-10.11.1 - FIRST AND SECOND AMENDMENTS TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT - PDC ENERGY, INC.a2015_10kxexx10111.htm
EX-21.1 - SUBSIDIARIES - PDC ENERGY, INC.a2015_10kxexx211.htm
EX-10.5 - AMENDED AND RESTATED 2010 LONG-TERM EQUITY COMPENSATION PLAN,AS AMENDED - PDC ENERGY, INC.a2015_10kxexx105.htm
EX-10.6 - EXECUTIVE SEVERANCE COMPENSATION PLAN, AS AMENDED. - PDC ENERGY, INC.a2015_10kxexx106.htm
EX-31.2 - 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - PDC ENERGY, INC.a2015_10kxexx312.htm
EX-10.7.8 - FORM OF 2016 PERFORMANCE SHARE AGREEMENT - PDC ENERGY, INC.a2015_10kxexx1078.htm


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, 2015

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, 2015 was $2.1 billion (based on the closing price of $53.64 per share as of the last business day of the fiscal quarter ending June 30, 2015).

As of February 1, 2016, there were 40,269,891 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 2016 Annual Meeting of Stockholders.




PDC ENERGY, INC.
2015 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

 
PART I
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART IV
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





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 affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture owned 50% each by PDC and Lime Rock Partners, LP until its sale in October 2014. Unless the context otherwise requires, references in this report to "Appalachian Basin" refers to our operations in the Utica Shale in Ohio and Marcellus Shale in West Virginia and Pennsylvania, including PDC's proportionate share of our affiliated partnerships' and PDCM's assets, results of operations, cash flows and operating activities. See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries and Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for a discussion of the sale of our interest in PDCM. 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 and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated future production (including the components of such production), sales, expenses, cash flows, liquidity and balance sheet attributes; estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves; the impact of prolonged depressed commodity prices including potentially reduced production and associated cash flow; anticipated 2016 capital projects, expenditures and opportunities, including our expectation that 2016 cash flows from operations will approximate cash flows from investing activities; expected 2016 capital budget allocations; our operational flexibility and ability to revise our 2016 development plan; availability of sufficient funding and liquidity for our 2016 capital program and sources of that funding; expected losses of Riley Natural Gas ("RNG") through 2022 and expected discontinuation of RNG's business; future exploration, drilling and development activities, including non-operated activity, the number of drilling rigs we expect to run during 2016, number of locations and lateral lengths; opportunity in the Utica Shale to add reserves in a more favorable price environment; capital efficiencies and per well reserves expected to be realized; expected 2016 production and cash flow ranges; our evaluation method of our customers' and derivative counterparties' credit risk; effectiveness of our derivative program in providing a degree of price stability; future horizontal drilling locations that are economically producible at certain commodity prices and costs; potential for future impairments; potential acquisitions of additional acreage and other future transactions; electronic, cyber or physical security breaches; the impact of high line pressures and the timing, availability, cost and effect of additional midstream facilities and services going forward; compliance with debt and senior notes covenants; expected funding sources for conversion of our 3.25% convertible senior notes due 2016; compliance with government regulations; impact of the Colorado task force on oil and gas regulation and potential future ballot initiatives and legislation; the level of our borrowing base under our credit facility; impact of litigation on our results of operations and financial position; the adequacy of existing insurance to cover operating hazards and the availability of such insurance on a cost effective basis in the future; that we hold good and defensible title to our leasehold; that we do not expect to pay dividends in the foreseeable future; and our future strategies, plans and objectives.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. 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 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;

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inaccuracy of reserve estimates and expected production rates;
potential for production decline rates from our wells being greater than expected;
timing and extent of our success in discovering, acquiring, developing and producing reserves;
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of crude oil and natural gas wells;
future cash flows, liquidity and financial condition;
competition within the oil and gas industry;
availability and cost of capital;
our success in marketing crude oil, natural gas and NGLs;
effect of crude oil and natural gas derivatives activities;
impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;
cost of pending or future litigation;
effect that acquisitions we may pursue have on our capital expenditures;
our ability to retain or attract senior management and key technical employees; and
success of strategic plans, expectations and objectives for our future operations.
 
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under 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 produces, develops, acquires and explores for crude oil, natural gas and NGLs with operations in the Wattenberg Field in Colorado and the Utica Shale in southeastern Ohio. Our 2016 drilling and completion operations in the Wattenberg Field are expected to focus on the middle core area of the Niobrara and Codell plays. As of December 31, 2015, we own an interest in approximately 3,000 gross producing wells, of which approximately 650 are horizontal. Production of 15.4 MMboe for the year ended December 31, 2015 represents an increase of 65% compared to the year ended December 31, 2014. For the month ended December 31, 2015, we maintained an average production rate of 52 MBoe per day. We were able to achieve this strong growth rate while maintaining a liquidity position of $402.2 million as of December 31, 2015 and a debt to EBITDAX ratio, as defined in our revolving credit facility agreement, of 1.4 times. As of December 31, 2015, we had approximately 273 MMBoe of proved reserves (26% of which are proved developed). Proved reserves at December 31, 2015 were comprised of approximately 60% liquids and 40% natural gas, and represent an increase of 23 MMBoe relative to December 31, 2014. Our proved reserve additions were primarily a result of the increased well density of proved undeveloped locations in the middle core area of the Niobrara formation in the Wattenberg Field, which allowed for the optimization of our five-year development plan. While the significant decrease in SEC commodity prices utilized in the 2015 year-end reserve report had a minimal impact on our quantities of proved reserves, this decrease in pricing resulted in a 61% decline in the pre-tax present value of future net revenues (“PV-10”) relative to December 31, 2014. PV-10 is not a financial measure under accounting principles generally accepted in the United States of America (“U.S. GAAP”). 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 our standardized measure.

Our Strengths

Multi-year project inventory in premier crude oil, natural gas and NGLs plays. We have a significant operational presence in the Wattenberg Field, a key U.S. onshore basin, and have identified a substantial inventory of 791 gross proved undeveloped horizontal drilling locations and approximately 1,400 probable horizontal drilling locations in this play. These location counts are based on wells expected to be drilled with an average lateral length of approximately 4,700 feet. Further, with our leaseholds in Ohio, we have the ability to pursue developmental drilling in the emerging Utica Shale play and are focusing our development in the condensate and wet natural gas window of the play. We believe that this inventory will allow us to continue to grow our reserves and production, and that, with respect to the Wattenberg Field in particular, the majority of our projects will generate attractive rates of return at current commodity price projections and our current projected cost structure.


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Strong liquidity position. As of December 31, 2015, we had a total liquidity position of $402.2 million, comprised of $0.9 million of cash and cash equivalents and $401.3 million available for borrowing under our revolving credit facility. We had $37.0 million outstanding on our revolving credit facility as of December 31, 2015. Our liquidity position will be reduced by $115 million upon the maturity of our 3.25% convertible senior notes in May 2016. Pursuant to the related indenture, we will settle the principal amount of the notes in cash and issue common stock for the excess conversion value upon maturity. In September 2015, we completed the semi-annual redetermination of the borrowing base under our revolving credit facility, which resulted in the reaffirmation of the borrowing base at $700 million. We elected to maintain the aggregate commitment at $450 million. Considering the additional $250 million borrowing base available under our revolving credit facility, subject to certain terms and conditions of the agreement, our liquidity position as of December 31, 2015 could have been $652.2 million.

Significant control in our core areas. Our operational control is enhanced by the fact that substantially all of our Wattenberg Field leasehold position is held-by-production. We remain flexible in terms of rig activity and capital deployment due to short-term rig contracts and held-by-production acreage. As a result, we can adjust our drilling plans if commodity prices deteriorate further in order to balance cash flows from operations and cash flows from investing activities, which primarily consist of our capital expenditures. 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. Additionally, as a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately 87% of the wells in which we have an interest. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas.

2016 derivative program. We have hedged a portion of our short-term future exposure to commodity price fluctuations by entering into crude oil and natural gas collars, fixed-price swaps and basis protection swaps. While our derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect our cash flows, borrowing base and liquidity during periods of depressed commodity prices. As of December 31, 2015, we had hedge positions covering approximately 4,140 MBbls of 2016 crude oil production, or approximately 45% to 50% of our expected crude oil production for the year. These hedges were at a weighted-average minimum price of $77.26 per Bbl and a weighted-average maximum price of $86.88 per Bbl. As of the same date, we had hedged approximately 29.8 Bcf, or approximately 59% to 65%, of our expected natural gas production in 2016, at a weighted-average minimum price of $3.62 per Mcf and a weighted-average maximum price of $3.72 per Mcf. As of December 31, 2015, we had hedged a much lower percentage of our expected production for the next 12 to 24 months than we have hedged historically.

Technology focused team. We have a proven track record of continuing improvement in both costs and productivity of our well operations. Recently, our teams have focused on transitioning to multi-well pad drilling, extended laterals, increased frac stage density, enhanced frac design and drilling efficiencies. In 2015, we introduced tighter frac stage density and, in 40% of our spuds, extended reach laterals that are 6,500 to 7,000 feet in length. We also began testing plug-and-perf completions along with diverting agents that have provided an uplift to our new well production. We have completed wells at various densities ranging from 16 wells per section equivalent to 26 wells per section equivalent, providing added information on the reserves that can potentially be recovered. Finally, our drilling team has made great strides in reducing drill times for one mile laterals from an average of approximately 14 days to seven days spud-to-spud over the year.

Track record of reserve and production growth. Our proved reserves have grown from 50 MMBoe at December 31, 2010, after adjusting for subsequent divestitures, to approximately 273 MMBoe at December 31, 2015, representing a compound annual growth rate (“CAGR”) of 40%. During the same time period, our proved crude oil and NGL reserves grew at a CAGR of 42%. Our annual production from continuing operations grew from 3.3 MMBoe in 2010 to 15.4 MMBoe in 2015, representing a CAGR of 36%. Future development of the Wattenberg Field provides the opportunity to add further proved, probable and possible reserves to our portfolio. Similarly, we believe the Utica Shale provides the opportunity for additional proved, probable and possible reserves in a more favorable crude oil and natural gas pricing environment. As a result of data generated from our downspacing testing in the Wattenberg Field, Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm, has increased the density of our proven undeveloped locations, year-over-year, in the Niobrara formation. In general, at December 31, 2013, Niobrara PUD locations were booked at an equivalent density of six wells per section, at December 31, 2014, Niobrara PUD locations were booked at an equivalent density of eight wells per section and at December 31, 2015, Niobrara PUD locations are booked at the equivalent density of 16 wells per section.

Strong environmental health and safety compliance programs. We have focused on establishing effective environmental health and safety programs that are able to earn trust and respect from 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, and in working with the local communities in which we operate.

Community participation and outreach. We are 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. We also encourage our employees to take an active role through our charitable matching contribution fund and by participating in our “Energizing Our Community” day, during which our employees volunteer in the communities in which they work and live.


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Business Strategy

Our long-term business strategy focuses on generating shareholder value through the development, acquisition and exploration of crude oil and natural gas properties. We are currently focused on the organic growth of our reserves, production and cash flows in our horizontal drilling programs after having completed multiple transactions in recent years to restructure and simplify our property portfolio. We pursue various midstream, marketing and cost reduction initiatives designed to increase our per unit operating margins while maintaining a conservative and 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 the current commodity price environment. Our current inventory of drilling locations supports our planned organic growth over the next several years. We expect it to drive increases in reserves, production and cash flows. In addition to development drilling, we routinely review acquisition and acreage swap opportunities in our core areas of operation as we believe we can extract additional value from such assets through production optimization and increasing our working interest in our development drilling locations. As a result, these types of core acquisitions and acreage swaps can potentially provide synergies that result in economies of scale. We also pursue a limited, but 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.

Development drilling
 
The following map presents the general locations of our development and production activities as of December 31, 2015:
 
Our leasehold interests consist of developed and undeveloped crude oil, natural gas and NGLs resources. Based upon well cost savings resulting from the continued deterioration of commodity prices, our current 2016 capital forecast is a range between $420 million and $450 million. We have allocated over 90% of our 2016 capital forecast to our higher-return projects in the Wattenberg Field, primarily in the middle core area. We may decrease our 2016 capital forecast during the year as a result of, among other things, a further decline in commodity prices, a reduction of our current internal outlook for commodity prices, drilling results, unfavorable changes in our borrowing capacity and/or a significant decline in cash flows.
 
Wattenberg Field. Our primary focus in the Wattenberg Field is drilling in the horizontal Niobrara and Codell plays. Based on our current drilling program, we have an inventory of 791 gross proved undeveloped horizontal drilling locations and approximately 1,400 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 2016, we expect to continue to realize additional capital efficiencies through drilling extended length laterals, use of a diverting agent with plug-and-perf completions, 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 2016, the majority of which will be in the middle core area of the field. In 2016, we plan to spud 135 and turn-in-line approximately 160 horizontal Niobrara or Codell 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
 
11
 
14
Estimated percentage of 2016 wells spud
 
36%
 
34%
 
30%
Estimated percentage of 2016 wells turned-in-line
 
50%
 
40%
 
10%
Estimated cost per well (in millions)(1)
 
$2.6
 
$3.6
 
$4.6
___________
(1) Estimated well costs include plug-and-perf technology.

The 2016 capital forecast anticipates a four-rig drilling program in the Wattenberg Field based on our current commodity price outlook. Approximately $400 million of our 2016 capital forecast is expected to be spent on development activities in the Wattenberg Field, comprised of approximately $350 million for our operated drilling program and approximately $35 million for non-operated projects. The remainder of the Wattenberg Field capital forecast is expected to be used for leasing, workover projects and other capital improvements, including the remodeling of our new field office in Greeley, Colorado. We expect to participate in approximately 35 gross, 7.0 net, non-operated horizontal opportunities in 2016.
 
Utica Shale. Our operations in the Utica Shale are currently less significant, and include horizontal drilling locations in the condensate and wet natural gas window of the play. In early 2015, based upon low commodity prices and large natural gas price differentials in Appalachia, we elected to temporarily cease drilling in the Utica Shale and limited our activity to completing and turning-in-line a four-well pad that was in process as of December 31, 2014. Due to a further significant decline in commodity prices and a decrease in net-back realizations, in the third quarter of 2015 we recorded an impairment charge of $150.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties. Based on the production results from our most recently drilled wells and the significant decrease in well costs, in 2016 we plan on executing a modest drilling operation in the condensate and wet natural gas window of the play. Early in 2016, we plan to spend approximately $35 million in the Utica Shale to drill, complete and turn-in-line five wells, all of which will have laterals of at least 6,000 feet. The planned activity will focus on further delineation of our southern acreage, determining the impact of well-orientation on productivity and testing improved capital efficiency of a 10,000 foot lateral length well.

While we expect to outspend our cash flows from operations during the first half of 2016, we believe that our cash flows from operations will exceed our cash flows from investing activities, which primarily consist of our capital expenditures, in the second half of 2016. As a result, we expect our overall 2016 cash flows from operations to approximate our cash flows from investing activities. However, a further deterioration of commodity prices could negatively impact our results of operations, financial condition and future development plans. We may decrease our 2016 capital forecast during the year as a result of, among other things, a further decline in commodity prices, drilling results, unfavorable changes in our borrowing capacity and/or a significant decline in cash flows. If commodity pricing falls short of our internal expectations, we would likely look to reduce our capital investment in the second quarter of 2016 to maintain our goal of capital expenditures approximating operational cash flows. We may change our capital expenditure plans from time to time for other reasons as well, including as a result of regulatory issues, drilling results or acquisition or divestiture opportunities. Our liquidity position will be reduced by the cash payment of approximately $115 million upon the maturity of our 3.25% convertible senior notes in May 2016. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - 2016 Operational Flexibility, for additional information.

Operational and financial risk management

We proactively employ strategies to help reduce the financial risks associated with our industry. One such strategy is to utilize commodity-based derivative instruments to manage a portion of our short-term exposure to price volatility with regard to our crude oil and natural gas sales and natural gas marketing segments. As of December 31, 2015, we had natural gas and crude oil derivative positions in place for 2016 covering approximately 4,140 MBbls of our crude oil production and approximately 29.8 Bcf of our natural gas production and for 2017 covering approximately 1,440 MBbls of our crude oil production and approximately 32.5 Bcf of our natural gas production. Currently, we do not hedge our NGL production.

Strategic acquisitions

We examine and evaluate acquisition opportunities as they present themselves and pursue those that meet our strategic plan and that we believe would increase shareholder value. We typically pursue the acquisition of assets with high quality undeveloped drilling locations, producing wells and/or behind-pipe reserves. We seek properties with large undeveloped drilling upside where we believe we can utilize our operational abilities to add shareholder value. In addition, we may pursue opportunities to swap acreage with other producers in order to optimize our portfolio by consolidating and concentrating our core assets. The large contiguous acreage blocks created through swapping of acreage provide the opportunity to optimize drilling activities and add more extended-reach lateral wells to our drilling program. We have an experienced team of management, engineering, geosciences and commercial professionals who identify and evaluate acquisition opportunities.

Selective exploration
 
In the current commodity pricing environment, we do not expect our exploration activity to be significant in 2016. Historically, we have pursued a disciplined exploration program intended to replenish our portfolio and to position us for production and reserve growth in future

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years. We have attempted 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 in the proximity of existing or emerging midstream infrastructure.

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

Our Oil and Gas Exploration and Production segment primarily reflects 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 to proved reserves 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 drilling of oil and gas wells, which are drilled, completed and put into production. Subsequent to completion, we operate and maintain the wells while controlling associated production costs. Upon extraction of the estimated recoverable reserves from a well, it is plugged and surface disturbance surrounding the well and producing facilities is remediated. In some cases, we may also own a working interest in wells operated by unrelated third-parties. The Oil and Gas Exploration and Production segment's most significant customers are currently Suncor Energy Marketing, Inc., Concord Energy, LLC, DCP Midstream, LP and Shell Trading Company. Sales to each of these parties constitute more than 10% of our revenues.

Our crude oil, natural gas and NGLs production is gathered, marketed and sold as follows:

Crude oil. We do not refine any of our crude oil production. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on NYMEX pricing, adjusted for differentials. We have entered into longer term commitments ranging from three months to one year to deliver crude oil to competitive markets and these agreements have resulted in significantly improved deductions compared to earlier in 2015. 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 of production. We began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline in July 2015. This is one of several agreements we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability and reducing the overall physical footprint of our well pads. We began delivering crude oil into this pipeline during the fourth quarter of 2015 and expect the system to be fully operational in the first quarter of 2016. 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.

Natural gas. We primarily sell our natural gas to midstream service providers, marketers and utilities. Our natural gas is transported through third-party gathering systems and pipelines and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. We generally sell the natural gas that we produce in the Wattenberg Field under contracts with indexed, NYMEX or CIG monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions whereby prices change with the market, with certain adjustments that may be made based on whether a well delivers to a gathering or transmission line and the quality of the natural gas. We have entered into firm gathering and processing agreements for all of our gas production to ensure there is infrastructure available to process the gas and get it to market. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP Midstream, LP, which gathers and processes wet natural gas produced in the basin and sells our residue gas to various markets. In the fourth quarter of 2014, we entered into an agreement with AKA Energy Group ("AKA") whereby we have committed production from a specified number of new horizontal wells to be drilled and completed by the end of 2016. Pursuant to the agreement, AKA is required to install and operate, or contract for use of, facilities necessary to receive and purchase the production volumes committed under the agreement. In the Utica Shale, wet natural gas produced in our northern acreage is gathered and processed pursuant to a firm gathering and processing agreement with MarkWest Utica EMG ("MarkWest") while wet natural gas produced in our southern acreage is gathered and processed by Blue Racer Midstream LLC ("Blue Racer"). The natural gas sales from the Blue Racer Plant are based on TETCO M-2 pricing. The gas sold at the tailgate of the MarkWest plant is sold at a price relative to the Chicago/Midwest market. Our sale of a significant portion of our Utica Shale gas to the Midwest market has helped to reduce the impact of the significant differentials that exist between the TETCO M-2 realizations and the NYMEX gas price. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas, which make economics challenging, will continue well into 2016.

NGLs. In the Wattenberg Field, all of our NGLs are sold at the tailgate of the third-party midstream service provider processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. 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 under both short- and long-term contracts. Due to an oversupply and growing inventories of nearly all domestic NGLs products, our realized sales price for NGLs declined significantly during 2015 and, while these prices have stabilized, we expect pricing to remain at depressed levels well into 2016 and perhaps beyond.
    

6



Gas Marketing

Our Gas Marketing segment is comprised solely of the operating activities of our wholly-owned subsidiary RNG. RNG specializes in the purchase, aggregation and sale of natural gas production in the Appalachian Basin. Financial results from our gas marketing segment were not material to our consolidated financial statements for any of the periods presented in this report and we do not expect them to be material in the future. RNG purchases for resale natural gas produced by third-party producers. 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. As of December 31, 2015, the dollar commitment related to this long-term firm transportation, sales and processing agreement was approximately $20.6 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 continue to remain depressed, certain third-party producers under our Gas Marketing segment have begun and may continue to experience financial distress, which has led to certain contractual defaults and litigation. To date, we have had no material counterparty default losses; however, we expect continued deterioration in the financial position of some counterparties. In 2015, we recorded an allowance for doubtful accounts of approximately $0.5 million. We have initiated several legal actions for collection against some of the third-party producers, which have resulted in no collections and some of the third-party producers shutting-in wells. As a result, 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. Following the sale of our 50% ownership interest in PDCM in October 2014, RNG's marketing activities were scaled down and are focused on selling natural gas production to meet its volume commitments. After the long-term firm transportation agreements expire, we expect to discontinue this segment.

For additional information regarding our business segments, see Note 17, 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, 2015
 
 
Crude Oil
 
Natural Gas
 
Total
Operating Region/Area
 
 Gross
 
 Net
 
Gross
 
 Net 
 
 Gross
 
 Net
Wattenberg Field
 
625

 
380.9

 
2,329

 
2,102.9

 
2,954

 
2,483.8

Utica Shale
 
25

 
19.9

 
3

 
3.0

 
28

 
22.9

 
 
 
 
 
 
 
 
 
 
 
 
 
Total productive wells
 
650

 
400.8

 
2,332

 
2,105.9

 
2,982

 
2,506.7


Proved Reserves

The following table presents our proved reserve estimates as of December 31, 2015 based on a reserve report prepared by Ryder Scott and related information:

 
Proved Reserves at December 31, 2015
 
 
 
 
 
 
 
Proved Reserves (MMBoe)
 
% of Total Proved Reserves
 
% Proved Developed
 
% Liquids
 
Proved Reserves to Production Ratio (in years)
 
2015 Production (MBoe)
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
270
 
99
%
 
25
%
 
60
%
 
18.9
 
14,232

Utica Shale
3
 
1
%
 
100
%
 
55
%
 
2.8
 
1,138

Total proved reserves
273
 
100
%
 
26
%
 
60
%
 
17.8
 
15,370


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. 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, 2015, all of our proved reserves, including our proportionate share of our affiliated partnerships' reserves, have been estimated by Ryder Scott.

7




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 and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data, and production performance data. The process includes a review of applicable working and net revenue interests and cost and performance data. The internal team compiles the reviewed data and forwards the data to Ryder Scott.

When preparing our reserve estimates, Ryder Scott did not independently verify 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 prepares an estimate 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 report is reviewed by our engineering staff and management prior to issuance by Ryder Scott.
 
The professional qualifications of the internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates qualify the engineer as a Reserves Estimator, 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. This person holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 39 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 actual production from projects in the same reservoir or an analogous reservoir or by other 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 2015 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.

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 unaudited Supplemental Information - Crude Oil and Natural Gas Information 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,
 
2015
 
2014
 
2013 (3)
Proved reserves
 
 
 
 
 
Crude oil and condensate (MMBbls)
99

 
101

 
94

Natural gas (Bcf)
661

 
537

 
740

NGLs (MMBbls)
64

 
60

 
49

Total proved reserves (MMBoe)
273

 
250

 
266

Proved developed reserves (MMBoe)
70

 
75

 
76

Estimated future net cash flows (in millions) (1)
$
2,259

 
$
4,938

 
$
4,323

PV-10 (in millions) (2)
$
1,338

 
$
3,450

 
$
2,704

Standardized measure (in millions)
$
1,097

 
$
2,306

 
$
1,782

___________
(1)
Amount represents undiscounted pre-tax future net cash flows estimated by Ryder Scott of approximately $2.8 billion, $7.3 billion and $6.4 billion as of December 31, 2015, 2014 and 2013, respectively, less an internally-estimated future income tax expense of approximately $0.5 billion, $2.3 billion and $2.1 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.

(3)
Includes estimated reserve data related to our Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of these assets.

The following table sets forth information regarding estimated proved reserves for our Marcellus Shale crude oil and natural gas properties:


8



 
December 31, 2013
Proved reserves
 
Natural gas (Bcf)
237

Total proved reserves (MMBoe)
40

Proved developed reserves (MMBoe)
9

Estimated future net cash flows (in millions)
$
394


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

 
 
As of December 31, 2015
Operating Region/Area
 
Crude Oil and Condensate (MBbls)
 
Natural Gas
(MMcf)
 
NGLs
(MBbls)
 
Crude Oil
Equivalent
(MBoe)
 
Percent
Proved developed
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
25,240

 
166,679

 
14,284

 
67,304

 
95
%
Utica Shale
 
1,017

 
8,688

 
727

 
3,192

 
5
%
Total proved developed
 
26,257

 
175,367

 
15,011

 
70,496

 
100
%
Proved undeveloped
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
72,718

 
485,370

 
48,716

 
202,329

 
100
%
Utica Shale
 

 

 

 

 
%
Total proved undeveloped
 
72,718

 
485,370

 
48,716

 
202,329

 
100
%
Proved reserves
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
97,958

 
652,049

 
63,000

 
269,633

 
99
%
Utica Shale
 
1,017

 
8,688

 
727

 
3,192

 
1
%
Total proved reserves
 
98,975

 
660,737

 
63,727

 
272,825

 
100
%
 
 
 
 
 
 
 
 
 
 
 

We have stress-tested our proved reserve estimates as of December 31, 2015 to determine the impact of lower crude oil prices. Replacing the 2015 NYMEX commodity prices used in estimating our reported proved reserves (see Supplemental Information - Crude Oil and Natural Gas Information, provided with our consolidated financial statements included elsewhere in this report) with those shown on the table below, and leaving all other parameters unchanged, results in a decrease in 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, 2015 Estimated Reserves
2015 Reserve Report (2)
$
50.28

 
$
2.59

 
272.8

 

Scenario A
40.00

 
2.59

 
266.1

 
(2
)%
Scenario B
30.00

 
2.59

 
256.5

 
(6
)%
__________
(1)
These prices are indices and do not include basin differentials for crude oil and natural gas. The above scenarios were calculated using the indicated index prices, less any basin differentials, transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity.
(2)
The NYMEX prices used for the 2015 Reserve Report are based on SEC price parameters using the unweighted average of the prices in effect on the first day of the month for each month within the period of January 2015 through December 2015.


9



Developed and Undeveloped Acreage

The following table presents our developed and undeveloped lease acreage:
 
 
As of December 31, 2015
 
 
Developed
 
Undeveloped
 
Total
Operating Region/Area
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wattenberg Field
 
97,600

 
89,400

 
7,600

 
6,300

 
105,200

 
95,700

Utica Shale
 
3,166

 
2,670

 
66,132

 
62,044

 
69,298

 
64,714

 Total acreage
 
100,766

 
92,070

 
73,732

 
68,344

 
174,498

 
160,414

 
 
 
 
 
 
 
 
 
 
 
 
 

Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held-by-production. Approximately 8%, 21% and 7% of our undeveloped leaseholds in the Utica Shale are scheduled to expire during 2016, 2017 and 2018, respectively. While the undeveloped leaseholds expiring in 2016 in the Utica Shale are not significant, we believe that our planned modest investment in the Utica Shale in 2016 will provide production, reservoir and completion analyses that will provide us with a better understanding of our Utica Shale acreage as we exit 2016 and may influence our re-leasing decisions as more undeveloped leaseholds expire in 2017. In the event these leaseholds are not renewed, we do not expect a significant charge as the carrying value of our Utica Shale acreage as of December 31, 2015 is not material as a result of impairments recorded in 2014 and 2015.

Drilling Activity
    
The following table presents information regarding the number of wells drilled or participated in for the period presented. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.

 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
Operating Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wattenberg Field, operated wells
 
140

 
113.5

 
88

 
71.0

 
62

 
53.3

Wattenberg Field, non-operated wells
 
58

 
9.3

 
70

 
14.9

 
35

 
7.9

Utica Shale
 
4

 
3.0

 
9

 
8.0

 
11

 
8.7

Other (1)
 

 

 
4

 
2.0

 
10

 
5.0

Total wells drilled
 
202

 
125.8

 
171

 
95.9

 
118

 
74.9

__________
(1)
Includes drilling activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.

The following tables set forth 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 spud, turned-in-line and producing during the period. 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.
 
 
 
Net Development Well Drilling Activity
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
Operating Region/Area
 
Productive
 
In-Process
 
Dry (1)
 
Productive
 
In-Process
 
Dry (1)
 
Productive
 
In-Process
 
Dry
Wattenberg Field, operated wells
 
110.8
 
50.6
 
2.7
 
75.8

 
36.5

 
1.7

 
40.5

 

 

Wattenberg Field, non-operated wells
 
9.3
 
4.6
 
 
14.9

 
6.3

 

 
13.0

 
15.6

 
0.1

Utica Shale
 
3.0
 
4.2
 
 
7.0

 
3.0

 
1.0

 
3.0

 
2.0

 

Other (2)
 
 
 
 
2.0

 

 

 
3.5

 
2.0

 

Total net development wells
 
123.1
 
59.4
 
2.7
 
99.7

 
45.8

 
2.7

 
60.0

 
19.6

 
0.1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(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.


10



We had no exploratory well drilling activity in 2015 and 2014. The following table presents our net exploratory well drilling activity in 2013:

 
 
Net Exploratory Well Drilling Activity
 
 
December 31, 2013
Operating Region/Area
 
Productive
 
In-Process
 
Dry
Utica Shale
 
4.2

 

 

Other (1)
 
1.5

 

 

Total net exploratory wells
 
5.7

 

 

__________
(1)
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 with respect to discovered defects which we deem to be significant. 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 Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report.

Facilities

We lease 56,000 square feet of office space in Denver, Colorado, which serves as our corporate office, through February 2021. We own a 32,000 square foot administrative office building located in Bridgeport, West Virginia and a newly acquired 60,000 square foot field operating facility in Greeley, Colorado.

We own or lease field operating facilities in Evans, Colorado 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 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;

11



surface use and restoration of well properties;
well plugging and abandoning;
fluid disposal; and
air emissions.

In 2014, Colorado Governor Hickenlooper created a task force charged with crafting recommendations to help minimize land use conflicts relating to the location of oil and gas facilities. The task force was created pursuant to a compromise under which certain potential ballot initiatives that would have impacted the oil and natural gas industry in Colorado were withdrawn from the November 2014 ballot. The task force, which was called the Task Force on State and Local Regulation of Oil and Gas Operations, was comprised of 21 members representing various interests. Recommendations of the task force regarding new or amended legislation, appropriations or other action were submitted to the Governor in February 2015. In 2015 and into 2016, the Colorado Oil and Gas Conservation Commission (the “COGCC”) conducted a rulemaking to implement two of these task force recommendations related to the permitting of large-scale facilities in urban mitigation areas and municipality notice provisions. Both rulemakings were finalized in January 2016 and new rules will become effective in spring 2016. In addition, depending on the outcome of the task force process and any related legislative or administrative activity, ballot initiatives, like those proposed in December 2015 and again in January 2016, affecting our operations may be proposed and adopted by the voters in future elections.

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% of the leases located within the proposed unit. State laws may establish maximum rates of production from crude oil and natural gas wells, 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. 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.


12



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.

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 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 continues its study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and issued a draft assessment in June 2015, with a final, peer-reviewed report expected in 2016. 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 and Ohio, have adopted regulations regarding permitting, transparency and well construction requirements with respect to hydraulic fracturing operations and may in the future adopt additional regulations or otherwise seek to ban fracturing activities altogether. Colorado requires 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 COGCC issued new, more restrictive rules regarding spill reporting and remediation. See further discussion in Item 1A, Risk Factors.

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, which are anticipated to be effective in March 2016, 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 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 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.


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In October 2015, the ODNR proposed draft regulations pertaining to incident notification. These rules are not yet final and we do not have an anticipated effective date. Additionally, in November 2015, the ODNR Assistant Chief announced draft rules in progress include 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, local governing bodies have begun to issue 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 cities of Boulder, Lafayette, Fort Collins and Brighton passed hydraulic fracturing bans. See Item 1A, Risk Factors, for a more detailed discussion of these bans. 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) or remediate property contamination (including surface and groundwater contamination) or to 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 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 the development of regulations to implement these requirements. We may be required to incur certain capital expenditures 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 ("NSPS OOOO") became effective in 2012, with more amendments effective in 2013 and 2014, all of which have added administrative and operational costs. In addition, as part of its comprehensive strategy to further reduce methane emissions from the oil and gas sector, EPA proposed amendments to NSPS OOOO in 2015 that would impose additional control and other requirements to reduce such emissions. A final rule is expected in the summer of 2016. 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 more stringent than NSPS OOOO 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 strengthened 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 and Ohio. By October 2016, states are expected to have revised state implementation plans and proposed regulations to meet the new standard.

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 loadout 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 defining the scope of jurisdictional Waters of the U.S. This final rule has been stayed pending the resolution of ongoing litigation.


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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 May 2014 proposed a rule to alter how it identifies critical habitat for endangered and threatened species. It is unclear when this rule will be finalized.

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. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including us, to procure and implement additional SPCC measures relating to the possible discharge of crude oil into surface waters. 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 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 2016 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 Note 12, 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 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 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 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. 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

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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, 2015, we had 362 full-time employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be good.

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, shareholder 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 continuing 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 fallen dramatically since mid-2014, with a high over $100 per barrel in June 2014 to recent lows below $30 per barrel, in each case based on WTI prices, due to a combination of factors including increased U.S. supply, global economic concerns, the likely resumption of oil exports from Iran and OPEC’s decision not to reduce supply. Prices for natural gas and NGLs have experienced declines of similar magnitude. These declines have adversely affected, among other things, our revenue and reserves, and has caused us to reduce our company-wide budgeted 2016 capital program relative to 2015 and 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. An extended period of continued lower oil prices, or additional price declines, will have further adverse effects on us. For example, if we reduce our capital expenditures further 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.
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.

Our operations are focused primarily on the Wattenberg Field, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Approximately $400 million, or 91%, of our 2016 capital forecast is expected to be spent on development activities in the Wattenberg Field. Because our operations are 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 the area 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 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, 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.

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 Safe Drinking Water Act (“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 concludes 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. EPA’s science advisory board, however, has subsequently questioned several elements and conclusions in EPA’s draft assessment. In addition, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.

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. 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, 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. 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.
 
EPA also finalized major new U.S. Clean Air Act (“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, 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 September 2015 EPA published proposed amendments to the 2012 NSPS Quad OOOO rules focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The proposed rule would include, among others, 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. If finalized, these additional methane reduction requirements could increase future costs of our operations and require us to make modifications to our operations and install new equipment. These CAA rules and associated amendments are substantial and will increase future costs of our operations and will require us to make modifications to our operations and install new equipment.

On the same day EPA proposed amendments to NSPS Quad OOOO, EPA also published a proposed rule regarding source determination and permitting requirements for the onshore oil and gas industry under the CAA. The proposed rule sought public comment on two approaches for defining 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. Depending on EPA’s final approach, the oil and gas industry and our operations could be subject to increased permitting costs and more stringent control requirements.

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 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

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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 January 2016, BLM proposed rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules, which would require additional controls and impose new emissions and other standards on certain operations on applicable leases, are expected to be finalized in 2016. 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. The public comment period for this proposal closed January 8, 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 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. New York has also placed a permanent moratorium on all hydraulic fracturing activities within the state. Similar initiatives could spread to 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 heard oral arguments on December 9, 2015, and a decision is expected in the first half of 2016. If the Colorado Supreme Court determines the bans are valid, such a decision could increase the costs of our operations, impact our profitability, and prevent us from drilling in certain locations. 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.

Ballot initiatives have been proposed in Colorado 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. This could adversely affect the cost, manner, and feasibility of development activities in Colorado or elsewhere, particularly those involving hydraulic fracturing, and significantly affect the value of our assets and our financial results and impede our growth.

Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various options for ballot initiatives aimed at significantly limiting or preventing oil and natural gas development. Signatures for two such proposals were submitted for a vote at the November 2014 election. One proposed to amend the Colorado constitution to establish an “environmental bill of rights” that would have allowed local governments in Colorado the right, without limitation, to prohibit crude oil and natural gas development within their respective jurisdictions. The second proposal would have imposed a statewide mandatory minimum spacing, or setback, between oil and gas wells and occupied structures of 2,000 feet. As part of a compromise negotiated by Governor John Hickenlooper, both initiatives were withdrawn prior to the election and were not voted upon. In December 2015, interest groups filed a package of 11 potential ballot initiatives focused on restricting oil and gas development in Colorado. Among other things, these initiatives, if successful, could require mandatory setbacks, allow local control over drilling, and impose prohibitions on drilling. Additional proposals of this nature may be made in the future, including in other states. Should any such proposal be successful and survive legal challenge, it could have a materially adverse impact on our ability to drill and/or produce crude oil and natural gas in Colorado or elsewhere, and could materially impact our results of operations, production and reserves.


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Moreover, pursuant to the compromise that resulted in the withdrawal of the 2014 ballot proposals, in February 2015, a task force created by the State of Colorado made recommendations for minimizing land use and other conflicts concerning the location of new oil and gas facilities. The task force ultimately approved and sent to Governor Hickenlooper for his review nine proposals. Three of the proposals required further legislative action, while the other six proposals required rulemaking or other regulatory action. The proposals contemplated (i) a senate bill that would postpone expiration of recently adopted regulations regarding air emissions; (ii) tasking the COGCC with crafting new rules related to siting of “large-scale” pads and facilities; (iii) requiring the industry to provide advance information about development plans to local governments; (iv) improving the COGCC’s local government liaison and designee programs; (v) adding 11 full-time staffers to the COGCC to improve inspections and field operations; (vi) bolstering the inspection staff and equipment for monitoring oil and gas facility air emissions and setting up a hotline for citizen health complaints at the Colorado Department of Public Health and Environment; (vii) creating a statewide oil and gas information clearinghouse; (viii) studying ways to ameliorate the impact of oil and gas truck traffic and (ix) creating a compliance-assistance program at the COGCC to help operators comply with the state’s changing rules and ensure consistent enforcement of rules by state inspectors. A number of additional proposals did not receive sufficient task force support to be included with the nine proposals, but may nevertheless result in future legislation or rulemakings. 
 
In 2015 and into 2016, COGCC began a rulemaking to implement two of these recommendations (in particular items (ii) and (iii) identified above). With respect to recommendation (ii) above, the COGCC has finalized rules to permit “large-scale facilities” in “urban mitigation areas.” With respect to recommendation (iii) above, the COGCC finalized rules requiring operators to provide certain municipalities with public notice prior to engaging in operations. Both rules will become effective later in 2016. These rulemakings could impact our ability to develop and operate in certain areas in Colorado. The other seven recommendations, which were ministerial in nature and did not require a separate rulemaking, have been or are being implemented.

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 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. Similar events could occur in the future. We are also dependent on the availability and capacity of crude oil purchasers for our production. For example, reductions in purchases by a local crude oil refinery beginning in late 2013 increased the amount of oil that we had to transport out of the Wattenberg area for sale. This increased our transportation costs and reduced the price we received for the affected production for much of 2014. We expect this situation could occur again in the future. In addition, the use of alternative forms of transportation such as trucks or rail involve risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or railcars. We face similar risks in our Utica operating area. 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. Falling commodity prices have resulted in reduced investment in midstream facilities by some third parties, increasing the risk that sufficient midstream infrastructure will not be available in future periods.
 
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

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information systems and related infrastructure. Nevertheless, a vulnerability in the cyber security 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 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. Well publicized recent cyber-attacks include those directed at the U.S. Government’s Federal Office of Personnel Management, Anthem, Inc. and Sony Pictures, but lower profile attacks are also common.

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.

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 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.

In August 2015, we received a Clean Air Act Section 114 Information Request (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, 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 and will result in a state rulemaking to address the new “moderate” status. This rulemaking may result in more stringent standards or additional control requirements applicable to our operations in Colorado.

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 is expected to be finalized in 2016 and could expand the reach of the ESA.


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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 could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues. In 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 January 2015, the COGCC amended its regulations to implement this new legislation. These legislative and regulatory amendments expand the COGCC’s enforcement authority and tools by, for example, mandating monetary penalties for certain types of violations, requiring a penalty to be assessed for each day of violation, and significantly increasing the maximum daily penalty amount. These changes could significantly increase both the frequency and the amount of future administrative penalties assessed by the COGCC.

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 in the absence of comparable federal regulation is a significant new authority being asserted at the state level and has the potential to adversely affect operations in Colorado as well as in other parts of the country. In 2015, EPA proposed similar “methane” amendments to Subpart OOOO, which if finalized, could impose additional control or other regulatory requirements on our operations. 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 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.

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.

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, Colorado has a relatively arid climate and experiences 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 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 Resource Conservation and Recovery Act. EPA has not yet acted on the petition and it remains pending. Were EPA to begin treating some or all of these wastes as “hazardous” under

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Subtitle C in response to the petition, 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 U.S. Clean Water Act (“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, 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 April 2015, EPA published proposed pretreatment standards for the oil and gas extraction industry. The proposed regulations would address discharges of 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, following the conclusion and finalization of EPA’s study, the agency 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. These water-related concerns are heightened by the potential for flooding events in Colorado such as those that occurred in 2013. For example, during that flood we experienced damage to some of our facilities as well as other operational impediments.

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

Crude oil prices fell dramatically in the second half of 2014, with further declines in 2015 and 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. In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved crude oil and natural gas properties. In 2013, we recognized additional charges of $48.8 million associated with our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties. In December 2014, we recognized a charge of $158.3 million associated with our Utica Shale properties, and we recognized an additional charge of $150.3 million with respect to those properties in the third quarter of 2015. 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 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.

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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 utilize 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 has an even more limited history, particularly in the southern part of the play where most of our acreage is located. 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, 2015, approximately 74% 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 $2.0 billion during the five years ending December 31, 2020. 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. In December 2015, we received a comment letter from the staff of the SEC requesting certain information regarding our PUD disclosures in prior years, and we cannot predict the outcome of the comment process.

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. Because market prices for crude oil at the end of 2015 were significantly lower than the average price for the year determined under SEC rules, the estimated quantity and present values of our reserves presented in this report using SEC pricing are higher than they would be if we had used year-end commodity prices instead.

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% 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 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. As we continue to develop our position in the Wattenberg Field, and as the field in general matures

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as a horizontal drilling play, it will be increasingly important for us to develop or acquire additional drilling opportunities there or elsewhere to replace our reserves as they are developed.
 
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. We reduced our forecasted company-wide capital expenditures in 2016 relative to 2015 in response to significant declines in the market price of crude oil, and we expect to drill fewer wells during the year. 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. If these 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.

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. Recent reductions in drilling and completion costs, which have accompanied lower commodity prices, may not be continued or sustained. If we drill a dry hole or unprofitable well on a current or future prospect, the profitability of our operations will decline and the value of our properties will likely be reduced. These risks are greater in developing areas such as the Utica Shale. 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.

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;

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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. Historically, 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. 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.

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 believe the current market environment for some types of financing, including high-yield notes, to be highly adverse. In addition, 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

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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 indenture 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 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. Significant recent decreases in the price of crude oil are likely 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.

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 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. If our operating performance declines, we may in the future need to seek to obtain 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

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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 2016. 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 87% 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 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 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 derivative contract defaults on its contractual obligations. Based on current commodity prices and our current derivative position, we may receive significant revenues from our derivative positions in 2016, increasing the adverse consequences to us if a derivative counterparty fails to perform. In addition, many of our 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, 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.

In addition, at December 31, 2015, we had hedged a total of 5.6 million barrels of oil volumes and 77,320 BBtu of natural gas hedged for 2016, 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. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and this could negatively impact our results of operations and financial condition.
 
Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our

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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 derivatives as well as the 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% 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.

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.


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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 swaps 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. In the current commodity price environment, 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 swaps 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 swap or exchange. Such an undervaluation would result in the transaction being less favorable to us than we expected.

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.

The administration of U.S. President Barack Obama has proposed to eliminate certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The proposals 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. In addition, the President has recently proposed a $10.25 per barrel tax on oil companies. 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, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). 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

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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, or will be, subject to significant new capital, margin and business conduct 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.

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.

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, 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 EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the U.S. Clean Air Act (“CAA”). In June 2010, 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, EPA recommended options for BACT from the largest sources, which include improved energy efficiency, among others. 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 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 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 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. EPA intends to conduct future rulemaking to make appropriate revisions in light of the court rulings. Depending on what EPA does, 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 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. Following the publication in March 2014 of a series of Methane White Papers addressing suspected methane emissions from the oil and gas sector, EPA proposed new rules in 2015 aimed at further reducing methane emissions from the oil and gas sector, with final rules expected in 2016. These rules, which build on the Methane White Papers, include new regulatory requirements affecting our operations. In addition, a lawsuit has been filed by several northeastern states that would require 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% 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 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.

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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.

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, as discussed above, in August 2015 we received a Clean Air Act Section 114 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.

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. 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.

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 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

On December 21, 2015, we received a comment letter from the staff of the Division of Corporation Finance of the SEC (the "Staff"). The comments from the Staff were issued with respect to its review of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014. We responded to all of the Staff’s comments in a letter we filed with the SEC dated January 29, 2016. Included in our response were the supplemental analyses and information requested by the Staff. On February 18, 2016, we received a follow-up comment letter from the Staff, which we are currently reviewing. As of the date of the filing of this Annual Report on Form 10-K, we are continuing to work with the Staff on our responses and, therefore, these comments remain unresolved.

ITEM 3. LEGAL PROCEEDINGS

Information regarding our legal proceedings can be found in Note 12, Commitments and Contingencies – Litigation, to our consolidated financial statements included elsewhere in this report.

ITEM 4. MINE SAFETY DISCLOSURES
    
Not applicable.


32



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 for each of the periods presented:

 
 
 
High
 
Low
 
 
 
 
January 1 - March 31, 2014
$
64.27

 
$
44.72

April 1 - June 30, 2014
70.44

 
56.88

July 1 - September 30, 2014
63.73

 
49.82

October 1 - December 31, 2014
50.95

 
27.91

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


As of February 1, 2016, we had approximately 650 shareholders 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 and the indenture governing our 7.75% senior notes due 2022 and we presently intend to continue a policy of using retained earnings for expansion of our business. See Note 8, Long-term Debt, to our consolidated financial statements included elsewhere in this report.

The following table presents information about our purchases of our common stock during the three months ended December 31, 2015:

Period
 
Total Number of Shares Purchased (1)
 
Average Price Paid per Share
 
 
 
 
 
October 1 - 31, 2015
 
3,190

 
$
54.76

November 1 - 30, 2015
 
3,598

 
61.19

December 1 - 31, 2015
 
20,178

 
53.78

Total fourth quarter purchases
 
26,966

 
54.89

__________
(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.


33



SHAREHOLDER PERFORMANCE GRAPH

The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2015, 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 235 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2010 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.



34




ITEM 6. SELECTED FINANCIAL DATA



 
Year Ended/As of December 31,

 
2015
 
2014
 
2013
 
2012
 
2011

 
(in millions, except per share data and as noted)
Statement of Operations (From Continuing Operations):
 
 
 
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs sales
 
$
378.7

 
$
471.4

 
$
340.8

 
$
228.0

 
$
216.1

Commodity price risk management gain (loss), net
 
203.2

 
$
310.3

 
(23.9
)
 
29.3

 
39.4

Total revenues
 
595.3

 
856.2

 
392.7

 
307.1

 
323.3

Income (loss) from continuing operations
 
(68.3
)
 
107.3

 
(21.1
)
 
(19.4
)
 
23.2


 
 
 
 
 
 
 
 
 
 
Earnings per share from continuing operations:
 
 
 
 
 
 
 
 
 
 
Basic
 
$
(1.74
)
 
$
3.00

 
$
(0.65
)
 
$
(0.70
)
 
$
0.98

Diluted
 
(1.74
)
 
2.93

 
(0.65
)
 
(0.70
)
 
0.97


 
 
 
 
 
 
 
 
 
 
Statement of Cash Flows:
 
 
 
 
 
 
 
 
 
 
Net cash from:
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
411.1

 
$
236.7

 
$
159.2

 
$
174.7

 
$
166.8

Investing activities
 
(604.3
)
 
(474.1
)
 
(217.1
)
 
(451.9
)
 
(456.4
)
Financing activities
 
178.0

 
60.3

 
248.7

 
271.4

 
243.4

Capital expenditures
 
604.7

 
628.6

 
394.9

 
347.7

 
334.5

Acquisitions of crude oil and natural gas properties
 

 

 
9.7

 
312.2

 
145.9


 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
2,370.5

 
$
2,331.1

 
$
1,991.7

 
$
1,777.9

 
$
1,676.1

Working capital
 
30.7

 
89.5

 
90.0

 
(67.6
)
 
(38.1
)
Total debt, net of unamortized discount and debt issuance costs
 
642.4

 
655.5

 
593.9

 
637.5

 
502.4

Total equity
 
1,287.2

 
1,137.4

 
967.6

 
703.2

 
664.1


 
 
 
 
 
 
 
 
 
 
Pricing and Lease Operating Expenses From Continuing Operations (per Boe):
 
 
 
 
 
 
 
 
 
 
Average sales price (excluding net settlements on derivatives)
 
$
24.64

 
$
50.72

 
$
52.23

 
$
46.85

 
$
49.97

Average lease operating expenses
 
3.71

 
4.56

 
5.18

 
5.54

 
4.95

 
 
 
 
 
 
 
 
 
 
 
Production (MBoe):
 
 
 
 
 
 
 
 
 
 
Production from continuing operations
 
15,369.4

 
9,294.4

 
6,524.7

 
4,866.5

 
4,324.4

Production from discontinued operations
 

 
1,093.0

 
2,032.6

 
3,458.7

 
3,596.3

Total production
 
15,369.4

 
10,387.4

 
8,557.3

 
8,325.2

 
7,920.7

 
 
 
 
 
 
 
 
 
 
 
Total proved reserves (MMBoe) (1)(2)(3)
 
272.8

 
250.1

 
265.8

 
192.8

 
169.3

______________
(1)
Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe, 30 MMBoe and 22 MMBoe as of December 31, 2013, 2012 and 2011, respectively. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets.
(2)
Includes total proved reserves related to our Piceance Basin and North Eastern Colorado ("NECO") assets of 14 MMBoe and 59 MMBoe as of December 31, 2012 and 2011, respectively. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance Basin and NECO assets.
(3)
Includes total proved reserves related to our Permian Basin assets of 11 MMBoe as of December 31, 2011. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian Basin assets.


35




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.

EXECUTIVE SUMMARY

2015 Financial Overview

Production volumes from continuing operations increased substantially to 15.4 MMboe in 2015 compared to 9.3 MMboe in 2014, representing an increase of 65%. The increase in production volumes was primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Crude oil production from continuing operations increased 62% in 2015, while NGL production from continuing operations increased 61%. Crude oil production comprised approximately 45% of total production from continuing operations in 2015. Natural gas production from continuing operations increased 73% in 2015 compared to 2014 as we shifted our 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. For the month ended December 31, 2015, we maintained an average production rate of 52 MBoe per day, up from 30 MBoe per day for the month ended December 31, 2014.

Crude oil, natural gas and NGLs sales from continuing operations, coupled with the impact of settlement of derivatives, increased in 2015. Increased production and positive net settlements on derivative positions more than offset the effect of declines in commodity prices during the year. Lower crude oil and natural gas index prices in 2015 were the primary reason for significant positive net settlements of $238.9 million on derivative positions compared to negative net settlements of $0.8 million in 2014. Crude oil, natural gas and NGLs sales, including the impact of net settlements on derivatives, was $617.6 million in 2015 compared to $470.6 million in 2014. This represents an increase of 31% in 2015 compared to 2014.

Other significant changes impacting our 2015 results of operations include the following:

Crude oil, natural gas and NGLs sales decreased to $378.7 million in 2015 compared to $471.4 million in 2014, due to a 51% decrease in the weighted-average realized prices of crude oil, natural gas and NGLs, offset in part by a 65% increase in production;
Negative net change in the fair value of unsettled derivative positions in 2015 was $35.8 million compared to a positive net change in the fair value of unsettled derivative positions of $311.1 million in 2014, primarily attributable to crude oil and natural gas derivatives that settled in 2015;
General and administrative expense decreased to $90.0 million in 2015 compared to $123.6 million in 2014, 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;
Impairment of crude oil and natural gas properties was $161.6 million in 2015 compared to $166.8 million in 2014, both primarily related to the write-down of our Utica Shale producing and non-producing crude oil and natural gas properties; and
Depreciation, depletion and amortization expense increased to $303.3 million in 2015 compared to $192.5 million in 2014, primarily due to increased production, offset in part by lower weighted-average depreciation, depletion and amortization rates.

Available liquidity as of December 31, 2015 was $402.2 million compared to $398.4 million as of December 31, 2014. Available liquidity as of December 31, 2015 is comprised of $0.9 million of cash and cash equivalents and $401.3 million available for borrowing under our revolving credit facility. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the agreement. In September 2015, we completed the semi-annual redetermination of the borrowing base under our revolving credit facility, which resulted in the reaffirmation of the borrowing base at $700 million. We have elected to maintain the aggregate commitment level at $450 million.

In March 2015, we completed a public offering of 4,002,000 shares of our common stock for net proceeds of approximately $203 million, after deducting offering expenses and underwriting discounts. We used a portion of the proceeds of the offering to repay all amounts then outstanding on our revolving credit facility, and used the remaining amounts to fund a portion of our capital program. With our current derivative position, available liquidity and expected cash flows from operations, we believe we have sufficient liquidity to allow us to execute our expected capital program through 2016.
 

36



2015 Operational Overview

During 2015, we continued to execute our strategic plan of increasing production, reserves and cash flows from drilling operations in the Wattenberg Field in Colorado and from completion activities in the Utica Shale play in southeastern Ohio. In the Wattenberg Field, we reduced our rig count in December to four automated drilling rigs from five due to the increases in our drilling rig efficiencies. In 2015, we spud 174 horizontal wells in the Wattenberg Field and turned-in-line 136 horizontal wells. We also participated in 54 gross, 8.1 net, horizontal non-operated wells that were spud and 58 gross, 9.3 net, horizontal non-operated wells which were turned-in-line. We began implementing several horizontal well-recovery enhancements in 2015, including tighter spacing between frac intervals on all wells and by drilling 40% of our wells with extended reach laterals of 6,500 feet to 7,000 feet. We have been able to improve our drilling time due to several factors, including the use of automated drilling rigs that minimize downtime, improved drilling team cohesion and utilizing analytics to improve drilling efficiencies. In the Utica Shale, we completed and turned-in-line a four-well pad during the first half of 2015. As a result of the turn-in-line of a four-well pad in late 2014 and a four-well pad in the second quarter of 2015, production volumes from the Utica Shale increased 41% in 2015 compared to 2014.
    
2016 Operational Outlook

We expect our production for 2016 to range between 20.0 MMBoe to 22.0 MMBoe and that our production rate will average approximately 55,000 to 60,000 Boe per day. Our 2016 capital forecast of approximately $435 million at the midpoint is focused on continuing to provide value-driven production growth by exploiting our extensive inventory of reasonable rate-of-return projects in the Wattenberg Field. Capital spending is expected to be weighted to the front half of 2016 as we complete Wattenberg Field in-process wells spud in 2015 and execute our Utica Shale drilling program.

Wattenberg Field. The 2016 capital forecast anticipates a four-rig drilling program in the Wattenberg Field based on our December 2015 outlook for future commodity prices. Approximately $400 million of our 2016 capital forecast is expected to be spent on development activities in the Wattenberg Field, comprised of approximately $350 million for our operated drilling program and approximately $35 million for non-operated projects. The remainder of the Wattenberg Field capital forecast is expected to be used for leasing, workover projects and other capital improvements, including the remodeling of our Greeley, Colorado, field operating facilities. We plan to spud 135 and turn-in-line 160 horizontal Niobrara or Codell wells and participate in approximately 35.0 gross, 7.0 net, non-operated horizontal opportunities in 2016.

Utica Shale. Based on the production results from recently drilled wells and decreases in well costs, in 2016 we plan on executing a modest drilling operation in the condensate and wet natural gas window of the play. Early in 2016, we plan to spend approximately $35 million in the Utica Shale to drill, complete and turn-in-line five wells, all of which are at least 6,000 foot laterals. The planned activity will focus on further delineation of our southern acreage, determining the impact of well-orientation on productivity and testing improved capital efficiency of a 10,000 foot lateral well.

2016 Operational Flexibility

In December 2015, the Board of Directors approved our 2016 development plan as described above. This plan, which primarily focuses on a four-rig drilling program in the Wattenberg Field, was based upon our December 2015 internal outlook for crude oil and natural gas prices, favorable debt metrics and the strength of our balance sheet, including our strong hedge position for 2016. In 2016, our goal continues to be preserving this balance sheet strength by managing our capital spending to approximate our cash flows from operations.

Since approving our 2016 development plan in December 2015, future commodity prices have continued to decline. Concurrently, capital costs to drill and complete Wattenberg Field wells have decreased, while crude oil differentials in the field have improved. We expect that our capital forecast of $420 million to $450 million will fund the same level of drilling and completions activity as projected prior to the aforementioned changes. Moreover, despite commodity prices decreasing in early 2016, we are anticipating reasonable rates of return in our middle core acreage in the Wattenberg Field.

The Company maintains significant operational flexibility in 2016 to reduce the pace of our capital spending. We will continue to monitor future commodity prices throughout 2016, and should prices remain depressed or continue to further deteriorate, we believe an adjustment to our development plan would be appropriate. We have ample opportunities to reduce capital spending, including but not limited to: working with our vendors to achieve further cost reductions; reducing the number of rigs being utilized in our drilling program; and/or managing our completion schedule. The production impact of reduced 2016 capital spending would be felt primarily in 2017 and thereafter, as our anticipated long-term production growth would likely be reduced. This operational flexibility is maintained with little exposure to incurring additional costs, given that all of our acreage in the Wattenberg Field is held by production, a reduction in rigs would not cause us to incur substantial idling costs as our rig commitments are short term (30 to 90 days), and we do not anticipate having additional material unfulfilled transportation commitment fees. Further, throughout 2016, such a reduction would be consistent with maintaining compliance well within the limits of our debt covenants.

As we go through 2016, our priority remains ensuring ample liquidity and protecting the strength of our balance sheet, and we will adjust our development plans as necessary to this end. We remain in close contact with the banks in our credit facility and are evaluating the increased risk that lenders may seek to reduce our borrowing base due to regulatory pressure to reduce their exposure to the energy industry or for other reasons. Further, we continue to monitor debt, equity and hedging markets for opportunities to strengthen our liquidity position.


37




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
 
2015
 
2014
 
2013
 
2015-2014
 
2014-2013
 
(dollars in millions, except per unit data)
 
 
 
 
Production (1)
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
6,983.8

 
4,321.9

 
2,909.7

 
61.6
 %
 
48.5
 %
Natural gas (MMcf)
33,301.7

 
19,298.0

 
15,431.2

 
72.6
 %
 
25.1
 %
NGLs (MBbls)
2,835.3

 
1,756.2

 
1,043.2

 
61.4
 %
 
68.3
 %
Crude oil equivalent (MBoe) (2)
15,369.4

 
9,294.4

 
6,524.7

 
65.4
 %
 
42.4
 %
Average MBoe per day
42.1

 
25.5

 
17.9

 
65.4
 %
 
42.4
 %
Crude Oil, Natural Gas and NGLs Sales
 
 
 
 
 
 
 
 
 
Crude oil
$
280.3

 
$
348.6

 
$
261.6

 
(19.6
)%
 
33.3
 %
Natural gas
68.0

 
74.7

 
50.0

 
(9.0
)%
 
49.4
 %
NGLs
30.4

 
48.1

 
29.2

 
(36.8
)%
 
64.7
 %
Total crude oil, natural gas and NGLs sales
$
378.7

 
$
471.4

 
$
340.8

 
(19.7
)%
 
38.3
 %
 
 
 
 
 
 
 
 
 
 
Net Settlements on Derivatives (3)
 
 
 
 
 
 
 
 
 
Natural gas
$
30.0

 
$
(3.1
)
 
$
14.3

 
*

 
*

Crude oil
208.9

 
2.3

 
(3.1
)
 
*

 
*

Total net settlements on derivatives
$
238.9

 
$
(0.8
)
 
$
11.2

 
*

 
*

 
 
 
 
 
 
 
 
 
 
Average Sales Price (excluding net settlements on derivatives)
 
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
$
40.14

 
$
80.67

 
$
89.92

 
(50.2
)%
 
(10.3
)%
Natural gas (per Mcf)
2.04

 
3.87

 
3.24

 
(47.3
)%
 
19.4
 %
NGLs (per Bbl)
10.72

 
27.39

 
27.97

 
(60.9
)%
 
(2.1
)%
Crude oil equivalent (per Boe)
24.64

 
50.72

 
52.23

 
(51.4
)%
 
(2.9
)%
 
 
 
 
 
 
 
 
 
 
Average Lease Operating Expenses (per Boe) (4)
 
 
 
 
 
 
 
 
 
Wattenberg Field
$
3.78

 
$
4.82

 
$
4.68

 
(21.6
)%
 
3.0
 %
Utica Shale
2.79

 
1.87

 
2.63

 
49.2
 %
 
(28.9
)%
Other

 
3.19

 
14.81

 
*

 
(78.5
)%
Weighted-average
3.71

 
4.56

 
5.18

 
(18.6
)%
 
(12.0
)%
 
 
 
 
 
 
 
 
 
 
Natural Gas Marketing Contribution Margin (5)
$
(0.8
)
 
$
(0.4
)
 
$
(0.3
)
 
(100.0
)%
 
(33.3
)%
 
 
 
 
 
 
 
 
 
 
Other Costs and Expenses
 
 
 
 
 
 
 
 
 
Production taxes
$
18.4

 
$
25.6

 
$
21.8

 
(28.0
)%
 
17.7
 %
Transportation, gathering and processing expenses
10.2

 
4.6

 
5.2

 
121.1
 %
 
(10.9
)%
Exploration expense
1.1

 
0.9

 
6.3

 
16.4
 %
 
(85.0
)%
Impairment of crude oil and natural gas properties
161.6

 
166.8

 
52.9

 
(3.1
)%
 
215.6
 %
General and administrative expense
90.0

 
123.6

 
63.7

 
(27.2
)%
 
93.9
 %
Depreciation, depletion and amortization
303.3

 
192.5

 
115.6

 
57.5
 %
 
66.5
 %
 
 
 
 
 
 
 
 
 
 
Interest expense
$
47.6

 
$
47.8

 
$
50.1

 
(0.6
)%
 
(4.6
)%
*
Percentage change is not meaningful or equal to or greater than 300%.
Amounts may not recalculate due to rounding.

38



______________
(1)
Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. For total production volume, including discontinued operations, see Part I, Item 6, Selected Financial Data.
(2)
One Bbl of crude oil or NGL equals six Mcf of natural gas.
(3)
Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing.
(4)
Represents lease operating expenses, exclusive of production taxes, on a per unit basis.
(5)
Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities.

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
 
2015
 
2014
 
2013
 
2015-2014
 
2014-2013
Crude oil (MBbls)
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
6,490.4

 
4,026.7

 
2,783.1

 
61.2
%
 
44.7
 %
Utica Shale
 
493.4

 
295.2

 
122.8

 
67.1
%
 
140.4
 %
Other
 

 

 
3.8

 
*

 
*

Total
 
6,983.8

 
4,321.9

 
2,909.7

 
61.6
%
 
48.5
 %
 Natural gas (MMcf)
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
30,752.8

 
17,108.9

 
12,724.3

 
79.7
%
 
34.5
 %
Utica Shale
 
2,548.9

 
2,152.9

 
561.1