Attached files

file filename
EX-99.1 - REPORT OF INDEPENDENT PETROLEUM CONSULTANTS - RYDER SCOTT COMPANY, L.P. - PDC ENERGY, INC.a2016_10kxexx991.htm
EX-99.2 - REPORT OF INDEPENDENT PETROLEUM CONSULTANTS - NETHERLAND, SEWELL & ASSOCIATES - PDC ENERGY, INC.a2016_10kxexx992.htm
EX-32.1 - 906 CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - PDC ENERGY, INC.a2016_10kxexx321.htm
EX-31.2 - 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - PDC ENERGY, INC.a2016_10kxexx312.htm
EX-31.1 - 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - PDC ENERGY, INC.a2016_10kxexx311.htm
EX-23.3 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC., PETROLEUM CONSULTANTS - PDC ENERGY, INC.a2016_10kxexx233.htm
EX-23.2 - CONSENT OF RYDER SCOTT COMPANY, L.P., PETROLEUM CONSULTANTS - PDC ENERGY, INC.a2016_10kxexx232.htm
EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS LLP - PDC ENERGY, INC.a2016_10kxexx231.htm
EX-21.1 - SUBSIDIARIES - PDC ENERGY, INC.a2016_10kxexx211.htm
EX-12.1 - COMPUTATION OF RATIO TO FIXED CHARGES - PDC ENERGY, INC.a2016_10kxexx121.htm
EX-10.14.1 - AMENDMENT TO THE PDC ENERGY CHANGE OF CONTROL AND SEVERANCE PLAN - PDC ENERGY, INC.a2016_10kxexx10141.htm
EX-10.14 - CHANGE OF CONTROL AND SEVERANCE PLAN - PDC ENERGY, INC.a2016_10kxexx1014.htm
EX-10.7.8 - FORM OF 2016 PERFORMANCE SHARE AGREEMENT - PDC ENERGY, INC.a2016_10kxexx1078.htm
EX-10.2 - 401(K) AND PROFIT SHARING PLAN, AS AMENDED ON JANUARY 4, 2016 - PDC ENERGY, INC.a2016_10kxexx102.htm
EX-4.1 - FORM OF COMMON STOCK CERTIFICATE OF THE COMPANY - PDC ENERGY, INC.a2016_10kxexx41.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, 2016

or

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

For the transition period from __________ to _________

Commission File Number 001-37419
logo123114a08.jpg
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware
95-2636730
(State of incorporation)
(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip code)

Registrant's telephone number, including area code: (303) 860-5800

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, par value $0.01 per share
 
NASDAQ Global Select Market

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

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer  x
Accelerated filer  o
Non-accelerated filer  £
(Do not check if a smaller reporting company)
Smaller reporting company  o

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

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

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


DOCUMENTS INCORPORATED BY REFERENCE

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




PDC ENERGY, INC.
2016 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

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

GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS
 
Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the terms “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.

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

changes in worldwide production volumes and demand, including economic conditions that might impact demand;
volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
reductions in the borrowing base under our revolving credit facility;
impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations;
declines in the value of our crude oil, natural gas, and NGLs properties resulting in further impairments;
changes in estimates of proved reserves;
inaccuracy of estimated reserves and production rates;
potential for production decline rates from our wells being greater than expected;
timing and extent of our success in discovering, acquiring, developing, and producing reserves;
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of crude oil and natural gas wells;
losses from our Gas Marketing segment exceeding our expectations;
difficulties in integrating our operations as a result of any significant acquisitions, including our recent acquisitions in the Delaware Basin;
increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion and facilities costs;
increases or adverse changes in construction costs and procurement costs associated with future build out of mid-stream related assets;
future cash flows, liquidity, and financial condition;
competition within the oil and gas industry;
availability and cost of capital;
our success in marketing crude oil, natural gas, and NGLs;

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effect of crude oil and natural gas derivatives activities;
impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;
cost of pending or future litigation;
effect that acquisitions we may pursue have on our capital investments;
our ability to retain or attract senior management and key technical employees; and
success of strategic plans, expectations and objectives for our future operations.
 
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

The Company

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

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

Our Strengths

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

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

In March 2016, we raised $296.6 million, net of issuance costs, from the sale of 5.9 million shares of common stock.
In September 2016, we issued 9.1 million shares of common stock for net proceeds of $558.5 million, $400.0 million of 6.125% senior unsecured notes due in 2024 ("2024 Senior Notes") for net proceeds of $392.2 million, and $200.0 million of 1.125% convertible senior notes due in 2021 for net proceeds of $193.9 million.

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We also issued 9.4 million shares of common stock valued at $690.7 million in December 2016 as partial consideration to the sellers for the initial Delaware Basin acquisition.
In December 2016, we increased the aggregate commitment under our revolving credit facility to $700 million.         

We intend to continue to manage our liquidity position through investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative program, and access to capital markets from time to time.

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

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

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

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

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

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

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

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

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

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

Business Strategy

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

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


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Development drilling
 
The following map presents the general locations of our development and production activities as of December 31, 2016:
 
usmap2016v3.jpg

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

We have allocated substantially all of our 2017 capital investment program to our higher-return projects in the Wattenberg Field and Delaware Basin, and have elected to defer drilling operations in the Utica Shale. Based on our current production and commodity price outlook for 2017, we continue to expect capital investments to exceed cash flows from operations by approximately $200 million. Our debt to EBITDAX ratio, as defined in our revolving credit facility agreement, is expected to decrease in 2017 based on production and operational cash flow growth. A deterioration of commodity prices could negatively impact our results of operations, financial condition, and future development plans. We may increase or decrease our 2017 capital investment program during the year as a result of, among other things, changes in commodity prices or our current internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. If such changes result in our election to deploy additional capital investment, amounts may further exceed our cash flow from operations.
 
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays. Based on our current drilling program, we have an inventory of 700 gross proved undeveloped horizontal drilling locations and approximately 1,100 gross probable horizontal drilling locations. These locations are in the core Wattenberg Field, which is further delineated between the inner, middle, and outer core. In 2017, we expect to continue to realize additional capital efficiencies through drilling extended length laterals, an increased number of fracturing stages, plug-and-perforation completions, enhanced well orientation, and mono-bore drilling. We plan to drill standard reach lateral (“SRL”), mid-length lateral (“MRL”), and extended reach lateral (“XRL”) wells in 2017, the majority of which will be in the middle core area of the field. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface. In 2017, to help balance our priorities, we now anticipate spudding 137 operated wells and turning-in-line to sales, approximately 139 horizontal operated wells as outlined below.


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

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

Delaware Basin. In December 2016, we closed a series of acquisitions providing us a total of approximately 62,500 net acres in Reeves and Culberson Counties, Texas (see “Business Strategy-Strategic acquisitions” below).  In 2017, our investment outlook now contemplates operating a two-rig to four-rig program at various times throughout the year and deploying the third rig in late Februay 2017. Total capital investment in the Delaware Basin is estimated to be $300 million, of which approximately $235 million is allocated to spud 31 wells and turn-in-line an estimated 26 wells.  Based on the timing of our operations and the requirements to hold acreage, we may adapt our capital investment program to drill wells in addition to those currently anticipated, as we are continuing to analyze the terms of the leaseholds related to our recent acquisitions of properties in the basin. We plan to drill 20 wells in our eastern acreage block, nine wells in our central acreage block, and two wells in our western acreage block, with the majority of wells targeting the Wolfcamp A and B zones. Of the 26 planned turn-in-lines, 14 are expected to have laterals of approximately 10,000 horizontal feet with completion stages currently expected to range from approximately 100 to 125 feet. Similarly spaced completions are anticipated for the remaining 12 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at depths of approximately 9,000 to 11,000 feet below the surface. Estimated well costs for SRL, MRL, and XRL wells are approximately $7.1 million, $8.8 million and $10.5 million, respectively. We plan to invest approximately $35 million for leasing, seismic, and technical studies with an additional $30 million for midstream related projects including gas connections, salt water disposal wells, and surface location infrastructure.
 
Utica Shale.  At this time, we are currently evaluating all of our strategic alternatives with respect to our Utica Shale position. As a result of such evaluation, we are deferring our 2017 planned expenditure of $18 million to drill, complete, and turn-in-line two wells in Guernsey County.  In 2017, our capital investment program for the Utica Shale is expected to include between $2 million to $3 million for additional leasing. Such leasing may be necessary to complete certain drilling operations if we decide to continue development of our existing position in the northern portion of our acreage.

Strategic acquisitions

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

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

The first transaction consisted of the acquisition of certain producing properties and approximately 57,900 acres for approximately $952.1 million in cash and the issuance of 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed, for total consideration of approximately $1.64 billion.
The second transaction occurred shortly thereafter and included certain developed assets and 4,600 net acres of undeveloped leasehold that is complementary to the initial transaction. This transaction was paid for in cash of $120.6 million.

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

6



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

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

Business Segments

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

Oil and Gas Exploration and Production

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

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


7



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

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

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

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

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

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

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


8



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

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

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

Properties

Productive Wells

The following table presents our productive wells:

 
 
Productive Wells
 
 
As of December 31, 2016
 
 
Crude Oil
 
Natural Gas
 
Total
Operating Region/Area
 
 Gross
 
 Net
 
Gross
 
 Net 
 
 Gross
 
 Net
Wattenberg Field
 
669

 
436.8

 
2,193

 
1,908.0

 
2,862

 
2,344.8

Delaware Basin
 
33

 
31.5

 

 

 
33

 
31.5

Utica Shale
 
27

 
22.2

 
3

 
3.0

 
30

 
25.2

 
 
 
 
 
 
 
 
 
 
 
 
 
Total productive wells
 
729

 
490.5

 
2,196

 
1,911.0

 
2,925

 
2,401.5



9



Proved Reserves

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

 
Proved Reserves at December 31, 2016
 
 
 
 
 
 
 
Proved Reserves (MMBoe)
 
% of Total Proved Reserves
 
% Proved Developed
 
% Liquids
 
Proved Reserves to Production Ratio (in years)(1)
 
2016 Production (MBoe)
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
305.3
 
89
%
 
29
%
 
58
%
 
14.6
 
20,945

Delaware Basin
32.5
 
10
%
 
22
%
 
68
%
 
15.2
 
178

Utica Shale
3.6
 
1
%
 
100
%
 
56
%
 
3.4
 
1,053

Total proved reserves
341.4
 
100
%
 
29
%
 
59
%
 
16.2
 
22,176

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

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

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

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

When preparing our reserve estimates, neither Ryder Scott nor NSAI independently verifies the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties, and sales of production. Ryder Scott and NSAI prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve reports are those as prepared by Ryder Scott and NSAI and are reviewed by our engineering staff and management prior to issuance by the independent professional reserve engineering firms.
 
The professional qualifications of our internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 40 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and is a registered Professional Engineer in the State of Colorado.

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


10



 
 
As of December 31,
 
 
2016
 
2015
 
2014
 
 
 
 
 
 
 
Crude oil (SEC NYMEX - $/Bbl)
 
$
42.75

 
$
50.28

 
$
94.99

Natural gas (SEC NYMEX - $/MMBtu)
 
$
2.48

 
$
2.59

 
$
4.35


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

 
As of December 31,
 
2016
 
2015
 
2014
Proved reserves
 
 
 
 
 
Crude oil and condensate (MMBbls)
118

 
99

 
101

Natural gas (Bcf)
834

 
661

 
537

NGLs (MMBbls)
84

 
64

 
60

Total proved reserves (MMBoe)
341

 
273

 
250

Proved developed reserves (MMBoe)
98

 
70

 
75

Estimated undiscounted future net cash flows (in millions) (1)
$
2,681

 
$
2,259

 
$
4,938

 
 
 
 
 
 
Standardized measure (in millions)
$
1,421

 
$
1,097

 
$
2,306

 
 
 
 
 
 
PV-10 (in millions) (2)
$
1,675

 
$
1,338

 
$
3,450

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

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

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


11



 
 
As of December 31, 2016
Operating Region/Area
 
Crude Oil and Condensate (MMBbls)
 
Natural Gas
(Bcf)
 
NGLs
(MMBbls)
 
Crude Oil
Equivalent
(MMBoe)
 
Percent
Proved developed
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
25.5

 
240.6

 
21.7

 
87.4

 
26
%
Delaware Basin
 
3.4

 
13.9

 
1.6

 
7.2

 
2
%
Utica Shale
 
1.1

 
9.9

 
0.9

 
3.6

 
1
%
Total proved developed
 
30.0

 
264.4

 
24.2

 
98.2

 
29
%
Proved undeveloped
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
76.6

 
520.6

 
54.5

 
217.9

 
64
%
Delaware Basin
 
11.6

 
48.7

 
5.6

 
25.3

 
7
%
Utica Shale
 

 

 

 

 
%
Total proved undeveloped
 
88.2

 
569.3

 
60.1

 
243.2

 
71
%
Total proved reserves
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
102.1

 
761.2

 
76.2

 
305.3

 
89
%
Delaware Basin
 
15.0

 
62.6

 
7.2

 
32.5

 
10
%
Utica Shale
 
1.1

 
9.9

 
0.9

 
3.6

 
1
%
Total proved reserves
 
118.2

 
833.7

 
84.3

 
341.4

 
100
%
 
 
 
 
 
 
 
 
 
 
 

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

 
Pricing Scenario - NYMEX
 
 
 
 
 
 
 
Crude Oil (per Bbl) (1)
 
Natural Gas (per MMBtu) (1)
 
Proved Reserves (MMBoe)
 
% Change from December 31, 2016 Estimated Reserves
PV-10 (in Millions)
PV-10 % Change from December 31, 2016 Estimate Reserves
2016 SEC Reserve Report
$
42.75

 
$
2.48

 
341.4

 

$
1,675.0


Alternate Price Scenarios:
 
 
 
 
 
 
 
 
 
Lower Price Scenario
$
30.00

 
$
2.48

 
326.5

 
(4
)%
$
705.7

(58
)%
Higher Price Scenario
$
50.00

 
$
2.48

 
345.7

 
1
 %
$
2,247.0

34
 %
__________
(1)
These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently across each pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.


12



Developed and Undeveloped Acreage

The following table presents our developed and undeveloped lease acreage:
 
 
As of December 31, 2016
 
 
Developed
 
Undeveloped
 
Total
Operating Region/Area
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wattenberg Field
 
96,700

 
89,200

 
7,700

 
6,300

 
104,400

 
95,500

Delaware Basin
 
19,586

 
18,664

 
49,645

 
43,837

 
69,231

 
62,501

Utica Shale
 
5,454

 
4,291

 
61,862

 
58,162

 
67,316

 
62,453

 Total acreage
 
121,740

 
112,155

 
119,207

 
108,299

 
240,947

 
220,454

 
 
 
 
 
 
 
 
 
 
 
 
 

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

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

 
 
Gross Development Well Drilling Activity
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Operating Region/Area
 
Productive
 
In-Process
 
Non-Productive (1)
 
Productive
 
In-Process
 
Non-Productive (1)
 
Productive
 
In-Process
 
Non-Productive (1)
Wattenberg Field, operated wells
 
140

 
64

 
2

 
136

 
78

 
4

 
86

 
44

 
2

Wattenberg Field, non-operated wells
 
24

 
12

 

 
58

 
19

 

 
70

 
25

 

Delaware Basin
 
1

 
5

 

 

 

 

 

 

 

Utica Shale
 
5

 

 

 
4

 
5

 

 
8

 
4

 
1

Other (2)
 

 

 

 

 

 

 
4

 

 

Total gross development wells
 
170

 
81

 
2

 
198

 
102

 
4

 
168

 
73

 
3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(1)
Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
(2)
Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.

13



 
 
 
Net Development Well Drilling Activity
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Operating Region/Area
 
Productive
 
In-Process
 
Non-Productive (1)
 
Productive
 
In-Process
 
Non-Productive (1)
 
Productive
 
In-Process
 
Non-Productive (1)
Wattenberg Field, operated wells
 
109.7

 
52.7

 
1.7

 
110.8

 
54.6

 
2.7

 
75.8

 
36.5

 
1.7

Wattenberg Field, non-operated wells
 
5.0

 
2.8

 

 
9.3

 
4.3

 

 
14.9

 
6.3

 

Delaware Basin
 
1.0

 
4.8

 

 

 

 

 

 

 

Utica Shale
 
4.5

 

 

 
3.0

 
4.5

 

 
7.0

 
3.0

 
1.0

Other (2)
 

 

 

 

 

 

 
2.0

 

 

Total net development wells
 
120.2

 
60.3

 
1.7

 
123.1

 
63.4

 
2.7

 
99.7

 
45.8

 
2.7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(1)
Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
(2)
Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.

Title to Properties

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

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

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

Facilities

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

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

Governmental Regulation

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

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

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

bond requirements in order to drill or operate wells;
well locations;
drilling and casing methods;
surface use and restoration of well properties;
well plugging and abandoning;
fluid disposal; and
air emissions.

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

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

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

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

costs of providing service, including depreciation expense;
allowed rate of return, including the equity component of the capital structure, and related income taxes; and
volume throughput assumptions.

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

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


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Environmental Matters

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil increases our risks related to soil and water contamination from any future oil spills.
    
Our costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2017 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report.

Operating Hazards and Insurance

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

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

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

Competition and Technological Changes

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

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

Employees

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

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WHERE YOU CAN FIND ADDITIONAL INFORMATION

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

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


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ITEM 1A. RISK FACTORS

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

Risks Relating to Our Business and the Industry

Crude oil, natural gas, and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and impede our growth.
Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas, and NGLs. Changes in prices affect many aspects of our business, including:
our revenue, profitability and cash flows;
our liquidity;
the quantity and present value of our reserves;
the borrowing base under our revolving credit facility and access to other sources of capital; and
the nature and scale of our operations.

The markets for crude oil, natural gas, and NGLs are often volatile, and prices may fluctuate in response to, among other things:
relatively minor changes in regional, national, or global supply and demand;
regional, national, or global economic conditions, and perceived trends in those conditions;
geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or OPEC; and
regulatory changes.

The price of oil has been volatile since mid-2014, with a high over $100 per barrel in June 2014 to lows below $30 per barrel in 2016, in each case based on WTI prices, due to a combination of factors including increased U.S. supply, global economic concerns, and the resumption of oil exports from Iran. Prices for natural gas and NGLs have experienced similar volatility. Declines in prices adversely affect, among other things, our revenue and reserves, and have contributed to the recognition of impairment charges, including charges of $158.3 million and $150.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in 2014 and 2015, respectively. Any future extended period of lower oil prices, or additional price declines, will have further adverse effects on us. For example, if we reduce our capital expenditures due to low prices, natural declines in production from our wells will likely result in reduced production and therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production.
In addition to factors affecting the price of crude oil, natural gas, and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants, and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally may result in widening differentials, particularly for production from some basins. We may be materially and adversely impacted by widening differentials on our production.
The Delaware Basin acquisitions may not achieve their intended results and may result in us assuming unanticipated liabilities.
The Delaware Basin acquisitions subject us to many of the risks described below in “Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties.” For example, we may discover title defects or adverse environmental or other conditions relating to the properties acquired in the transactions of which we are currently unaware. Environmental, title, and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We have assumed substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances, for limited periods and in limited amounts. We cannot provide assurance that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant. Also, it is uncertain whether our existing operations and the acquired properties and assets can be integrated in an efficient and effective manner. In addition, the success of the Delaware Basin acquisitions depend on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGL and natural gas prices and operating costs, and various other factors. The majority of the value was attributed to unproved leaseholds, which inherently have a higher risk of uncertainty than the acquisition of proved developed reserves. These assessments were based to a significant degree on information provided by the sellers and we cannot guarantee their accuracy. Although the acquired properties are subject to many of the risks and uncertainties to which acquisitions we pursue are subject generally, risks associated with the Delaware Basin acquisitions in particular include those associated with our ability to operate efficiently in a new area, the significant size of the transactions in the aggregate, the fact that a substantial majority of the acquired properties are undeveloped, and the additional indebtedness and transaction costs we incurred in connection with the acquisitions. Many of these risks also apply to acquisitions of additional Delaware Basin properties

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we have pursued or may pursue in the future. In addition, we expect that pursuing our future development plans for the properties will require capital in excess of our projected cash flow from operations for some period of time beginning in 2017, which may increase our need for external financing.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, approvals of the Texas General Land Office for our Delaware Basin properties, and other factors. These risks are currently greater for us in the Delaware Basin area than in our other operating areas. As of December 31, 2016, approximately 30 percent of our total net acreage in the Delaware Basin was held-by-production or drilling operations. In addition, a substantial portion of our Utica Shale acreage is held-by-production by a third party operator’s shallow vertical wells. Our relative lack of control over this acreage increases the risk that some of our leases will expire.
Ballot initiatives have been proposed in Colorado from time to time that could vastly expand the right of local governments to limit or prohibit oil and natural gas production and development in their jurisdictions and could impose additional regulations on production and development activities. If any initiative or legislation of this nature is implemented and survives legal challenge, additional limitations or prohibitions could be placed on crude oil, natural gas and NGL production and development within certain areas of Colorado or the state as a whole. Similar initiatives could be proposed in other states.
During 2016, certain interest groups in Colorado opposed to oil and natural gas development generally, or hydraulic fracturing in particular, advanced various options for ballot initiatives aimed at significantly limiting or effectively preventing oil and natural gas development in the state of Colorado. Proponents of two such initiatives attempted to qualify the initiatives to appear on the ballot for the November 2016 election. On August 29, 2016, the Colorado Secretary of State issued a press release and statements of insufficiency of signatures, stating that the proponents of the proposals had failed to collect enough valid signatures to have the proposals included on the ballot.
One of the initiatives, which we refer to as the “local control” initiative, would have amended the state constitution to give city, town, and county governments the right to regulate, or to ban, oil and gas development and production within their boundaries, notwithstanding rules and approvals to the contrary at the state level. This proposal was motivated in part by a decision of the Colorado Supreme Court holding that local government restrictions on oil and gas activities are subject to preemption by state rules.
A second initiative, which we refer to as the “setback” initiative, would have amended the state constitution to require all new oil and gas development facilities to be located at least 2,500 feet away from any occupied structure or broadly defined “area of special concern,” including public and community drinking water sources, lakes, rivers, perennial or intermittent streams, creeks, irrigation canals, riparian areas, playgrounds, permanent sports fields, amphitheaters, public parks, and public open space.
If implemented, the setback initiative would have effectively prohibited the vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. The local control proposal would potentially have had a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities. Pursuant to the determination of the Colorado Secretary of State, these proposals did not appear on the November 2016 ballot. However, future proposals of this nature are possible.
Because a substantial portion of our operations and reserves are located in Colorado, the risks we face with respect to such future proposals are greater than those of our competitors with more geographically diverse operations. Although we cannot predict the outcome of future ballot initiatives, statutes, or regulatory developments, such developments could materially impact our results of operations, production, and reserves.
A substantial part of our crude oil, natural gas, and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations.
Although we have significant non-producing leasehold positions in the Delaware Basin in Texas and the Utica Shale in Ohio, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including:
fluctuations in prices of crude oil, natural gas, and NGLs produced from the wells in the area;
natural disasters such as the flooding that occurred in Northern Colorado in September 2013;
restrictive governmental regulations; and
curtailment of production or interruption in the availability of gathering, processing, or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells.


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For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations.
Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.
Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business.  Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general.  The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Utica Shale area are particularly vulnerable to title deficiencies due the long history of land ownership in the area and correspondingly extensive and complex chains of title. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability.
Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of crude oil, natural gas, and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including:
our proved reserves;
the amount of crude oil, natural gas, and NGLs we are able to produce from existing wells;
the prices at which crude oil, natural gas, and NGLs are sold;
the costs to produce crude oil, natural gas, and NGLs; and
our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability.
Our ability to produce crude oil, natural gas, and NGLs could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.
Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). In addition, both eastern Colorado and western Texas have relatively arid climates and experience drought conditions from time to time. As a result, future availability of water from certain sources used in the past may become limited.
The imposition of new environmental initiatives relating to wastewater could restrict our ability to conduct certain operations such as hydraulic fracturing. This includes potential restrictions on waste disposal, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of hydrocarbons. For example, in 2010 a petition was filed by the Natural Resources Defense Council with the EPA requesting that the agency reassess its prior and long-standing determination that certain oil and natural gas exploration and production wastes would not be regulated as hazardous waste under Subtitle C of the RCRA. The EPA has not yet acted on the petition and it remains pending. In a separate but related matter, a proposed consent decree filed in December 2016 between the EPA and several environmental groups commits the EPA to decide whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector by March 2019. If the EPA began treating some or all of these wastes as “hazardous”

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under Subtitle C in response to the petition or as a result of the proposed consent decree, the consequences for our operations would be serious, and would include a significant increase in costs associated with waste treatment and disposal and a potential inability to conduct operations in some instances.
The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated federal and state waters. Permits or other approvals must be obtained to discharge fill and pollutants into regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. In June 2015, the EPA and the U.S. Army Corps of Engineers issued a final rule that clarifies the scope of the agencies’ jurisdiction under section 404 of the CWA to regulate certain activities occurring in waters of the United States. This rule, known as the Clean Water Rule, has been challenged by various parties in multiple federal courts, and as a result of this litigation is currently stayed and not yet effective. An expansive definition of such jurisdictional waters could affect our ability to operate in certain areas, increase costs of operations, and cause significant scrutiny and delays in permitting. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. These permits, in turn, impose far-ranging monitoring, flow control, and other obligations that have generated, and will continue to generate, increased costs for our operations.
In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. Some states, including Pennsylvania, have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There also has been recent nationwide concern, particularly in Ohio and Oklahoma, over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. As seen in Ohio, it is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others.
Finally, the EPA study on hydraulic fracturing noted above focused on various stages of water use in hydraulic fracturing operations. It is possible that the EPA will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. In addition, an inability to meet our water supply needs to conduct our completion operations may adversely impact our business.
The marketability of our production is dependent upon transportation and processing facilities the capacity and operation of which we do not control. Market conditions or operational impediments, including high line pressures, particularly in the Wattenberg Field, and other impediments affecting midstream facilities and services, could hinder our access to crude oil, natural gas, and NGL markets, increase our costs or delay production, and thereby adversely affect our profitability.
Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, in some recent periods, due to ongoing drilling activities by us and third parties and hot temperatures during the summer months, the principal third-party provider we use in the Wattenberg Field area for midstream facilities and services experienced increased gathering system pressures during those warmer months. The resulting capacity constraints reduced the productivity of some of our older vertical wells and limited incremental production from some of our newer horizontal wells. This constrained our production and reduced our revenue from the affected wells. Capacity constraints affecting natural gas production also impacted the associated NGLs. Some operators in the Delaware Basin have experienced similar issues from time to time, in part due to significant increases in production in the area. Our operations in Texas and elsewhere may be adversely affected by those issues. The use of alternative forms of transportation for oil production such as trucks or rail involve risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or railcars.
In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas, and NGLs we produce.
We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example:
Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties;
Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; and
Some upstream energy companies have in the recent past sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure.

Like other producers we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If we reduce the pace of our drilling activities significantly after entering into such commitments for any reason, it may be difficult or impossible for us to satisfy those commitments.
Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves.

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Crude oil prices fell dramatically in the second half of 2014, with further declines in 2015 and into 2016, and the domestic natural gas market remains weak. Low commodity prices could result in, among other adverse effects, significant impairment charges. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges of $150.3 million and $158.3 million relating to our Utica Shale properties in 2015 and 2014, respectively. Similar charges could occur in the future. In addition, low commodity prices could result in significant downward revisions to the estimated quantity and value of our proved reserves.
Our estimated crude oil and natural gas reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.
Calculating reserves for crude oil, natural gas, and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas, and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding commodity prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual results could greatly affect:
the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties;
future depreciation, depletion, and amortization (“DD&A”) rates and amounts;
impairments in the value of our assets;
the classifications of reserves based on risk of recovery;
estimates of future net cash flows;
timing of our capital expenditures; and
the amount of funds available for us to borrow under our revolving credit facility.

Some of our reserve estimates must be made with limited production histories, which renders these reserve estimates less reliable than estimates based on longer production histories. Horizontal drilling in the Wattenberg Field is a relatively recent development, whereas vertical drilling has been used by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small, and future reserve estimates will be affected by additional production data as it becomes available. Horizontal drilling in the Utica Shale and the Delaware Basin has an even more limited history. Further, reserve estimates are based on the volumes of crude oil, natural gas, and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas, and NGLs recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons.
At December 31, 2016, approximately 71.2 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.1 billion during the five years ending December 31, 2021, as estimated in the calculation of the standardized measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame.
The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, were based on the prior year’s first day of the month 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas, and NGLs, and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general.
Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned.
Producing crude oil, natural gas, and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover, or acquire additional

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reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations.
     We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including:
crude oil, natural gas, and NGL prices;
the availability and cost of capital;
drilling and production costs;
availability of drilling services and equipment;
drilling results;
lease expirations;
midstream constraints;
access to and availability of water sourcing and distribution systems;
regulatory approvals; and
other factors.

Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas, or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances in order to facilitate exploration.  Other states, including Texas, restrict involuntary pooling to a narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and leases.  In states where pooling is accomplished primarily on a voluntary basis, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than 100 percent of the leasehold or one or more of our leases does not provide the necessary pooling authority. If third parties are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, and this would limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified. Further, our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable, and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related inventory of drilling locations.
The wells we drill may not yield crude oil, natural gas, or NGLs in commercially viable quantities and productive wells may be less successful than we expect.
A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas, or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to whether hydrocarbons are, in fact, present in those structures or the quantity of the hydrocarbons. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas, or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas, and NGLs to be profitable, or they may be less productive and/or profitable than we expected. In recent years we have been able to achieve reductions in drilling and completion costs in connection with lower commodity prices. However, as commodity prices have stabilized or increased since mid-2016, many of these costs have begun to increase, and further increases are expected. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase, the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period.

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Drilling for and producing crude oil, natural gas, and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.
Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays, or cancellations as a result of other factors, including:
unusual or unexpected geological formations;
pressures;
fires;
floods;
loss of well control;
loss of drilling fluid circulation;
title problems;
facility or equipment malfunctions;
unexpected operational events;
shortages or delays in the delivery of equipment and services;
unanticipated environmental liabilities;
compliance with environmental and other governmental requirements; and
adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells, and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites.
Our business strategy focuses on production in our liquid-rich shale plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. Prior to 2012, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of our capital budget to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells - including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - and the risk of failure is therefore greater than the risk involved in drilling vertical wells. Additionally, drilling a horizontal well is typically far costlier than drilling a vertical well. This means that the risks of our drilling program will be spread over a smaller number of wells, and that, in order to be economic, each horizontal well will need to produce at a higher level in order to cover the higher drilling costs. Similarly, the average lateral length of the horizontal wells we drill has generally been increasing. Longer-lateral wells are typically more expensive and require more time for preparation and permitting. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program.
Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability.
We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed.
We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt.
We have a substantial amount of indebtedness. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. We incurred a substantial amount of additional debt in order

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to finance part of the purchase price for the Delaware Basin acquisitions, and the properties acquired currently produce only modest amounts of cash flow from operations.
Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flows from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions, including possibly depressed commodity pricing, and financial, business and other factors, many of which are beyond our control. We expect that some commercial lenders may look to reduce their exposure to exploration and production companies due to regulatory pressures they face and/or independent business considerations. This could adversely affect our liquidity and our ability to refinance our debt.
A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt, or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our existing debt agreements do, restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. Because the cash required to service our indebtedness is not available to finance our operations and other business activities, our indebtedness limits our flexibility in planning for or reacting to changes in our business and the industry in which we operate and increases our vulnerability to economic downturns and sustained declines in commodity prices.
Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions.
The indentures governing our senior notes and our revolving credit facility contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and certain of our subsidiaries’ ability to:
incur additional debt;
pay dividends on, redeem, or repurchase stock;
create liens;
make specified types of investments;
apply net proceeds from certain asset sales;
engage in transactions with our affiliates;
engage in sale and leaseback transactions;
merge or consolidate;
restrict dividends or other payments from restricted subsidiaries;
sell equity interests of restricted subsidiaries; and
sell, assign, transfer, lease, convey or dispose of assets.

Our revolving credit facility is secured by substantially all of our crude oil and natural gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility.
Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices.
We depend in large part on our revolving credit facility for future capital needs. The terms of the credit agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable.
The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas, or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results.

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If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations.
Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease.
Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above.
We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility, and may do so in 2017. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we now face.
Seasonal weather conditions and lease stipulations can adversely affect our operations.
Seasonal weather conditions and lease stipulations designed to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, oil field equipment, services, supplies, and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows.
We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.
We operate approximately 88 percent of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks are heightened in some respects in periods of depressed commodity prices as operators may propose operations that we believe to be economically unattractive, leading us to incur non-consent penalties. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters.
Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income.
We use commodity derivatives for a portion of the production from our own wells and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss.
Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity, and they may require the use of our resources to meet cash margin requirements.

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In addition, at December 31, 2016, we had hedged a total of 13,342 MBbls of crude oil and 128,036 BBtu of natural gas for 2017 and 2018. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices, and our current hedge position is smaller than it has been in recent years.
The estimated fair value of our aggregate commodity derivative position as of December 31, 2015, was an asset balance of approximately $263.8 million.  As a result of factors including the settlement of commodity derivative positions over the course of 2016 and changes in commodity prices, the estimated fair value of our aggregate commodity derivative position as of December 31, 2016 was a liability balance of approximately $70.0 million.  Accordingly, based on our current commodity derivative positions and current commodity prices, we expect that cash flow from our commodity derivative activities will be substantially lower in 2017 than it was in 2016, and may be negative.
Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income.
The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from our crude oil, natural gas, and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives as well as the commodity derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We frequently own less than 100 percent of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas, and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.
Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.
The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We also do not carry contingent business interruption insurance related to the purchasers of our production. In addition, pollution and environmental risks are generally not fully insurable.
We may not be able to keep pace with technological developments in our industry.
Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.
Competition in our industry is intense, which may adversely affect our ability to succeed.
Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas, and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local, and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our operations and our profitability.
Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

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Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
A failure to complete successful acquisitions would limit our growth.
Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes, and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete land trades or exchanges and other acquisitions that allow us to increase our working interests in particular properties. Acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations.
Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties.
Acquisitions of producing properties and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological, and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface, and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor.
When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire.
Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges.
Some of our acquisitions are structured as land trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange. Such an undervaluation would result in the transaction being less favorable to us than we expected.
The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. In addition in August 2015 we received a Clean Air Act Section 114 Information Request (the "Information Request")from the EPA, and this request could result in penalties or other liabilities. The outcome of pending legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees, or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.
The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger declines in the price of our common stock, including, among others:
changes in production volumes, worldwide demand and prices for crude oil and natural gas;
changes in market prices of crude oil and natural gas;
inability to hedge future production at the same pricing level as our current hedges;
changes in securities analysts’ estimates of our financial performance;
fluctuations in stock market prices and volumes, particularly among securities of energy companies;
changes in market valuations and valuation multiples of similar companies;
changes in interest rates;
announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing crude oil and natural gas resources;
announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;
decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate;
operating results that fall below market expectations or variations in our quarterly operating results;
loss of a major customer;
loss of a relationship with a partner;
the identification of and severity of environmental events and governmental and other third-party responses to the events; or
additions or departures of key personnel.

External events, such as news concerning economic conditions, counterparties to our natural gas or oil derivatives arrangements, changes in government regulations impacting the oil and natural gas exploration and production industries or the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. Similarly, our stock price could be adversely affected by changes in the way that analysts and investors assess the geological and economic characteristics of the basins in which we operate. For example, general market perceptions of the Permian Basin region have recently become highly favorable, and adverse changes in those perceptions could have a corresponding effect on the price of our stock. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. Recently, the stock markets have experienced price and volume volatility that has affected many companies’ stock prices. Stock prices for many companies have experienced wide fluctuations that have often been unrelated to the operating performance of those companies. These fluctuations may affect the market price of our common stock.
In addition, a portion of the consideration we paid to the sellers in the Delaware Basin acquisitions was in the form our common stock. Those shares are currently subject to lock-up periods set forth in the applicable Investment Agreement. Upon the expiration of the lock-up period, the sellers will be entitled to sell their shares into the public markets, which could cause the market price of our common stock to decline.
Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.
We face various security threats, including attempts by third parties to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows.
In particular, the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling activities, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data.
We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to store, transmit, process, and record sensitive information (including trade secrets, employee information, and financial and operating data), communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexity of the technologies needed to explore for and develop oil, natural gas, and NGLs make certain information more attractive to thieves.
Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. Some of these business partners may be provided limited access to our sensitive information or our information systems and related infrastructure. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. “Phishing” and other types of attempts to obtain unauthorized

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information or access are often sophisticated and difficult to detect or defeat. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies.
Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Given the politically sensitive nature of hydraulic fracturing and the controversy generated by its opponents, our technologies, systems and networks may be of particular interest to certain groups with political agendas, which may seek to launch cyber-attacks as a method of promoting their message. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber-attacks, there can be no assurance that we will not be the target of such attacks in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any security vulnerabilities.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil, natural gas, and NGLs that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such GHGs are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. It was widely expected that facilities required to obtain PSD permits for their GHG emissions would be required to also reduce those emissions according to “best available control technology” (“BACT”) standards. In its permitting guidance for GHGs, issued in November 2010, the EPA recommended options for BACT from the largest sources, which include improved energy efficiency, among others. The EPA also issued a final rule in July 2013 retaining the “tailored” permitting thresholds, opting not to extend GHG permitting requirements to smaller stationary sources at that time.
In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency, upholding the EPA’s GHG-related rules against challenges from various state and industry group petitioners. In October 2013, the United States Supreme Court in Utility Air Regulatory Group v. EPA, accepted a petition for certiorari to decide whether the EPA correctly determined that its regulation of GHGs from mobile sources triggered permitting requirements under the CAA for stationary sources that emit GHGs. In June 2014, the Supreme Court upheld a portion of the EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG BACT requirements, but ruled that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, the EPA issued a proposed rule to revise its PSD and Title V regulations applicable to GHGs in accordance with the decisions noted above, including proposing a de minimis level of GHG emissions below which BACT is not required. Depending on what the EPA does in a final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations and also adversely affect demand for the crude oil and natural gas that we produce.
In the past, Congress has considered various pieces of legislation to reduce emissions of GHGs. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such measures could include a carbon tax, which could result in additional direct costs to our operations. In the absence of such national legislation, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. For example, in February 2014, Colorado adopted rules directly regulating methane emissions from the oil and gas sector.
President Obama indicated that climate change and GHG regulation was a significant priority for his second term. The President issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector. In November 2013, the President released an Executive Order charging various federal agencies, including the EPA, with devising and pursuing strategies to improve the country’s preparedness and resilience to climate change. In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus as reflected in both the EPA’s OOOOa and BLM’s venting and flaring regulations both finalized in 2016 as noted above. In addition, a lawsuit has been filed by several northeastern states that would require the EPA to more stringently regulate methane emissions from the oil and gas sector. Finally, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the United States initially pledged to make a 26-28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020. The passage of legislation or executive and other initiatives, including those made to implement the pledges made in Paris, that limit emissions of GHGs from our equipment and operations could require us to incur costs to reduce GHG emissions, and it could also adversely affect demand for the crude oil, natural gas, and NGLs that we produce.
Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our

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operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance.
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
Federal, state and local laws and regulations relating to hydraulic fracturing could result in increased costs, additional drilling and operating restrictions or delays in the production of crude oil, natural gas, and NGLs, and could prohibit hydraulic fracturing activities.
Substantially all of our drilling uses hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale, coalbed, and tight sand formations. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the crude oil and natural gas industry in fracturing fluids under the SDWA, and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, including in the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. In March 2011, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. In June 2015, the EPA released a draft assessment of the potential impacts to drinking water resources from hydraulic fracturing for public comment and peer review. The assessment concluded that while there are mechanisms by which hydraulic fracturing can impact drinking water resources, there was no evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States. The EPA’s science advisory board subsequently questioned several elements and conclusions in the EPA’s draft assessment. In December 2016, the EPA released the final report on impacts from hydraulic fracturing activities on drinking water, concluding that hydraulic fracturing activities can impact drinking water resources under some circumstances and identified some factors that could influence these impacts. In addition, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.
The EPA has begun a Toxic Substances Control Act rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. The EPA has not indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the rulemaking. In October 2015, the EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Toxics Release Inventory (“TRI”) program under EPCRA. The EPA determined that natural gas processing facilities may be appropriate for addition to the scope of TRI and will conduct a rulemaking process to propose such action. On January 6, 2017, the EPA issued a proposed rule to include natural gas processing facilities in the TRI program.
The EPA also finalized major new CAA standards (New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels in August 2012. The standards require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators. Following administrative reconsideration of a portion of the 2012 rules, the EPA issued one set of final amendments to the rule in September 2013 related to storage tanks, and a second set of final amendments largely related to reduced emissions completion requirements in December 2014. Most key provisions in the new CAA standards became effective in 2015.
In January 2015, President Obama announced a comprehensive strategy to further reduce methane emissions from the oil and gas sector. As part of this strategy, in June 2016, the EPA finalized amendments to the 2012 NSPS Quad OOOO rules as well as new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. Known as NSPS OOOOa, the new rules impose, among other things, new requirements for leak detection and repair, control requirements at oil well completions, replacement of certain pneumatic pumps and controllers, and additional control requirements for gathering, boosting, and compressor stations. These additional methane reduction requirements are substantial and could increase future costs of our operations and require us to make modifications to our operations and install new equipment. In December 2016, the EPA began a process to regulate existing oil and natural gas facilities through a nationwide Information Collection Request (ICR). The ICR has two parts. First, the EPA is requesting general information about equipment at existing facilities from every operator throughout the country. Second, the EPA issued ICRs to a more targeted set of facilities, requesting more detailed information about these operations. During the fall of 2016, the EPA also issued final Control Techniques Guidelines (CTGs) for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Front Range 8-hour ozone non-attainment area. The ICR and CTG processes could culminate in additional controls being required for our existing sources, which may increase the future costs of operations and require modifications or the installation of new equipment.
On the same day the EPA finalized the NSPS OOOOa rules, it also finalized a rule regarding source determination and permitting requirements for the onshore oil and gas industry under the CAA. The final rule defines the term “adjacent,” which is one of three factors used to determine whether stationary sources (including oil and gas equipment and activities) are considered part of a source that is subject to major source permitting requirements under the CAA. Under this final rule, the oil and gas industry and our operations could be subject to increased permitting costs and more stringent control requirements.

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The EPA has also issued permitting guidance under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by the EPA and may therefore adversely affect even companies, such as PDC, that do not use diesel fuel in hydraulic fracturing activities.
Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. Most notably, in 2015 the U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing on federal and tribal lands. Due to pending litigation, however, the effective date of the rule has been postponed. In November 2016, BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules require additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drain federal minerals. In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. In May 2015, the U.S. Department of Transportation also issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing, and certification requirements.
In addition, the governments of certain states, including Colorado, Texas, and Ohio, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, seismic monitoring, well construction and well location requirements on hydraulic fracturing operations, more stringent notification or consultation processes, or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. For example, in January 2012, the Ohio Department of Natural Resources (“ODNR”) issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio in order to study the relationship between these wells and earthquakes reported in the area. As a result, ODNR promulgated new and more stringent regulations for certain underground injection wells, including requirements for a complete suite of geophysical logs, analytical interpretation of the logs, and enhanced monitoring and recording. More recently, in April 2014, ODNR shut down a number of well sites after a series of small earthquakes in northeast Ohio. After investigating the earthquakes and determining that the connection to hydraulic fracturing was “probable,” ODNR implemented new permit conditions, requiring that operators of well sites within three miles of a known fault must install sensitive seismic-monitoring equipment. Operators must also halt drilling if a seismic event exceeds 1.0 magnitude. In January 2014, the Railroad Commission of Texas finalized a “well integrity rule,” which updates the requirements for drilling and cementing wells, and includes new testing and reporting requirements. In October 2014, the Railroad Commission published a new rule governing the permitting of disposal wells that requires the submission of detailed information related to seismicity. This rule grants the Railroad Commission the ability to deny, modify, suspend or terminate the permit application or existing operating permit. Similar initiatives could spread to other states in which we operate. In addition, oil and gas producers may be subject to lawsuits brought by landowners for earthquake-related damages.
At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing. Beginning in 2012, voters in the cities of Fort Collins, Boulder, Longmont, Broomfield and Lafayette, Colorado approved bans of varying length on hydraulic fracturing within their respective city limits. In 2014, Boulder and Larimer county lower courts overturned the bans. The cities of Longmont and Fort Collins appealed the decisions. In August 2015, the Court of Appeals requested that the Colorado Supreme Court rule on the issue. The Colorado Supreme Court struck down the Fort Collins and Longmont bans in May 2016. Nonetheless, extended moratoria, like that put in place by Boulder County in December 2016, remain a threat to oil and gas operations in Colorado.
In Texas, voters in the City of Denton approved a local ordinance banning hydraulic fracturing in November 2014. In May 2015, the Texas legislature responded by enacting a statute preempting local government regulation of oil and gas activities.
In Ohio, several municipalities have passed hydraulic fracturing bans. In February 2015, the Ohio Supreme Court ruled that local governments cannot regulate hydraulic fracturing, finding that the State of Ohio has exclusive authority over regulating this activity under the State’s oil and gas preemption law, passed in 2004. In light of the recent Ohio Supreme Court decision, activists in Ohio are calling for the repeal of the oil and gas preemption law.
     In addition, lawsuits have been filed against unrelated third parties in several states, including Colorado and Ohio, alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil, natural gas, and NGL production activities using hydraulic fracturing techniques. Additional legislation, regulation, litigation, or moratoria could also lead to operational delays or lead us to incur increased operating or capital costs in the production of crude oil, natural gas, and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, litigation, and other initiatives cause a material decrease in the drilling of new wells or an increase in drilling costs, our profitability could be materially impacted.
Environmental and overall public scrutiny focused on the oil and gas industry is increasing. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local, and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Our exploration, development, production, and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage, and natural resource or other damages. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger

34



companies in the industry which can more easily capture economies of scale with respect to compliance. Failure to comply with these laws and regulations may result in various sanctions, including the suspension or termination of our operations or other operational impediments, and could subject us to administrative, civil, and criminal penalties. Moreover, public interest in environmental protection has increased in recent years-particularly with respect to hydraulic fracturing-and environmental organizations have opposed, with some success, certain drilling projects. These regulations also affect our operations, increase our costs of exploration and production, and limit the quantity of crude oil, natural gas, and NGLs that we can produce and market.
A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our properties. Additionally, the crude oil and natural gas regulatory environment could change in ways that substantially increase our financial and managerial compliance costs, increase our exposure to potential damages or limit our activities.
The election of President Trump has resulted in uncertainty with respect to the future regulatory environment affecting the oil and natural gas industry. This uncertainty may affect how our industry is regulated as well as the level of public interest in environmental protection and may result in new or different pressures being exerted. For example, public interest groups may increase their use of litigation as a means to continue to exert pressure on the oil and natural gas industry. Accordingly, while we expect regulatory and enforcement pressures on our business to continue at federal, state, and local levels, the nature, level, and source of such pressures may change.
In August 2015, we received the Information Request from the EPA. The Information Request seeks, among other things, information related to the design, operation, and maintenance of our production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses primarily on 46 of our production facilities and asks that we conduct certain sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016. We cannot predict the outcome of this matter at this time. Certain other operators in the area have been assessed penalties following similar information requests.
In a related Clean Air Act development, on October 1, 2015, the EPA announced its final rule lowering the existing 75 part per billion (“ppb”) NAAQS for ozone under the CAA to 70 ppb. The lower ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs. In addition, the state of Colorado’s non-attainment status was bumped up from “marginal” to “moderate” for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area. This increase in non-attainment status triggers significant additional obligations for the State under the CAA. In 2016, the state undertook rulemaking to address the new “moderate” status, culminating in, among others, the incorporation of two existing state-only requirements for oil and natural gas operations into the federally-enforceable State Implementation Plan ("SIP"). In 2017, as part of the federal Control Techniques Guideline (“CTG”) process for oil and natural gas, Colorado will begin a stakeholder and rulemaking effort to compare the CTGs to existing Colorado requirements to ensure they meet applicable federal requirements. This process could result in new or more stringent air quality control requirements applicable to our operations.
In addition, our activities are subject to regulations governing conservation practices, protection of wildlife and habitat, and protection of correlative rights by state governments. For example, the federal Endangered Species Act (“ESA”) and analogous state laws restrict activities that may adversely affect endangered and threatened species or their habitat. The designation of previously unidentified endangered or threatened species or their habitat in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. For example, the U.S. Fish and Wildlife Service in May 2014 proposed a rule to alter how that agency designates critical habitat. That rule was finalized in 2016 and, depending on how it is implemented, could expand the reach of the ESA.
At the state level the COGCC issued a rule in 2013 governing mandatory minimum setbacks between oil and gas wells and occupied buildings and other areas. Also in 2013, the COGCC issued rules that require baseline sampling of certain ground and surface water in most areas of Colorado and impose stringent spill reporting and remediation requirements. These new sampling requirements could increase the costs of developing wells in certain locations. Other regulatory amendments and policies recently adopted or being proposed by the COGCC address wellbore integrity, hydraulic fracturing, well control, waste management, spill reporting, development of large scale facilities in urban mitigation areas, and certain local government notice requirements. In addition to increasing costs of operation and permitting times, some of these rules and policies, as well as litigation by public interest groups challenging application of these rules or policies, could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues.
In addition, during 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to public health, safety, or welfare; require the COGCC to assess a penalty for each day there is evidence of a violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting from gross negligence or knowing and willful misconduct. In December 2014, the COGCC convened a hearing and adopted proposed amendments to its regulations to implement this new legislation and address certain other issues. Among other things, the amendments create a new process for calculating penalties, new standards for determining days of violation and penalty amounts, new restrictions on the use of informal enforcement procedures, and penalty reductions for voluntary disclosures. Following the adoption of this new penalty scheme, Colorado operators have experienced increased penalties for violations within COGCC’s jurisdiction.
In 2015, the COGCC convened hearings on regulations for large facilities located in urban mitigation areas. These new rules require best available technology and include required mitigations for emissions, flaring, fire, fluid leak detection, repair, reporting, automated well shut-in, storage tank pressure control, and proppant dust control. During these hearings, COGCC staff reported there would

35



also be site-specific mitigation requirements for noise, ground and surface water protection, visual impacts, and remote stimulation. After debate, the rule did not include duration limits despite an opinion from the State Attorney General Office that the COGCC possessed authority to impose duration limits under current and existing statutes.
In February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) finalized regulations imposing stringent new requirements relating to air emissions from oil and gas facilities in Colorado. The new rules impose significantly more stringent control, monitoring, recordkeeping, and reporting requirements than those required under comparable new federal rules. In addition, as part of the rule, the AQCC approved the direct regulation of hydrocarbon (i.e., methane) emissions from the Colorado oil and gas sector. Such state-only, direct regulation of methane (a greenhouse gas) from a single industry sector affected federal regulations from the EPA and the BLM, and continues to have the potential to adversely affect operations in Colorado as well as in other parts of the country. Along the same lines, local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies, in combination with other air quality-related studies that are national in scope, may result in the imposition of additional regulatory requirements on oil and gas operations.
CERCLA (or the “Superfund law”) and some comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. This includes potential liability for activities on properties we may currently own or operate upon, but where previous owner/operators caused the release of a hazardous substance. In addition, we may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been or threaten to be released into the environment. From time to time, we are involved in remediation activities at such properties.
Regulatory focus on worker safety and health regulations involving operating hazards in oil and natural gas exploration and production activities is also increasing. One example is a recent investigation by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain fuel transfer and related tasks. Several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. For example, in December 2015, the Department of Labor and the Department of Justice, Environment and Natural Resources Division released a Memorandum of Understanding (“MOU”), announcing an inter-agency effort to increase the enforcement of workplace safety crimes that occur in conjunction with environmental crimes. Consistent with this MOU, DOJ will look for additional felony violations (such as false statements and willful violations of certain standards) when prosecuting safety crimes in order to heighten prospective penalties and strengthen enforcement. In October 2016, OSHA issued a Regional Emphasis Program (REP) notice for the purpose of conducting safety and hazard inspections at oil and gas industry facilities in Region III (Pennsylvania and West Virginia). Similar notices could result in increased OSHA activities in the areas in which we operate.
Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Ohio. This could adversely affect our existing operations in the state and the economic viability of future drilling. Additional laws, regulations, or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flows, in addition to undermining the demand for the crude oil, natural gas, and NGLs we produce.
Certain federal income tax deductions currently available with respect to crude oil and natural gas and exploration and development may be eliminated as a result of future legislation.
Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include, but are not limited to (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, which could negatively affect our financial condition and results of operations. In addition, proposals are made from time to time in states where we operate to implement or increase severance or other taxes at the state level, and any such additional taxes would have similarly adverse effects on us.
Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability.
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following:
The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.
If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.
Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us.

36




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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

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

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

In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. This matter has been combined with the matter discussed above. The ultimate outcome related to these combined actions has not been determined at this time.

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

Action Regarding Firm Transportation Contracts

A group of 42 independent West Virginia natural gas producers has filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. ("Dominion"), certain entities affiliated with Dominion, and our subsidiary RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. RNG and Dominion have removed the case to the U.S. District Court for the Northern District of West Virginia and have filed pre-trial pleadings. At this time, the case has been remanded back to the state court. RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses.

Class Action Regarding 2010 and 2011 Partnership Purchases

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

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

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

ITEM 4. MINE SAFETY DISCLOSURES
    
Not applicable.

37



PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
    
Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth the range of high and low sales prices for our common stock based on intra-day trading for each of the periods presented:
 
 
 
High
 
Low
 
 
 
 
January 1 - March 31, 2015
$
55.47

 
$
37.62

April 1 - June 30, 2015
61.41

 
51.01

July 1 - September 30, 2015
61.55

 
41.17

October 1 - December 31, 2015
64.99

 
52.46

January 1 - March 31, 2016
60.56

 
42.68

April 1 - June 30, 2016
65.86

 
51.92

July 1 - September 30, 2016
71.00

 
50.12

October 1 - December 31, 2016
84.88

 
59.82


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

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

Period
 
Total Number of Shares Purchased (1)
 
Average Price Paid per Share
 
 
 
 
 
October 1 - 31, 2016
 
5,742

 
$
66.98

November 1 - 30, 2016
 

 
$

December 1 - 31, 2016
 
19,969

 
$
73.37

Total fourth quarter 2016 purchases
 
25,711

 
$
71.94

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


38



STOCKHOLDER PERFORMANCE GRAPH

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


pdce2016performancegraphv2.jpg

39




ITEM 6. SELECTED FINANCIAL DATA


 
Year Ended/As of December 31,

 
2016 (1)
 
2015
 
2014
 
2013
 
2012

 
(in millions, except per share data and as noted)
Statement of Operations (From Continuing Operations) (2):
 
 
 
 
 
 
 
 
 
 
Crude oil, natural gas and NGLs sales
 
$
497.4

 
$
378.7

 
$
471.4

 
$
340.8

 
$
228.0

Commodity price risk management gain (loss), net of actual settlements and changes in mark-to-market valuation adjustments
 
(125.7
)
 
$
203.2

 
310.3

 
(23.9
)
 
29.3

Total revenues
 
382.9

 
595.3

 
856.2

 
392.7

 
307.1

Income (loss) from continuing operations
 
(245.9
)
 
(68.3
)
 
107.3

 
(21.1
)
 
(19.4
)

 
 
 
 
 
 
 
 
 
 
Earnings (loss) per share from continuing operations:
 
 
 
 
 
 
 
 
 
 
Basic
 
$
(5.01
)
 
$
(1.74
)
 
$
3.00

 
$
(0.65
)
 
$
(0.70
)
Diluted
 
(5.01
)
 
(1.74
)
 
2.93

 
(0.65
)
 
(0.70
)

 
 
 
 
 
 
 
 
 
 
Statement of Cash Flows:
 
 
 
 
 
 
 
 
 
 
Net cash flows from:
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
486.3

 
$
411.1

 
$
236.7

 
$
159.2

 
$
174.7

Investing activities
 
(1,509.1
)
 
(604.3
)
 
(474.1
)
 
(217.1
)
 
(451.9
)
Financing activities
 
1,266.1

 
178.0

 
60.3

 
248.7

 
271.4

Capital expenditures from development and exploration activities (3)
 
436.9

 
599.5

 
623.8

 
384.7

 
344.2

Acquisitions of crude oil and natural gas properties
 
1,073.7

 

 

 
9.7

 
312.2


 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
4,485.8

 
$
2,370.5

 
$
2,331.1

 
$
1,991.7

 
$
1,777.9

Working capital
 
129.2

 
30.7

 
89.5

 
90.0

 
(67.6
)
Total debt, net of unamortized discount and debt issuance costs
 
1,044.0

 
642.4

 
655.5

 
593.9

 
637.5

Total equity
 
2,622.8

 
1,287.2

 
1,137.4

 
967.6

 
703.2


 
 
 
 
 
 
 
 
 
 
Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for Production Taxes):
 
 
 
 
 
 
 
 
 
 
Average sales price (excluding net settlements on derivatives)
 
$
22.43

 
$
24.64

 
$
50.72

 
$
52.23

 
$
46.85

Lease operating expenses
 
$
2.70

 
$
3.71

 
$
4.56

 
$
5.18

 
$
5.54

Transportation, gathering, and processing
 
$
0.83

 
$
0.66

 
$
0.49

 
$
0.79

 
$
0.56

Production taxes
 
$
1.42

 
$
1.20

 
$
2.76

 
$
3.33

 
$
2.86

Production taxes as a percent of sales
 
6.3
%
 
4.9
%
 
5.4
%
 
6.4
%
 
6.1
%
 
 
 
 
 
 
 
 
 
 
 
Production (MBoe):
 
 
 
 
 
 
 
 
 
 
Production from continuing operations
 
22,175.9

 
15,369.4

 
9,294.4

 
6,524.7

 
4,866.5

Production from discontinued operations
 

 

 
1,093.0

 
2,032.6

 
3,458.7

Total production
 
22,175.9

 
15,369.4

 
10,387.4

 
8,557.3

 
8,325.2

 
 
 
 
 
 
 
 
 
 
 
Total proved reserves (MMBoe) (4)(5)
 
341.4

 
272.8

 
250.1

 
265.8

 
192.8

______________
(1)
In 2016, we closed acquisitions in the Delaware Basin for aggregate consideration of approximately $1.76 billion.  See footnotes titled Properties and Equipment - Delaware Basin Acreage Acquisition and Business Combination to our consolidated financial statements included elsewhere in this report for further information regarding these acquisitions.
(2)
In 2014, we completed the sale of our ownership interest in PDCM.  Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations.  See footnote titled Divestiture and Discontinued Operations to our consolidated financial statements included elsewhere in this report for further information regarding this divestiture.
(3)
Includes impact of change in accounts payable related to capital expenditures.
(4)
Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe and 30 MMBoe as of December 31, 2013 and 2012, respectively. The joint venture that owned these reserves was sold in late 2014.
(5)
Includes total proved reserves related to our Piceance Basin and North Eastern Colorado ("NECO") assets of 14 MMBoe as of December 31, 2012. These assets were sold in 2013.

40




ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

SUMMARY

2016 Financial Overview of Operations and Liquidity

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

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

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

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

The net change in the fair value of unsettled derivative positions in 2016 was a loss of $333.8 million compared to a loss of $35.8 million in 2015. The decrease in the fair value of unsettled derivative positions is largely driven by the normal monthly settlements of the commodity derivative instruments in 2016. Additionally, the change in fair value was attributable to hedging positions entered into in 2016 at lower strike prices and the upward shift in the crude oil and natural gas forward curves that occurred during 2016 versus a downward shift in 2015.
Production tax expense increased to $31.4 million in 2016 from $18.4 million in 2015 due to increased production of 44 percent and higher overall sales proceeds. Additionally, we had a higher effective production tax rate in 2016 primarily from a reduction in ad valorem credits from the prior year to offset current year severance taxes due.
Impairment of crude oil and natural gas properties was $10.0 million in 2016 compared to $161.6 million in 2015. The 2016 impairments are a result of the write-off of certain leases that were no longer part of our development plan and to reflect the fair value of other land and buildings that are held for sale. The Utica Shale was the largest component of the 2015 write-down which included both producing and non-producing crude oil and natural gas properties.
General and administrative expense increased to $112.5 million in 2016 compared to $90.0 million in 2015. The increase was attributable to professional and transaction fees related to the Delaware Basin acquisitions and increases in payroll and employee benefits, as we increased our staff by nine percent over the course of 2016.
Depreciation, depletion, and amortization expense increased to $416.9 million in 2016 compared to $303.3 million in 2015, due to the increase in production volumes from year to year.
We recorded a provision for uncollectible notes receivable of $44.0 million in the first quarter of 2016 to impair a note receivable.
Interest expense increased to $62.0 million in 2016 from $47.6 million in 2015. The increase was primarily attributable to a $9.3 million charge for the bridge loan commitment related to our initial Delaware Basin acquisition, a $7.4 million increase in interest expense resulting from the issuance of our 2024 Senior Notes, and a $2.9 million increase in interest expense for the issuance of our 2021 Convertible Notes in September 2016. The increases were partially offset by a $5.1 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016.

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

41



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

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

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

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

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

Delaware Basin Acquisitions

Through a deliberate and disciplined process of searching for, and evaluating, a large-scale acquisition in a U.S. onshore basin that diversifies our operations and is capable of creating material long-term value-added growth, we recently acquired proved and unproved leasehold in the Delaware Basin in Reeves and Culberson Counties in Texas. The acquisition criteria focused on four key attributes:
top-tier acreage in core geologic positions;
significant drilling inventory with additional expansion through down spacing;
portfolio optionality for capital allocation and diversification; and
the ability to deliver long-term corporate accretion.

We believe the Delaware Basin acquisitions met these criteria.

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

The acquisitions were accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The details of the purchase price and the preliminary allocation of the purchase price for the first transaction are presented below (in thousands):
 
Acquisition costs:
 
       Cash, net of cash acquired
$
912,142

       Retirement of seller's debt
40,000

Total cash consideration
952,142

       Common stock, 9.4 million shares
690,702

      Other purchase price adjustments
1,026

  Total acquisition costs
$
1,643,870

 
 
Recognized amounts of identifiable assets acquired and liabilities assumed:
 
Assets acquired:
 
Current assets
$
8,201

Crude oil and natural gas properties - proved
216,000

Crude oil and natural gas properties - unproved
1,721,334

Infrastructure, pipeline, and other
32,590

Construction in progress
12,148

Goodwill
62,041

Total assets acquired
2,052,314

Liabilities assumed:
 
Current liabilities
(24,844
)
Asset retirement obligations
(3,705
)
Deferred tax liabilities, net
(379,895
)
Total liabilities assumed
(408,444
)
Total identifiable net assets acquired
$
1,643,870



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

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

2016 Drilling Overview

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


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The following table summarizes our 2016 drilling and completion activity:

 
 
 Gross
 
 Net
In-process as of December 31, 2015
 
102

 
63.4

Wells spud during the period
 
144

 
112.2

Wells turned-in-line to sales
 
(170
)
 
(120.2
)
Acquired in-process
 
5

 
4.9

In-process as of December 31, 2016
 
81

 
60.3


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

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

Wattenberg Field. The 2017 investment outlook of approximately $470 million in the Wattenberg Field anticipates a three to four-rig drilling program based on our current commodity price outlook. Approximately $460 million of our 2017 capital investment program is expected to be allocated to development activities, comprised of approximately $440 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder of the Wattenberg Field capital investment program is expected to be used for miscellaneous workover and capital projects. Wells in the Wattenberg Field typically have productive horizons at a depth of approximately 6,500 to 7,500 feet below the surface. In 2017, to help manage our priorities, we now anticipate spudding 137 and turning-in-line approximately 139 horizontal operated wells with lateral lengths of 5,000 to 10,000 feet.

Delaware Basin. Our 2017 investment outlook contemplates operating a two-rig to four-rig program in the Delaware Basin from time to time during the year. Total capital investment in the Delaware Basin is estimated to be $300 million, of which approximately $235 million is allocated to spud 31 and turn-in-line an estimated 26 wells.  Of the the 26 planned turn-in-lines, 14 are expected to have laterals of approximately 10,000 horizontal feet with an estimated 70 to 75 completion stages per well. Similarly spaced completion stages are anticipated for the remaining 12 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at a depth of approximately 9,000 to 11,000 feet below the surface. Based on the timing of our operations and the requirements to hold acreage, we may adapt our capital investment program to drill wells in addition to those currently anticipated, as we are continuing to analyze terms of the leaseholds related to our recent acquisitions of properties in the basin. We plan to invest approximately $35 million for leasing, seismic, and technical studies with an additional $30 million for midstream-related projects including gas connections, salt water disposal wells, and surface location infrastructure.

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







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Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results from continuing operations:
 
Year Ended December 31,
 
 
 
 
 
 
 
Percent Change
 
2016
 
2015
 
2014
 
2016-2015
 
2015-2014
 
(dollars in millions, except per unit data)
 
 
 
 
Production
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
8,728

 
6,984

 
4,322

 
25.0
 %
 
61.6
 %
Natural gas (MMcf)
51,730

 
33,302

 
19,298

 
55.3
 %
 
72.6
 %
NGLs (MBbls)
4,826

 
2,835

 
1,756

 
70.2
 %
 
61.4
 %