Document


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, 2017

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
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12085564&doc=20
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. T

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
                  
                   Emerging growth company  o

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

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, 2017 was $2.8 billion (based on the closing price of $43.11 per share as of the last business day of the fiscal quarter ending June 30, 2017).

As of February 15, 2018, there were 65,965,374 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 2018 Annual Meeting of Stockholders.




PDC ENERGY, INC.
2017 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," the "Company," "we," "us," "our," or "ours" refer to the registrant, PDC Energy, Inc., our wholly-owned subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships.

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 expect, anticipate, intend, plan, believe, seek, estimate 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 zones 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; our anticipated sale of our Utica Shale assets; certain accounting and tax change impacts; midstream capacity and related curtailments; and the closing of pending, and the nature of future, transactions.    

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or 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 and prices for products we produce;
volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
reductions in the borrowing base under our revolving credit facility;
impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement 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;
production decline rates from our wells being greater than expected;
timing and extent of our success in discovering, acquiring, developing, and producing reserves;
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of crude oil and natural gas wells;
losses from our gas marketing business exceeding our expectations;

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difficulties in integrating our operations as a result of any significant acquisitions and acreage exchanges;
increases or changes in expenses;
availability of supplies, materials, contractors, and services that may delay the drilling or completion of our wells;
potential losses of acreage or zones due to partial or complete lease expirations or otherwise;
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;
possibility that the sale of the Utica Shale properties will not close as expected;
competition within the oil and gas industry;
availability and cost of capital;
our success in marketing crude oil, natural gas, and NGLs;
effect of crude oil and natural gas derivatives activities;
impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;
cost of pending or future litigation;
effect that acquisitions we may pursue have on our capital requirements;
our ability to retain or attract senior management and key technical employees; and
success of strategic plans, expectations and objectives for our future operations.
 
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under 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, explores, and develops properties for the production of crude oil, natural gas, and NGLs. Our primary operations are located in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused on the Niobrara and Codell formations and our Delaware Basin operations are currently focused on the Wolfcamp zones. We also have operations in the Utica Shale in Southeastern Ohio; however, in February 2018, we entered into a definitive purchase and sale agreement ("PSA") for the sale of these properties for net cash proceeds of approximately $40.0 million, subject to certain customary closing adjustments. This transaction is expected to close in the first quarter of 2018.

As of December 31, 2017, we own an interest in approximately 2,800 gross (2,300 net) productive wells, of which approximately 32 percent are horizontal. We operate 87 percent of the wells in which we have an interest. We produced 31.8 MMBoe in 2017, a 44 percent increase compared to 2016, including 4.2 MMBoe from the Delaware Basin assets that we acquired in December 2016. For the month ended December 31, 2017, we maintained an average production rate of 97 MBoe per day, representing a 33 percent increase from December 2016. 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 $880.7 million as of December 31, 2017. Our leverage ratio as of December 31, 2017, as defined in our revolving credit facility agreement, was 1.9 to 1.0. As of December 31, 2017, we had 452.9 MMBoe of proved reserves, 32 percent of which are proved developed reserves. Approximately 58 percent of our reserves at December 31, 2017 are liquids, which includes crude oil and NGLs. Our 452.9 MMBoe of total proved reserves as of December 31, 2017, represented an increase of 111.5 MMBoe, or 33 percent, relative to December 31, 2016. The additions to our proved reserves were primarily a result of extending the average lateral length of newly-drilled and expected future wells, combined with an increase in our working interest ownership in wells in areas with established reserves, and the addition of proved undeveloped locations in the Delaware Basin.

On January 5, 2018, we closed an acquisition of properties from Bayswater Exploration and Production, LLC and certain related parties in the core Wattenberg Field (the "Bayswater Acquisition") for approximately $186 million, subject to certain customary post-closing adjustments. In addition to the approximately $186 million of cash paid at closing, we invested approximately $15 million during 2017 to complete certain drilled uncompleted wells ("DUCs") acquired in the transaction.


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Our Strengths

Multi-year project inventory in premier crude oil, natural gas, and NGL plays.  We have a significant operational presence in two premier U.S. onshore basins, the Wattenberg Field in Weld County, Colorado, and the Delaware Basin in Reeves and Culberson Counties, Texas.  The company has identified a significant inventory of horizontal drilling locations in each basin which will allow us to continue to grow our proved reserves and production at attractive rates of return based on our current internal long-term commodity price projections and our current expected cost structure. Our 2018 drilling and completion operations are expected to focus on the Kersey area of the Wattenberg Field and in our oilier eastern and north central areas of the Delaware Basin, where we expect to deliver our strongest economic results.
 
In the Wattenberg Field, we have identified a gross operated inventory of approximately 1,500 horizontal drilling locations, including locations acquired in the Bayswater Acquisition, that consist of an average lateral length of approximately 6,300 feet per well.  Our Wattenberg Field horizontal drilling locations have been substantially de-risked through multiple years of successful development from the field.  In the Delaware Basin, we have identified a gross operated inventory of approximately 450 horizontal Wolfcamp drilling locations, primarily within our oilier eastern and north central focus areas, that consist of an average lateral length of approximately 7,500 feet per well.  Some of these 450 locations are subject to a higher degree of uncertainty as they reflect assumptions primarily related to future downspacing that we are either in the process of testing, or have not yet tested.  Our other Delaware Basin leaseholds that are not currently in our primary focus area contain an estimated 240 additional potential horizontal Wolfcamp drilling locations that typically have a higher gas to oil ratio, contain less contiguous acreage for long lateral development, or may require additional technical assessments.  We believe that our inventory in the Delaware Basin may increase over time, depending upon, among other variables, successful trades to consolidate leaseholds, additional exploration and development activity in other potential zones, service cost efficiencies, and improved commodity and netback pricing. 

Strong liquidity position. As of December 31, 2017, we had a total liquidity position of $880.7 million, comprised of $180.7 million of cash and cash equivalents and $700.0 million available for borrowing under our revolving credit facility. In November 2017, we issued $600 million principal amount of 5.75 percent unsecured senior notes due in 2026 (the "2026 Senior Notes"). The net proceeds from the offering were used to redeem our $500 million 7.75 percent senior notes due in 2022 (the "2022 Senior Notes"), fund a portion of the Bayswater Acquisition, which closed in early January 2018, and for general corporate purposes. If the Bayswater Acquisition had closed in December 2017, our liquidity position as of December 31, 2017 would have been approximately $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. Having drilling opportunities in both the Wattenberg Field and the Delaware Basin allows us to allocate capital between the two basins to diversify our risk. We believe this will improve overall economic results and drive our future production and reserve growth. Additionally, we believe the geographical diversity of our portfolio aids in the mitigation of risks associated with a single dominant producing area, as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, 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 and consolidating largely concentrated acreage positions with high working interests, we operate and manage approximately 87 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 significantly enhanced as a result of our 2016 and 2017 acreage exchanges and the Bayswater Acquisition, 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 our 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.

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In the Delaware Basin, our average working interest in our properties that we operate is approximately 90 percent. We own and operate certain midstream assets in the Delaware Basin and believe this will allow for timely system expansion, well connections, fresh water supply for completion operations, and produced water disposal. Our leasehold in the Delaware Basin requires a more active drilling program and we have less flexibility than we do in the Wattenberg Field, in terms of managing lease expiration issues. In some cases, continuous operations will be required to maintain the underlying leasehold in the Delaware Basin. However, with our high percentage of operated leasehold in the area, we expect to have adequate control over the location and pace of our development to manage lease expirations and meet our drilling obligations in the central and eastern parts of the basin. See Item 1A. Risk Factors - 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.
 
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 operations. Our efficiencies have historically been 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 2017, approximately 65 percent of our horizontal well spuds were mid- or extended-reach laterals that ranged from approximately 6,000 to 10,000 horizontal feet in length. We also use 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 2,700 feet drilled per day in 2017 from approximately 2,200 feet drilled per day in 2016.

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. This is an important part of our strategy and 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.

Commodity derivative program. Our active use of commodity derivative instruments to protect our investment returns and cash flows was particularly important through the recent commodity price downturns. We have continued this program and entered into commodity derivative instruments to mitigate a portion of our short-term future exposure to commodity price fluctuations, including fixed-price swaps, crude oil and natural gas collars, basis swaps, and rollfactor swap contracts. 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 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.

As of December 31, 2017, we had commodity derivatives positions covering approximately 11.9 MMBbls and 6.6 MMBbls of crude oil production for 2018 and 2019, respectively. As of the same date, we had hedged approximately 56.5 Bcf of natural gas and 1.1 MMBbls of propane for 2018.  The details of these transactions are described in Item 7a. - Quantitative and Qualitative Disclosures About Market Risk.

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, strategy, and general operations, and has helped us continue our growth through periods of commodity price pressure and cost inflation, and other challenging environments.


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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 through horizontal drilling. Our operational focus is concentrated within 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 exchanges 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.

In 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area of the Wattenberg Field, creating two development areas that we refer to as Prairie and Plains. Both transactions involved the exchange of leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing the transactions, we received an aggregate of approximately 15,900 net acres in exchange for an aggregate of approximately 16,200 net acres. The difference in net acres is primarily due to variances in working and net revenue interests and in midstream contracts.

As referenced above, we closed the Bayswater Acquisition in January 2018, acquiring approximately 7,400 net acres, 24 operated horizontal wells that were either DUCs or in-process wells at the time of closing and an estimated 220 gross drilling locations at the time of closing.

Development drilling
 
The following map presents the general locations of our development and production activities as of December 31, 2017:
 
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12085564&doc=30
        
(1) In February 2018, we entered into a PSA to sell the Utica Shale properties.


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Our leasehold interests cover properties with developed and undeveloped crude oil, natural gas, and NGLs resources. We own approximately 2,800 gross (2,300 net) wells in our two primary operating basins. Our 2018 capital investment program, which contemplates expenditures of between $850 million and $920 million, is primarily focused on continued execution in the Wattenberg Field and Delaware Basin using three drilling rigs and one completion crew in each basin throughout the year.

Based on our current production forecast for 2018 and assuming an average $57.50 New York Mercantile Exchange ("NYMEX") crude oil price for the year and a $3.00 NYMEX natural gas price, we expect 2018 capital investments to exceed our 2018 cash flows from operations by approximately less than $90 million. We anticipate that the proceeds received from the sale of our Utica Shale assets and a midstream dedication agreement (see the footnote titled Subsequent Events to the consolidated financial statements included elsewhere in this report), will fund approximately two-thirds of this outspend. We expect this outspend to occur during the first half of 2018, with cash flows exceeding capital investment during the second half of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to decrease by the end of 2018 based on production and operational cash flow growth. However, a significant deterioration in commodity prices could negatively impact our results of operations, financial condition, and future development plans. We may increase or decrease our 2018 capital investment program during the year as a result of, among other things, changes in commodity prices or our 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, amounts invested may further exceed our cash flow from operations.
 
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the core Wattenberg Field, which is further delineated between the Kersey, Prairie and Plains development areas. We plan to drill standard-reach lateral (“SRL”), mid-reach lateral (“MRL”), and extended-reach lateral (“XRL”) wells in 2018, the majority of which will be in the Kersey 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 2018, we anticipate spudding and turning-in-line between approximately 135 to 150 operated wells, as outlined below:
 
 
SRL
 
MRL
 
XRL
Estimated average lateral length (in feet)
 
4,200
 
6,900
 
9,500
Expected drilling days (spud-to-spud)
 
6
 
8
 
10
Estimated percentage of 2018 wells spud
 
25%
 
45%
 
30%
Estimated percentage of 2018 wells turned-in-line
 
50%
 
35%
 
15%
Estimated cost per well (in millions)
 
$2.6
 
$3.5
 
$4.4

Our 2018 capital investment program for the Wattenberg Field is approximately $470 million to $500 million, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. The remainder of the Wattenberg Field capital investment program is expected to be used for non-operated drilling, land, and miscellaneous workover and capital projects.


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The following map presents the general locations of our development areas in the Niobrara and Codell plays of the Wattenberg Field as of December 31, 2017:

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12085564&doc=26

Delaware Basin. Our 2018 capital investment program for the Delaware Basin contemplates operating at a three-rig pace throughout the year. Total capital investment in the Delaware Basin for 2018 is expected to be approximately $380 million to $420 million, of which approximately 75 percent is allocated to both spud and turn-in-line approximately 25 to 30 operated wells.  Based on the timing of our operations and requirements to hold acreage, we may elect to drill wells different from or in addition to those currently anticipated, as we are continuing to analyze the terms of the relevant leases. Our anticipated Delaware Basin drilling program is outlined below:
 
SRL
 
MRL
 
XRL
Estimated average lateral length (in feet)
5,000
 
8,000
 
10,000
Expected drilling days (spud-to-rig release)
30
 
31
 
36
Estimated percentage of 2018 wells spud
10%
 
40%
 
50%
Estimated percentage of 2018 wells turned-in-line
25%
 
45%
 
30%
Estimated cost per well (in millions)
$9.2
 
$10.8
 
$13.2

Wells in the Delaware Basin typically have productive horizons at depths of approximately 8,000 to 11,000 feet below the surface. We plan to use approximately 10 percent of our budgeted capital for leasing, non-operated capital, seismic, and technical studies, with the remaining 15 percent for midstream-related projects, including oil and gas gathering systems and water supply and disposal systems.
 










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The following map presents the general locations of our Wolfcamp formation development areas in the Delaware Basin as of December 31, 2017:

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12085564&doc=19

Utica Shale.  In 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as of December 31, 2017. In February 2018, we entered into a PSA to sell these properties for net cash proceeds of approximately $40.0 million, subject to certain customary closing adjustments.

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 exchange acreage with other producers or complete small bolt-on acquisitions in order to optimize our portfolio by consolidating and concentrating on 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. We believe the Bayswater Acquisition and the acreage exchanges executed in 2016 and 2017 met the criteria. Any acquisition activity we may pursue in 2018 is expected to be focused on the Wattenberg Field and Delaware Basin.

Selective exploration
 
Historically, we have pursued a disciplined exploration program intended to replenish our portfolio of potential drilling locations and position us for production and reserve growth in future years. When doing so, we attempt 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 recent exploration activity has been in the Delaware Basin as there are multiple zones that have not seen development sufficient to record proved reserves. We believe such zones could provide

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us with additional potential drilling locations and/or proved reserves, based upon the results of our exploratory wells. See the footnote titled Properties and Equipment - Suspended Well Costs to our consolidated financial statements included elsewhere in this report for additional details regarding our exploratory wells.

Business Segments

We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning in 2017, our gas marketing segment did not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented.

The 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 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 crude oil and natural gas wells, which are then turned-in-line to production. 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. and DCP Midstream, LP ("DCP"). Sales to each of these parties constituted more than 10 percent of our 2017 revenues. Given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any purchaser or the aggregate loss of several customers could be managed by selling to alternative purchasers. See Part II, Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, Summary Operating Results, for sales, pricing, production, and operating cost data.




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Properties

Productive Wells

The following table presents our productive wells:

    
 
 
Productive Wells
 
 
As of December 31, 2017
 
 
Crude Oil
 
Natural Gas
 
Total
Operating Region/Area
 
 Gross
 
 Net
 
Gross
 
 Net 
 
 Gross
 
 Net
Wattenberg Field (1)
 
811

 
551.6

 
1,893

 
1,660.7

 
2,704

 
2,212.3

Delaware Basin (2)
 
47

 
43.1

 
4

 
4.0

 
51

 
47.1

Utica Shale (3)
 
27

 
22.2

 
3

 
3.0

 
30

 
25.2

Total productive wells
 
885

 
616.9

 
1,900

 
1,667.7

 
2,785

 
2,284.6

_________    
(1) Additionally, the Bayswater Acquisition, which closed in January 2018, included 56 gross (19.7 net) productive crude oil
wells and 164 gross (118.7 net) productive natural gas wells.
(2) During 2017, we submitted applications to the Railroad Commission of Texas ("RRC of Texas") requesting that the
designation for 20 wells in the Delaware Basin be changed from crude oil to natural gas per their GOR analysis. The
applications are currently pending review by the RRC of Texas.         
(3) In February 2018, we entered into a PSA to sell the Utica Shale properties.
    
Proved Reserves

The following table presents our proved reserve estimates as of December 31, 2017, 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, 2017
 
 
 
 
 
 
 
Proved Reserves (MMBoe)
 
% of Total Proved Reserves
 
% Proved Developed
 
% Liquids
 
Proved Reserves to Production Ratio (in years)(1)
 
2017 Production (MBoe)
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
350.8
 
77
%
 
33
%
 
55
%
 
13.1
 
26,815

Delaware Basin
97.9
 
22
%
 
23
%
 
67
%
 
23.4
 
4,184

Utica Shale (2)
4.2
 
1
%
 
100
%
 
51
%
 
5.1
 
831

Total proved reserves
452.9
 
100
%
 
32
%
 
58
%
 
14.2
 
31,830

_________
(1) Based on production during 2017.
(2) In February 2018, we entered into a PSA to sell the Utica Shale properties.
          
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. Our proved reserves in the Wattenberg Field and Utica Shale as of December 31, 2017 were estimated by Ryder Scott and our reserves in the Delaware Basin as of that date 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 accounting records,

10



available geological and reservoir data, and production performance data. The internal team compiles the reviewed data and forwards the data to Ryder Scott and NSAI, as applicable.

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, or 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 prepared by Ryder Scott and NSAI and reviewed by our engineering staff and management prior to issuance by those 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 the location’s initial booking date. Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted based on 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:

 
 
As of December 31,
 
 
2017
 
2016
 
2015
 
 
 
 
 
 
 
Crude oil (SEC NYMEX - $/Bbl)
 
$
51.34

 
$
42.75

 
$
50.28

Natural gas (SEC NYMEX - $/MMBtu)
 
$
2.98

 
$
2.48

 
$
2.59


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 geologic 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 provided with our consolidated financial statements included elsewhere in this report.


11



The following tables provide information regarding our estimated proved reserves:
 
As of December 31,
 
2017
 
2016
 
2015
Proved reserves
 
 
 
 
 
Crude oil and condensate (MMBbls)
155

 
118

 
99

Natural gas (Bcf)
1,154

 
834

 
661

NGLs (MMBbls)
106

 
84

 
64

Total proved reserves (MMBoe)
453

 
341

 
273

Proved developed reserves (MMBoe)
143

 
98

 
70

Estimated undiscounted future net cash flows (in millions) (1)
$
5,453

 
$
2,681

 
$
2,259

 
 
 
 
 
 
Standardized measure (in millions)
$
2,880

 
$
1,421

 
$
1,097

 
 
 
 
 
 
PV-10 (in millions) (2) (3)
$
3,212

 
$
1,675

 
$
1,338

___________
(1)
Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI, of approximately $6.2 billion, $3.3 billion, and $2.8 billion as of December 31, 2017, 2016, and 2015, respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.7 billion, $0.6 billion, and $0.5 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 II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure.
(3)
Of the PV-10 amounts, $31.6 million, $21.6 million, and $26.6 million represent amounts attributable to our Utica Shale properties as of December 31, 2017, 2016, and 2015, respectively. In February 2018, we entered into a PSA to sell these properties.
 
The following table presents our estimated proved developed and undeveloped reserves by category and area:

 
 
As of December 31, 2017
Operating Region/Area
 
Crude Oil and Condensate (MMBbls)
 
Natural Gas
(Bcf)
 
NGLs
(MMBbls)
 
Crude Oil
Equivalent
(MMBoe)
 
Percent
Proved developed
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
36.3

 
301.9

 
29.2

 
115.9

 
26
%
Delaware Basin
 
9.5

 
50.6

 
4.9

 
22.9

 
5
%
Utica Shale (1)
 
1.0

 
12.8

 
1.1

 
4.2

 
1
%
Total proved developed
 
46.8

 
365.3

 
35.2

 
143.0

 
32
%
Proved undeveloped
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
69.7

 
644.5

 
57.8

 
234.9

 
51
%
Delaware Basin
 
38.3

 
144.5

 
12.7

 
75.0

 
17
%
Total proved undeveloped
 
108.0

 
789.0

 
70.5

 
309.9

 
68
%
Total proved reserves
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
106.0

 
946.4

 
87.0

 
350.8

 
77
%
Delaware Basin
 
47.8

 
195.1

 
17.6

 
97.9

 
22
%
Utica Shale (1)
 
1.0

 
12.8

 
1.1

 
4.2

 
1
%
Total proved reserves
 
154.8

 
1,154.3

 
105.7

 
452.9

 
100
%
 
 
 
 
 
 
 
 
 
 
 
________    
(1) In February 2018, we entered into a PSA to sell the Utica Shale properties.
    



12



We have performed an analysis of our proved reserve estimates as of December 31, 2017 to present sensitivity associated with a lower crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. Replacing the 2017 NYMEX price for crude oil used in estimating our reported proved reserves with $30.00 as shown on the table below, and leaving all other parameters unchanged, results in changes to our estimated proved reserves as shown.

 
Pricing Scenario - NYMEX
 
Crude Oil (per Bbl)
 
Natural Gas (per MMBtu)
 
Proved Reserves (MMBoe)
 
% Change from December 31, 2017 Estimated Reserves
PV-10 (in Millions)
PV-10 % Change from December 31, 2017 Estimate Reserves
2017 SEC Reserve Report (1)
$
51.34

 
$
2.98

 
452.9

 

$
3,212.0


Alternate Price Scenario
$
30.00

 
$
2.98

 
424.9

 
(6
)%
$
1,021.0

(68
)%
__________
(1)
These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently in the alternate 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.

Developed and Undeveloped Acreage

The following table presents our developed and undeveloped lease acreage:
 
 
As of December 31, 2017
 
 
Developed
 
Undeveloped
 
Total
Operating Region/Area
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wattenberg Field (1) (2)
 
114,200

 
109,200

 
8,800

 
7,600

 
123,000

 
116,800

Delaware Basin (3)
 
31,900

 
29,500

 
36,600

 
30,400

 
68,500

 
59,900

Utica Shale (4)
 
5,300

 
4,500

 
44,600

 
41,100

 
49,900

 
45,600

 Total acreage
 
151,400

 
143,200

 
90,000

 
79,100

 
241,400

 
222,300

 
 
 
 
 
 
 
 
 
 
 
 
 
___________
(1) Of the amounts shown, 91,600 gross (87,400 net) developed lease acres and 4,700 gross (3,900 net) undeveloped
lease acres are associated with our approximately 1,500 operated horizontal Wattenberg Field drilling locations targeting
the Niobrara or Codell plays. The remaining acres are associated with other zones within the field that we do not
currently estimate to be economic to develop; therefore, we have not currently identified any potential drilling
locations on these acres.
(2) The Bayswater Acquisition, which closed in January 2018, included 9,100 gross (7,200 net) developed lease acres and
200 gross and net undeveloped lease acres, providing us a total of 132,300 gross (124,200 net) total acres in the Wattenberg
Field.
(3) See below regarding Culberson County acreage expirations.
(4) In February 2018, we entered into a PSA to sell the Utica Shale properties.

13




Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held by production. In the Wattenberg Field, the leaseholds at risk to expire in 2018, 2019, and 2020 are not material. 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 development 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, when development plans dictate or when our analysis of the acreage supports such a decision, we will make any necessary bonus extension payments, changes to drilling schedules, or will seek to renew or re-lease in order to retain the leases in the eastern and central areas. However, the payments necessary to extend or retain certain leases may be significant and we may not be successful in such efforts or may elect not to pursue them. We expect that approximately 3,200 gross and net Delaware Basin acres in our western area block located in Culberson County will expire during the first half of 2019 as a result of normal course lease expirations that we do not anticipate renewing due to an expected lack of economically recoverable production quantities. These acres were impaired to an immaterial value in 2017. In total for the Delaware Basin, approximately 12 percent, 35 percent, and two percent of the leaseholds are at risk to expire in 2018, 2019, and 2020, respectively. See Item 1A. Risk Factors - 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.

14



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 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. 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. This normal in-process inventory also exists in the development of our Delaware Basin leasehold.

 
 
Gross Development Well Drilling Activity
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
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
 
130

 
87

 

 
140

 
64

 
2

 
136

 
78

 
4

Wattenberg Field, non-operated wells
 
12

 
14

 
1

 
24

 
12

 

 
58

 
19

 

Delaware Basin
 
11

 
18

 

 
1

 
5

 

 

 

 

Utica Shale (2)
 

 

 

 
5

 

 

 
4

 
5

 

Total gross development wells
 
153

 
119


1

 
170

 
81

 
2

 
198

 
102

 
4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(1)
Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
(2)
In February 2018, we entered into a PSA to sell the Utica Shale properties.
 
 
Net Development Well Drilling Activity
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
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
 
112.8

 
80.1

 

 
109.7

 
52.7

 
1.7

 
110.8

 
54.6

 
2.7

Wattenberg Field, non-operated wells
 
1.6

 
2.6

 
0.1

 
5.0

 
2.8

 

 
9.3

 
4.3

 

Delaware Basin
 
10.5

 
10.4

 

 
1.0

 
4.8

 

 

 

 

Utica Shale (2)
 

 

 

 
4.5

 

 

 
3.0

 
4.5

 

Total net development wells
 
124.9

 
93.1

 
0.1

 
120.2

 
60.3

 
1.7

 
123.1

 
63.4

 
2.7

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(1)
Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
(2)
In February 2018, we entered into a PSA to sell the Utica Shale properties.





15



 
 
Gross Exploratory Well Drilling Activity
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Operating Region/Area
 
Productive
 
In-Process
 
Non-Productive
 
Productive
 
In-Process
 
Non-Productive
 
Productive
 
In-Process
 
Non-Productive
Wattenberg Field, operated wells
 

 

 

 

 

 

 

 

 

Wattenberg Field, non-operated wells
 

 

 

 

 

 

 

 

 

Delaware Basin
 
5

 
3

 
2

 

 

 

 

 

 

Utica Shale
 

 

 

 

 

 

 

 

 

Total gross development wells
 
5

 
3

 
2

 

 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 
Net Exploratory Well Drilling Activity
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Operating Region/Area
 
Productive
 
In-Process
 
Non-Productive
 
Productive
 
In-Process
 
Non-Productive
 
Productive
 
In-Process
 
Non-Productive
Wattenberg Field, operated wells
 

 

 

 

 

 

 

 

 

Wattenberg Field, non-operated wells
 

 

 

 

 

 

 

 

 

Delaware Basin
 
3.1

 
2.8

 
2.0

 

 

 

 

 

 

Utica Shale
 

 

 

 

 

 

 

 

 

Total gross development wells
 
3.1

 
2.8

 
2.0

 

 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

    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 87,000 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.

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

Governmental Regulation

The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us.

16




Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are subject to a variety of rules and regulations concerning drilling permits, the spacing and density of wells, rates of production, water discharge, prevention of waste, bonding requirements, surface use and restoration and well plugging and abandonment. The primary state-level regulatory authority regarding these matters is the Colorado Oil and Gas Conservation Commission (the “COGCC”). For example, prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. Similarly, our operations must comply with rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some states, such as Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as Texas, rely primarily or exclusively on voluntary pooling of lands and leases. In states, such as Texas, where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in circumstances where we do not own all of the leases in the proposed unit. State laws may also establish maximum rates of production from crude oil and natural gas wells, prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. Leases covering state or federal lands often include additional regulations and conditions. These laws, regulations and conditions can limit the number of wells we can drill and the permissible production from successful wells and can increase our costs.

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. Rates and charges for the transportation of natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Natural gas pipeline companies hold certificates of public convenience and necessity issued by FERC authorizing ownership and operation of certain pipelines, facilities and properties. 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. 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.

Transportation and safety of natural gas is also subject to regulation by the United States Department of Transportation under the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2012.
The availability, terms, and cost of transportation affect our natural gas sales. 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. Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are subject to state regulation, however, which includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements.
Environmental Matters

Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes.

Hazardous Substances and Wastes

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. In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a coalition of environmental groups. The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste. The EPA must complete its review and make its decision regarding revision by March 2019. If the EPA chooses to revise the applicable RCRA regulations, it must sign a notice taking final action related to the new regulation by July 2021.

17




We currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes 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 by us or prior owners or operators of such properties, we could be subject to liability under 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. 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 or remediation to prevent future contamination 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.
In October 2015, the EPA 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 the Emergency Planning and Community Right-to-Know Act.

Hydraulic Fracturing

Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development 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, but is also the subject of various other regulatory initiatives at the federal, state and local levels.

Federal Regulation

Beginning in 2012, the EPA implemented Clean Air Act (“CAA”) standards (New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels. 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.

In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act ("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.

In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act pursuant to which it will collect extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors.

The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), 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 BLM rescinded the rule in December 2017.

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.

In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. 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

18



and similar 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.
  
State Regulation

Each of the states in which we currently operate, 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 and/or more stringent notification or consultation processes. The Ohio Department of Natural Resources (“ODNR”) has required the suspension of certain activities relating to hydraulic fracturing in the past in response to earthquakes occurring near development operations. Similarly, the Railroad Commission of Texas has implemented rules requiring the submission of detailed information related to seismicity in connection with permit applications. In addition, some states have banned the treatment of fracturing wastewater at publicly owned treatment facilities.
    
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”).

Concerns about hydraulic fracturing have contributed to support for proposed ballot initiatives in Colorado that would dramatically limit the areas of the state in which drilling would be permitted to occur. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us.

Local Regulation

Various local and municipal bodies in each of the states in which we operate have purported to impose drilling moratoria and other restrictions on hydraulic fracturing activities. The cities purporting to ban hydraulic fracturing currently include Fort Collins, Boulder, Lafayette, Longmont and Brighton in Colorado and Denton in Texas. Ballot initiatives have been proposed in Colorado that would authorize local governmental authorities to implement hydraulic fracturing bans or other regulations. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us.

Private Lawsuits

Lawsuits have been filed against other operators in several states, including Colorado and Ohio, alleging contamination of drinking water as a result of hydraulic fracturing activities.

Greenhouse Gases

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 such emissions 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.
In the past, Congress has considered proposed 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. In addition, 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. In February 2014 and November 2017, Colorado adopted rules regulating methane emissions from the oil and gas sector.
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 Paris Agreement). In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement.


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Air Quality

Our operations are subject to the 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 state governments 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. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding the Clean Air Act Section 114 Information Request that we received from the EPA in August 2015.
In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers, and additional control requirements for gathering, boosting, and compressor stations. The EPA has proposed a two-year stay of the effective dates of several requirements of the rules. Also in 2016, the EPA issued guidelines for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-Hour Non-Attainment (“Denver Metro/North Front Range NAA”) area discussed below.
In November 2016, the 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 drains federal minerals. The rules are the subject of litigation in federal court. In December 2017, the BLM published a rule to temporarily suspend or delay certain rule requirements until January 2019; that rule is also the subject of litigation in federal court.
In 2016, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro/North Front Range NAA area from “marginal” to “moderate” under the 2008 national ambient air quality standard (“NAAQS”). This increase in non-attainment status triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in November 2017 that are applicable to our operations. The Denver Metro/North Front Range NAA is at risk of being reclassified again to “serious” if it does not meet the 2008 NAAQS by 2018 or obtain an extension of the deadline from the EPA. A “serious” classification would trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements applicable to our operations and significant costs and delays in obtaining necessary permits.
State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public Health and Environment’s Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping, and reporting matters.
Water Quality
 
The federal Clean Water Act (“CWA”) and analogous state laws impose strict controls concerning 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 United States. The scope of what areas constitute jurisdictional waters of the United States regulated under the CWA is currently the subject of ongoing litigation and related administrative matters that are not expected to be resolved for several years.  In January 2017, the Army Corps of Engineers issued revised and renewed streamlined general nationwide permits that are available to satisfy permitting requirements for certain work in streams, wetlands and other waters of the United States under Section 404 of the CWA and the Rivers and Harbors Act.  The new nationwide permits took effect in March 2017, or when certified by each state, whichever was later.  The oil and gas industry broadly utilizes nationwide permits 12, 14, and 39 for the construction, maintenance and repairs of pipelines, roads, and drill pads, respectively, and related structures in waters of the United States that impact less than a half-acre of waters of the United States and meet the other criteria of each nationwide permit.  
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.

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Endangered Species

The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles, or golden eagles.

Safety and Spill Prevention

In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration 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.
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 significant crude oil discharge or crude oil spill problems.
In May 2015, the U.S. Department of Transportation 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.
We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. The COGCC has adopted or amended numerous rules in recent years, including rules relating to safety matters, and currently is pursuing a rulemaking process relating to flowline safety and leak detection.
 

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 may 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 West Texas Intermediate (“WTI”) prices, due to a combination of factors including increased U.S. supply and global economic concerns. Prices for natural gas and NGLs have experienced similar volatility. 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, or in production from particular basins, may result in widening differentials. We may be materially and adversely impacted by widening differentials on our production and decreasing commodity prices.

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 affecting midstream facilities and services could hinder our access to crude oil, natural gas, and NGL markets, increase our costs or delay production. Our efforts to address midstream issues may not be successful.
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 recent periods, due to ongoing drilling activities by us and third parties and seasonal changes in temperatures, our principal third-party provider in the Wattenberg Field for midstream facilities and services has experienced significantly increased gathering system pressures. 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 volumes and reduced our revenue from the affected wells. Capacity constraints affecting natural gas production

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also impacted the associated NGLs. While this has not been a problem for us in the Delaware Basin to date, some operators in the Delaware Basin have also experienced similar issues from time to time, in part due to significant increases in production in the area. 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 rail-cars. 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 recently 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 our production falls below the level required under these agreements, we could be subject to substantial penalties. 

In order to attempt to alleviate some of the risks associated with the midstream services and facilities upon which we rely, we have pursued various means of addressing our midstream needs, including by entering into facility expansion agreements with our primary midstream provider in the Wattenberg Field in 2017. We may pursue additional options with respect to midstream matters, possibly through one or more joint ventures or monetization transactions. There can be no assurance that we will be able to negotiate and complete the transactions contemplated by our chosen strategy or that such transactions will provide us with the benefits we expect to obtain.

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 substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering our undeveloped acreage, 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 and other factors. These risks are currently greater for us in the Delaware Basin area than in our other operating areas as approximately one-third of our Delaware Basin acreage is currently scheduled to expire by mid-2019 unless the relevant leases are extended or adequate production is established.

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 leasehold positions in the Delaware Basin in Texas, 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, chemicals, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, chemicals, 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, and we may experience delays or curtailment in the pursuit of development activities and may be precluded from drilling wells in some areas.

We may incur losses as a result of title defects in the properties in which we invest or acquire.
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 record title examinations before we acquire oil and gas leases and related interests. 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.

We are subject to complex federal, state, local, and other laws and regulations that adversely affect the cost and manner 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, and could be required to change, suspend or terminate operations. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These costs may put us at a competitive disadvantage compared to larger companies in the industry which can more easily capture economies of scale with respect to compliance. A summary of certain laws and regulations that apply to us is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation.
In June 2017, the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, filed a complaint against us, claiming that we failed to operate and maintain certain condensate collection equipment at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding this litigation.
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. Our ability to obtain the permits needed to pursue our development plans may be impacted by a variety of factors, including opposition by landowners or interest groups. 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

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unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our properties.

Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us.

The regulatory environment in which we operate changes frequently, often through the imposition of new or more stringent environmental and other requirements. We cannot predict the nature, timing or effect of such additional requirements, but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary widely and include, but are not limited to, the following:

Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices. Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs, reduce our inventory of economically viable drilling locations and reduce our reserves.

Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other greenhouse gases ("GHGs"). For example, the EPA has made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. In addition, 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 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline (although President Trump subsequently announced that the United States is withdrawing from the Paris Agreement). Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program.

From time to time ballot initiatives have been proposed in Colorado that would adversely affect our operations. For example, during 2016, interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, advanced two initiatives: (i) a “local control” initiative that 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, and (ii) a “setback” initiative that 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”. 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. These proposals ultimately did not appear on the November 2016 ballot but it is likely that similar proposals will be made in 2018 and in future years. Similar proposals may also be made in other states.

A recently-adopted ballot initiative that would make it more difficult to implement certain types of ballot initiatives in the future is currently the subject of a legal challenge and may be invalidated.

Proposals are made from time to time to amend U.S. federal and state income tax laws in ways that would be adverse to us, including by eliminating 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 (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. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling.

The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage, and use of surface water or groundwater, or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays,

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interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition.

See Items 1 and 2, Business and Properties - Governmental Regulation for a summary of certain laws and regulations that currently apply to us. Any of such laws and regulations could be amended, and new laws or regulations could be implemented, in a way that adversely affects our operations.
In addition, 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 of continuing 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.
Our ability to produce crude oil, natural gas, and NGLs economically and in commercial quantities 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 or recycle the water we use at a reasonable cost and within applicable environmental rules.

Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of wastewater. 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. 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 relatively arid climates such as eastern Colorado and western Texas.

As we turn-in-line wells in the Delaware Basin, we are seeing a greater volume of water recovery and production than originally anticipated.  Our operations depend on being able to reuse or dispose of wastewater in a timely and economic fashion. Wastewater from oil and gas operations is often disposed of through underground injection. An increased number of earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection safety. 
Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves.
Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the future. Low commodity prices could result in, among other things, 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, the outlook for forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date 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 $251.6 million to write down assets and $75.1 million to impair goodwill associated with our acquisition in the Delaware Basin in 2017 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 2015. Similar charges could occur in the future.

Our estimated 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 assumptions regarding commodity prices, production levels, and operating and development costs that may prove to be 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;

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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 estimates less reliable than those based on longer production histories. 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 are 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, 2017, approximately 68 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 $2.8 billion during the five years ending December 31, 2022, 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 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, are 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 we use when calculating discounted future net cash flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general.
Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned.
Producing crude oil, natural gas, and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover, or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations.
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 or limitations as to depth;
midstream constraints;

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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 all 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. Further, the number of available locations will depend in part on the expected lateral lengths of the wells we drill. Because the intended lateral length of a well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this or numerous other reasons, our actual drilling activities may materially differ from those presently identified.
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, given the limitations of available data and technology, 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. 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 the quantity of the hydrocarbons in those structures. 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 some recent periods we have been able to achieve reductions in drilling and completion costs in connection with lower commodity prices. However, as commodity prices have increased since mid-2016, many of these costs have increased, 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.

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.


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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. 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.
Prior to 2012, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of our capital 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.

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

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Seasonal weather conditions and lease stipulations designed to prohibit or limit operations during crop-growing seasons and 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, equipment, supplies, chemicals, personnel, and oilfield services, which may lead to additional or increased costs or periodic shortages. These constraints, and the resulting high costs or shortages, could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows.

We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.
We operate approximately 87 percent of the wells in which we own an interest. If we do not operate a property, we do not have control over normal operating procedures, expenditures or future development of the property. 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 may be heightened during 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

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 all of the working interest in the oil and gas leases on which we conduct operations. 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 the other 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, may declare bankruptcy. In the event any of our project partners does 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 the costs from the partner. This could materially adversely affect our financial position.
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 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 our operations and our profitability.

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Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.
Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
A failure to complete successful acquisitions would limit our growth.
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 asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. When attractive opportunities arise, acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, 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 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 that we believe are generally consistent with customary 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. We may not be 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 asset 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 or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected.

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We operate in a litigious environment. 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, employment litigation, 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. As discussed in the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report, we are the subject of a recently filed lawsuit relating to our two remaining affiliated partnerships, and the strained financial condition of those partnerships makes additional litigation more likely. The outcome of 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 attention 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. Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report.
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 competitive 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.

Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development, and production activities. 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 but not limited to trade secrets, employee information, and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. The complexity of the technologies needed to explore for and develop crude oil, natural gas, and NGLs make certain information more attractive to thieves.
 
As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. “Phishing” and other types of attempts to obtain unauthorized information or access are often sophisticated and difficult to detect or defeat.

Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems.

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. Although we have not suffered material losses related to cyber-attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.
The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

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Many scientists believe that increasing concentrations of carbon dioxide, methane, and other GHGs in the Earth's atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance.
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 production 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.

Risks Relating to Financial Matters

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 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.
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 outstanding. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs.
Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flow 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, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving credit facility or otherwise, to fund our liquidity needs.
A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining

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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 our debt agreements could 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 obligations then due.
Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions.
Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted 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 oil and gas properties as well as a pledge of all ownership interests in 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 subject us to additional restrictive covenants.
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 expect to depend on our revolving credit facility for part of our future capital needs. The terms of the credit agreement require us to comply with certain financial covenants. Our ability to comply with these 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 become 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 unless we 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 our debt agreements, the resulting default could lead to an acceleration of payment of funds that we have borrowed and we may not have or be able to obtain the funds necessary to repay those amounts.
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 and no waiver is obtained, 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. 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 and our subsidiaries now face.
Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period in which they are determined to be non-productive, which reduces our net income in such periods.
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. The costs of unsuccessful exploratory wells could result in a significant reduction in our profitability in periods in which the costs are required to be expensed.
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 crude 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.

35



At December 31, 2017, we had hedged a total of 18,484 MBbls of crude oil and 56,510 BBtu of natural gas for 2018 and 2019. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices, and our current hedge position is smaller, and its estimated fair value is lower, than our hedge position in some recent periods.
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.

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 that is not fully covered by insurance, not properly or timely noticed to our carrier, or that is 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. In addition, pollution and environmental risks are generally not fully insurable.
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 or prior 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 crude oil derivatives arrangements, changes in government regulations impacting the crude oil and natural gas exploration and production industry 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. For example, there have been recent efforts by some investment advisers, sovereign wealth funds, public pension funds, universities, and other investment groups to divest themselves from investments in companies involved in fossil fuel extraction, and these efforts could reduce the trading prices of our securities. 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. 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. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes.


36



We have identified material weaknesses in our internal control over financial reporting which could, if not remediated, result in material misstatements in our financial statements.

As disclosed in Item 9A - Controls and Procedures, management identified certain material weaknesses in our internal control over precision of the review of supporting documentation regarding the completeness and accuracy of certain land administrative records. Because of these material weaknesses, our management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2017. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.
 
With the oversight of the audit committee, we have begun taking steps to remediate the underlying cause of these material weaknesses and improve the design of controls. We cannot assure you that we will adequately remediate the material weaknesses or that additional material weaknesses in our internal controls will not be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in their implementation, could result in additional material weaknesses, or could result in material misstatements in our financial statements. These misstatements could result in restatements of our financial statements, cause us to fail to meet our reporting obligations, or cause investors to lose confidence in our reported financial information. Further and continued determinations that there are material weaknesses in the effectiveness of our internal controls could reduce our ability to obtain financing or could increase the cost of any financing we obtain and require additional expenditures of resources to comply with applicable requirements.

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.

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.

37



ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report.

ITEM 4. MINE SAFETY DISCLOSURES
    
Not applicable.

38



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, 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

January 1 - March 31, 2017
78.61

 
60.27

April 1 - June 30, 2017
65.99

 
40.12

July 1 - September 30, 2017
50.51

 
36.74

October 1 - December 31, 2017
53.41

 
41.13


As of February 15, 2018, we had approximately 589 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 indentures governing our 6.125% senior notes due September 15, 2024 (the "2024 Senior Notes") and our 2026 Senior Notes, and we presently intend to continue a policy of using retained earnings for the expansion of our business.

The following table presents information about our purchases of our common stock during the three months ended December 31, 2017:

Period
 
Total Number of Shares Purchased (1)
 
Average Price Paid per Share
 
 
 
 
 
October 1 - 31, 2017
 
5,636

 
$
48.88

November 1 - 30, 2017
 

 

December 1 - 31, 2017
 
21,301

 
50.68

Total fourth quarter 2017 purchases
 
26,937

 
50.30

__________
(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.


39



STOCKHOLDER PERFORMANCE GRAPH

The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2017 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 233 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, 2012, 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.


http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12085564&doc=25

40




ITEM 6. SELECTED FINANCIAL DATA


 
Year Ended/As of December 31,

 
2017
 
2016 (1)
 
2015
 
2014
 
2013

 
(in millions, except per share data and as noted)
Statement of Operations (From Continuing Operations) (2):
 
 
 
 
 
 
 
 
 
 
Crude oil, natural gas, and NGLs sales
 
$
913.1

 
$
497.4

 
$
378.7

 
$
471.4

 
$
340.8

Commodity price risk management gain (loss), net
 
(3.9
)
 
(125.7
)
 
203.2

 
310.3

 
(23.9
)
Total revenues
 
921.6

 
382.9

 
595.3

 
856.2

 
392.7

Income (loss) from continuing operations
 
(127.5
)
 
(245.9
)
 
(68.3
)
 
107.3

 
(21.1
)

 
 
 
 
 
 
 
 
 
 
Earnings per share from continuing operations:
 
 
 
 
 
 
 
 
 
 
Basic
 
$
(1.94
)
 
$
(5.01
)
 
$
(1.74
)
 
$
3.00

 
$
(0.65
)
Diluted
 
(1.94
)
 
(5.01
)
 
(1.74
)
 
2.93

 
(0.65
)

 
 
 
 
 
 
 
 
 
 
Statement of Cash Flows:
 
 
 
 
 
 
 
 
 
 
Net cash flows from:
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
588.6

 
$
486.3

 
$
411.1

 
$
236.7

 
$
159.2

Investing activities
 
(717.0
)
 
(1,509.1
)
 
(604.3
)
 
(474.1
)
 
(217.1
)
Financing activities
 
65.0

 
1,266.1

 
178.0

 
60.3

 
248.7

Capital expenditures from development and exploration activities (3)
 
737.2

 
436.9

 
599.5

 
623.8

 
384.7

Acquisitions of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition
 
15.6

 
1,073.7

 

 

 
9.7


 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
4,419.9

 
$
4,485.8

 
$
2,370.5

 
$
2,331.1

 
$
1,991.7

Working capital (deficit)
 
(16.4
)
 
129.2

 
30.7

 
89.5

 
90.0

Total debt, net of unamortized discount and debt issuance costs
 
1,151.9

 
1,044.0

 
642.4

 
655.5

 
593.9

Total equity
 
2,507.6

 
2,622.8

 
1,287.2

 
1,137.4

 
967.6


 
 
 
 
 
 
 
 
 
 
Average Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for production taxes):
 
 
 
 
 
 
 
 
 
 
Sales price (excluding net settlements on derivatives)
 
$
28.69

 
$
22.43

 
$
24.64

 
$
50.72

 
$
52.23

Lease operating expenses
 
$
2.82

 
$
2.70

 
$
3.71

 
$
4.56

 
$
5.18

Transportation, gathering, and processing
 
$
1.04

 
$
0.83

 
$
0.66

 
$
0.49

 
$
0.79

Production taxes
 
$
1.91

 
$
1.42

 
$
1.20

 
$
2.76

 
$
3.33

Production taxes as a percent of sales
 
6.6
%
 
6.3
%
 
4.9
%
 
5.4
%
 
6.4
%
 
 
 
 
 
 
 
 
 
 
 
Production (MBoe):
 
 
 
 
 
 
 
 
 
 
Production from continuing operations
 
31,830

 
22,176

 
15,369

 
9,294

 
6,525

Production from discontinued operations
 

 

 

 
1,093

 
2,032

Total production
 
31,830

 
22,176

 
15,369

 
10,387

 
8,557

 
 
 
 
 
 
 
 
 
 
 
Total proved reserves (MMBoe) (4)
 
452.9

 
341.4

 
272.8

 
250.1

 
265.8

______________
(1)
In 2016, we closed an acquisition 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 this acquisition.
(2)
In 2014, we completed the sale of our ownership interest in PDC Mountaineer, LLC ("PDCM").  Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations. 
(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 as of December 31, 2013. PDCM, which owned these reserves, was sold in late 2014.


41




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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes thereto 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

2017 Financial Overview of Operations and Liquidity

Production volumes increased 44 percent to 31.8 MMBoe in 2017 compared to 2016, including 4.2 MMBoe contributed from the Delaware Basin assets that we acquired in December 2016. The increase in production volumes was primarily attributable to the continued success of our horizontal Niobrara and Codell drilling program in the Wattenberg Field and growing production from our horizontal Wolfcamp drilling program in our Delaware Basin properties. Crude oil production increased 48 percent in 2017, which comprised approximately 41 percent of our total production. Natural gas production increased 39 percent and NGLs increased 45 percent in 2017 compared to 2016. On a combined basis, total liquids production of crude oil and NGLs comprised 62 percent of production in 2017. For the month ended December 31, 2017, we maintained an average production rate of approximately 97,000 Boe per day, including approximately 18,000 Boe per day from the Delaware Basin, up from approximately 73,200 Boe per day, including approximately 6,000 Boe per day from the Delaware Basin, for the month ended December 31, 2016.

Crude oil, natural gas, and NGLs sales increased to $913.1 million in 2017 compared to $497.4 million in 2016, due to a 44 percent increase in production, combined with a 28 percent increase in the weighted average realized commodity prices. Crude oil, natural gas, and NGLs sales increased 31 percent in 2016 as compared to 2015 due to a 44 percent increase in production, partially offset by a nine percent decrease in average realized commodity prices.

We had positive net settlements from our commodity derivative contracts of $13.3 million for 2017, $208.1 million for 2016, and $238.9 million for 2015. We entered into agreements for the derivative instruments that settled throughout 2016 and 2015 prior to commodity prices becoming depressed in late 2014.  Substantially all of these higher-value derivatives settled by the end of 2016.  Net settlements for 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices.  See Results of Operations - Commodity Price Risk Management, Net for further details of our settlements of derivatives and changes in the fair value of unsettled derivatives.

The combined revenue from crude oil, natural gas, and NGLs sales and net settlements received on our commodity derivative instruments increased 31 percent to $926.4 million in 2017 from $705.5 million in 2016. Such combined revenue of $705.5 million in 2016 increased 14 percent from $617.6 million in 2015.

During 2017, we recorded exploratory dry hole well expense of $41.3 million and an unproved and proved property impairment charge of $285.5 million, and we impaired all of the goodwill associated with the assets acquired in the Delaware Basin, which resulted in an impairment charge of $75.1 million. The majority of these charges are a result of our western Culberson County acreage not meeting our performance expectations. In addition, we recorded a loss on extinguishment of debt of $24.7 million related to the redemption of our 2022 Senior Notes. For more information regarding these expenses and charges see Results of Operations - Exploration, Geologic, and Geophysical Expense, Results of Operations - Impairments of Properties, Results of Operations - Impairment of Goodwill, and Results of Operations - Loss on Extinguishment of Debt.

In December 2017, the President of the United States signed into law the 2017 Tax Cuts and Jobs Act (the "2017 Tax Act").  We recorded the effects of changes in tax law in the period of enactment.  The 2017 Tax Act reduces the corporate tax rate from 35 percent to 21 percent effective January 1, 2018.  Consequently, we have decreased our deferred tax assets and deferred tax liabilities as of December 31, 2017.  Since we are in a net deferred liability position at 2017 year end, the tax rate change resulted in a deferred tax benefit and corresponding reduction of our net deferred tax liability of approximately $114 million in 2017.

42



In 2017, we generated a net loss of $127.5 million or $1.94 per diluted share. Our net income was negatively impacted by the aforementioned impairment charges, expensing of exploratory dry hole well costs, and extinguishment of debt. During the same period, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $682.1 million, up 48 percent relative to 2016. The increase in our 2017 adjusted EBITDAX as compared to 2016 was primarily the result of the increase in crude oil, natural gas, and NGLs sales of $415.7 million, as well as the recording of a provision for a note receivable in 2016 of $44.0 million and the subsequent sale of the note in 2017 to a third-party for $40.2 million. These increases were partially offset by a decrease in derivative commodity settlements of $194.8 million and increases in operating costs of $81.7 million and interest expense of $16.7 million. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic, and geophysical expense in our reconciliation of adjusted EBITDAX.  In prior periods, we reported adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments.  All prior periods have been conformed for comparability of this updated EBITDAX presentation. In 2016 and 2015, our net loss per diluted share was $5.01 and $1.74, respectively, and our adjusted EBITDAX was $459.8 million and $464.3 million, respectively. Our net cash flows from operating activities in 2017, 2016, and 2015 were $588.6 million, $486.3 million, and $411.1 million, respectively, and our adjusted cash flow from operations, a non-U.S. GAAP financial measure, were $582.1 million, $466.8 million, and $420.8 million, respectively. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.

Liquidity

Available liquidity as of December 31, 2017 was $880.7 million, which was comprised of $180.7 million of cash and cash equivalents and $700.0 million available for borrowing under our revolving credit facility at our current commitment level. In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment allowed the borrowing base to be set above the $1.0 billion borrowing capacity of the facility. The borrowing base for our November 2017 redetermination was confirmed at $1.1 billion and we elected to maintain a $700 million commitment level. Assuming that the Bayswater Acquisition had closed in December 2017, our liquidity position as of December 31, 2017, would have been approximately $700 million.

In November 2017, we issued $600 million principal amount of our 2026 Senior Notes. The net proceeds from the offering were used to fund the redemption of our $500 million 2022 Senior Notes and a portion of the purchase price of the January 2018 Bayswater Acquisition, 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 flows from operations, investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, potential utilization of our borrowing capacity under our revolving credit facility, and if warranted, capital markets transactions from time to time.

Acquisition

On January 5, 2018, we closed the Bayswater Acquisition for approximately $186 million, subject to certain customary post-closing adjustments. In addition to the approximately $186 million of cash paid at closing, we invested approximately $15 million during 2017 to complete certain DUCs acquired in the transaction.

Acreage Exchanges

In 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area of the Wattenberg Field. Both transactions involved the exchange of leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing the transactions, we received an aggregate of approximately 15,900 net acres in exchange for an aggregate of approximately 16,200 net acres. The difference in net acres is primarily due to variances in working and net revenue interests and midstream contracts.

43



    
2017 Drilling Overview

During the year ended December 31, 2017, we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. Our drilling efficiency in the Wattenberg Field over the last year has resulted in shorter drill times; as a result, we decreased our rig count from four to three in the fourth quarter of 2017. Due to the decreased drill times, the impact of the reduced rig count on our expected turn-in-line count in the Wattenberg Field was minimal in 2017. During the three months ended December 31, 2017, we briefly ran four rigs in the Delaware Basin as we swapped out rigs to focus on improving drill times. During the fourth quarter of 2017, we turned-in-line 19 wells in the Wattenberg Field and five wells in the Delaware Basin. We did not complete or turn-in-line any wells in the Utica Shale during 2017.

The following tables summarizes our drilling and completion activity for the year ended December 31, 2017:

 
 
Wells Operated by PDC
 
 
Wattenberg Field
 
Delaware Basin
 
Total
 
 
 Gross
 
 Net
 
Gross
 
Net
 
Gross
 
Net
In-process as of December 31, 2016
 
64

 
52.7

 
5

 
4.8

 
69

 
57.5

Wells spud
 
153

 
140.2

 
26

 
22.7

 
179

 
162.9

Wells turned-in-line
 
(130
)
 
(112.8
)
 
(16
)
 
(15.2
)
 
(146
)
 
(128.0
)
 Exploratory dry holes
 

 

 
(2
)
 
(2.0
)
 
(2
)
 
(2.0
)
In-process as of December 31, 2017
 
87

 
80.1

 
13

 
10.3

 
100

 
90.4


 
 
Wells Operated by Others
 
 
Wattenberg Field
 
Delaware Basin
 
Total
 
 
 Gross
 
 Net
 
Gross
 
Net
 
Gross
 
Net
In-process as of December 31, 2016
 
18

 
3.4

 

 

 
18

 
3.4

Wells spud
 
94

 
13.1

 
10

 
1.5

 
104

 
14.5

Wells turned-in-line
 
(12
)
 
(1.6
)
 
(2
)
 
(0.4
)
 
(14
)
 
(2.0
)
Wells interest exchanged
 
(85
)
 
(12.2
)
 

 

 
(85
)
 
(12.2
)
   Exploratory dry holes
 
(1
)
 
(0.1
)
 

 

 
(1
)
 
(0.1
)
In-process as of December 31, 2017
 
14

 
2.6

 
8

 
1.1

 
22

 
3.6


Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our DUCs are generally completed and turned-in-line within three to nine months of drilling. The majority of the PDC-operated in-process wells at each period end are DUCs, as we do not begin the completion process until the entire well pad is drilled. All appropriate costs incurred through the end of the period have been capitalized, while the capital investment to complete the wells will be incurred in the period in which the wells are completed.
2018 Operational and Financial Outlook

We expect our production for 2018 to range between 38 MMBoe to 42 MMBoe, or approximately 104,000 Boe to 115,000 Boe per day for the year. We expect that approximately 42 to 45 percent of our 2018 production will be comprised of crude oil and approximately 19 to 22 percent will be NGLs, for total liquids of approximately 64 to 67 percent. Our 2018 capital forecast of between $850 million and $920 million is focused on continued execution in the Wattenberg Field and Delaware Basin with three drilling rigs and one completion crew in each basin throughout the year.

We believe that we maintain significant operational flexibility to control the pace of our capital spending.  As we execute our capital investment program, we continually monitor, among other things, commodity prices, development costs, midstream capacity, and offset and continuous drilling obligations.  Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate.  We believe we have ample opportunities to reduce capital spending in order to stay within the range of our capital investment plan, including but not limited to reducing the number of rigs being utilized in our drilling program and/or managing our completion schedule.  This flexibility is more limited in the Delaware Basin given leasehold maintenance requirements.




44



Wattenberg Field. We are drilling in the Niobrara and Codell plays within the field and anticipate spudding and turning-in-line between approximately 135 to 150 operated wells in 2018. Our 2018 capital investment program is estimated to be approximately $470 million to $500 million in the Wattenberg Field, of which approximately 90 percent is anticipated to be invested in operated drilling and completion activity. The remainder of the Wattenberg Field capital investment program is expected to be used for non-operated wells and miscellaneous workover and capital projects.

Delaware Basin. Total capital investment in the Delaware Basin in 2018 is estimated to be approximately $380 million to $420 million, of which approximately 75 percent is allocated to both spud and turn-in-line approximately 25 to 30 operated wells targeting the Wolfcamp formation.  Based on the timing of our operations and requirements to hold acreage, we may adapt our capital investment program to drill wells different from or in addition to those currently anticipated, as we are continuing to analyze the terms of the relevant leases. We plan to invest approximately 10 percent of our capital in leasing, non-operated capital, seismic, and technical studies with an additional approximately 15 percent for midstream related projects including oil and gas gathering systems and water supply and disposal systems.

Utica Shale.  In 2017, as part of plans to divest the Utica Shale properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as of December 31, 2017. In February 2018, we entered into a definitive PSA to sell these properties for net cash proceeds of approximately $40.0 million. The transaction is expected to close in the first quarter of 2018, subject to certain customary closing conditions.

Financial Guidance. Based on our current production forecast for 2018 and assuming averages of approximately $57.50 NYMEX crude oil price for the year and a $3.00 NYMEX natural gas price, we expect 2018 capital investments to exceed our 2018 cash flows from operations by approximately less than $90 million. We anticipate that the proceeds received from the sale of our Utica Shale assets and a midstream dedication agreement (see the footnote titled Subsequent Events to the consolidated financial statements included elsewhere in this report), will fund approximately two-thirds of this outspend. We expect this capital investment outspend to occur during the first half of 2018, with cash flows exceeding capital investment during the second half of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to decrease in 2018 to 1.4 based on production and operational cash flow growth.

The following table provides projected financial guidance for 2018: