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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended December 31, 2019

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
https://cdn.kscope.io/7de660821aca94f1ec2381fb66edbfba-logo123114a18.jpg
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)

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

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

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Ticker Symbol
 
Name of each exchange on which registered
Common Stock, par value $0.01 per share
 
PDCE
 
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 every Interactive Data File required to be submitted 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 such files). Yes T No £



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

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, 2019 was $2.3 billion (based on the closing price of $36.06 per share as of the last business day of the fiscal quarter ending June 30, 2019).

As of February 18, 2020, there were 100,121,539 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 filed pursuant to Regulation 14A for our 2020 Annual Meeting of Stockholders.










PDC ENERGY, INC.
2019 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. and our wholly-owned subsidiaries consolidated for the purposes of our financial statements. PDC Energy, Inc. is a Delaware corporation, having reincorporated from Nevada in 2015.

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule 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: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; our stock repurchase program, which may be modified or discontinued at any time; potential additional payments from the sale of our midstream assets; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; timing and adequacy of infrastructure projects of our midstream providers and the related impact on our midstream capacity and related curtailments; fractionation capacity; impacts of Colorado political matters and expected timing of rulemakings; ability to meet our volume commitments to midstream providers; ability to obtain permits from the Colorado Oil and Gas Conservation Commission ("COGCC") in a timely manner; ongoing compliance with our consent decree and expected timing of certain litigation; and reclassification of the Denver Metro/North Front Range NAA ozone classification to serious.

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 global 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 extended periods of depressed prices;
volatility and widening of differentials;
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;
impact of recent regulatory developments in Colorado with respect to additional permit scrutiny;
declines in the value of our crude oil and natural gas properties resulting in impairments;
changes in estimates of proved reserves;
inaccuracy of estimated reserves and production rates;
potential for production decline rates from our wells being greater than expected;
timing and extent of our success in discovering, acquiring, developing and producing reserves;

1



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;
difficulties in integrating our operations as a result of any significant acquisitions, including the merger with SRC Energy, Inc. ("SRC"), or acreage exchanges;
increases or changes in costs and expenses;
limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells;
potential losses of acreage due to lease expirations or otherwise;
future cash flows, liquidity and financial condition;
competition within the oil and gas industry;
availability and cost of capital;
our success in marketing crude oil, natural gas and NGLs;
effect of crude oil, natural gas and NGLs derivatives activities;
impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders;
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.


2



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, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones.

The following map presents the general locations of our development and production activities as of December 31, 2019:
https://cdn.kscope.io/7de660821aca94f1ec2381fb66edbfba-map2018withlocationsa03.jpg
    
The following table presents selected information regarding our results of operations for the periods presented:
 
 
Year Ended/As of
 
 
December 31,
 
Percent Change
 
 
2019
 
2018
 
2019-2018
 
 
(production and reserves in MMBoe, dollars in millions)
 
 
Wells:
 
 
 
 
 
 
Gross productive wells
 
2,649

 
2,876

 
(7.9
)%
Net productive wells
 
2,101

 
2,284

 
(8.0
)%
Horizontal percentage
 
48
%
 
39
%
 
23
 %
Gross operated wells turned-in-line
 
135

 
165

 
(18.2
)%
Net operated wells turned-in-line
 
125

 
151

 
(17.2
)%
Production:
 
 
 
 
 
 
Wattenberg Field
 
38.0

 
30.7

 
23.9
 %
Delaware Basin
 
11.4

 
9.4

 
22.1
 %
Utica Shale (1)
 

 
0.1

 
*

Total
 
49.4

 
40.2

 
23.0
 %
Reserves:
 
 
 
 
 
 
Proved reserves
 
610.9

 
544.9

 
12.1
 %
Proved developed reserves percentage
 
35
%
 
33
%
 
6
 %
Standardized measure
 
$
3,310

 
$
4,448

 
(25.6
)%
PV-10 (2)
 
$
3,837

 
$
5,321

 
(27.9
)%
 
 
 
 
 
 
 
Liquidity
 
$
1,291.0

 
$
1,268.9

 
1.7
 %
Leverage ratio
 
1.4

 
1.4

 
 %
                                   
(1) In March 2018, we completed the disposition of our Utica Shale properties.
(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



Acquisition    
    
In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt (the “SRC Acquisition”). We issued approximately 39 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the merger agreement that we entered into with SRC (the "Merger Agreement").
    
The following table presents selected information regarding our and SRC's operations as of and for the year ended December 31, 2019:
 
 
Year Ended/As of December 31, 2019
 
 
PDC
 
SRC
 
Combined
 
 
(production in MBoe, reserves in MMBoe and dollars in millions)
Wells:
 
 
 
 
 
 
Gross productive wells
 
2,649

 
1,529

 
4,178

Net productive wells
 
2,101

 
958

 
3,059

 
 
 
 
 
 
 
Production:
 
 
 
 
 
 
Crude oil (MBbls)
 
19,166

 
9,813

 
28,979

Natural gas (MMcf)
 
115,950

 
49,471

 
165,421

NGLs (MBbls)
 
10,923

 
4,526

 
15,449

Crude oil equivalent (MBoe)
 
49,414

 
22,584

 
71,998

Average Boe per day (Boe)
 
135,381

 
61,874

 
197,255

Crude oil production percentage
 
38.8
%
 
43.5
%
 
40.2
%
 
 
 
 
 
 
 
Reserves:
 
 
 
 
 
 
Proved reserves (1)
 
610.9

 
295.0

 
905.9

Proved developed reserves percentage
 
35
%
 
42
%
 
37
%
Crude oil and condensate percentage
 
32
%
 
27
%
 
31
%
                      
(1) Estimated reserve information for SRC is based on assumed realized prices of $50.17 per Bbl of crude oil, $1.69 per Mcf of natural gas
and $9.67 per Bbl of NGLs and SRC's development plan for the related properties. The estimates are not included in the Ryder Scott
Company, L.P. ("Ryder Scott") or Netherland, Sewell, & Associates, Inc. ("NSAI") reports for our properties described below in "Properties -
Proved Reserves" and are subject to the risks and uncertainties described in "Risk Factors - Risks Relating to Our Business and Industry - 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."

2020 Strategic Focus
 
Our planned 2020 capital investments in crude oil and natural gas properties, which we expect to be between $1.0 billion and $1.1 billion, are focused on continued execution of our development plans in the Wattenberg Field, including acreage received in the SRC Acquisition, and Delaware Basin. In allocating our planned expenditures, we consider, among other things, cost efficiencies, midstream capacities and netback pricing, expected future cash flows and rates of return, the political environment and our remaining drilling location inventory in order to best meet our short- and long-term corporate strategy. We are committed to our disciplined approach to managing our development plans. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate.

Based on our current production forecast for 2020 and assumed average New York Mercantile Exchange (“NYMEX”) prices of $52.50 per Bbl of crude oil and $2.00 per Mcf of natural gas and an assumed average composite price of $11.00 per Bbl for NGLs, we expect 2020 adjusted cash flows from operations, a non-U.S. GAAP financial measure, to exceed our capital investments in crude oil and natural gas properties by approximately $250 million. Assuming consistent realization percentages, we estimate that for every:

4



    
$2.50 change in the NYMEX crude oil price from $52.50, our adjusted cash flows from operations would increase or decrease by approximately $30 million;
$0.25 change in the NYMEX natural gas price from $2.00, our adjusted cash flows from operations would increase or decrease by approximately $20 million; and
$1.00 change in the composite price for NGLs from $11.00, our adjusted cash flows from operations would increase or decrease by approximately $20 million.

We may revise our 2020 capital investment program during the year as a result of, among other things, changes in commodity prices and/or our internal long-term outlook for commodity prices, the cost of services for drilling and well completion activities, requirements to hold acreage, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, availability of midstream infrastructure and services, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities.

Long-Term Business Strategy and Key Strengths

Our long term business strategy focuses on creating shareholder value by delivering attractive returns from responsible development of our crude oil and natural gas properties, maintaining financial strength, generating sustainable cash flows from operations in excess of our capital investments in crude oil and natural gas properties and returning capital to shareholders. We seek to create long-term shareholder value through the following:

Strong financial position. We maintain a disciplined financial strategy that focuses on strong liquidity, low leverage ratios and an active commodity derivative program to help mitigate a portion of the risk associated with commodity price fluctuations. We believe that execution of this strategy will allow us to deliver strong corporate returns year-over-year, even through challenging commodity price environments. As of December 31, 2019, we had total liquidity of $1.3 billion, a leverage ratio, as defined in our revolving line of credit facility agreement, of 1.4 and commodity derivative positions covering approximately 10.8 MMBbls and 3.2 MMBbls of crude oil production for 2020 and 2021, respectively. As of the same date, we had hedged approximately 4.0 Bcf of natural gas production for 2020.

Focus on generating sustainable cash flows from operations in excess of capital investments. We are focused on generating multi-year sustainable cash flows from operations in excess of our capital investments through managing capital spending and growth rates, adjusting the timing of completion of our inventory of drilled uncompleted wells ("DUCs"), utilizing commodity derivative instruments, focusing on margin improvement from reductions in our cost structure and through increased capital efficiency from technological innovation.

Return of capital to shareholders. We are focused on returning capital to shareholders through our ongoing share repurchase program and a focus on debt reduction. Through February 24, 2020, we have repurchased an aggregate 5.3 million shares of our outstanding common stock for a total cost of $166.9 million. Through successful execution of our business plan, our projected cash flows are expected to position us to deliver on our commitment to return capital to shareholders.

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 acquisitions and acreage trades in our core areas of operations, we have built multiple concentrated acreage positions with high working interests that we believe will allow us to enhance the value of our assets and replenish our drilling inventory. Including wells that we received in the SRC Acquisition, we currently operate approximately 78 percent of all the wells in which we have an interest. This operational control allows us to better 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 with additional flexibility on the timing of drilling of those locations.

Project inventory in two premier crude oil, natural gas and NGL plays. We have a substantial multi-year inventory of high-quality horizontal drilling opportunities across two premier U.S. onshore basins: the Wattenberg Field in Weld County, Colorado and the Delaware Basin in Reeves County, Texas. Our portfolio has a proven record of delivering strong and repeatable economic returns and provides us the ability to allocate capital investments and manage risk 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. We have a disciplined development program that seeks to expand our project inventory through testing new intervals and considering various spacing configurations. We believe our project inventory will allow us to achieve attractive rates of return and grow our proved reserves and

5



production in a sustainable fashion. Such expected returns on drilling can vary well by well and are based upon many factors, including but not limited to, commodity prices and well development and operating costs.

Efficiency through technology and consolidation. Technological innovation has led to continued improvement in our drilling and completion times. We are utilizing technology to improve the efficiency of our horizontal drilling and completion operations in the Wattenberg Field. In the Delaware Basin, we continue to make progress towards improved capital efficiency through various drilling initiatives and completion designs. The technology associated with our completions process continues to improve as we design wellbore placement and stage spacing and, in the Wattenberg Field, increase the completed lateral length of our wells. In addition, completion equipment, perforation clusters, fluid and sand type and concentration decisions continue to result in more efficient recoveries of crude oil and natural gas reserves. As with our drilling operations, we are currently working toward using the expertise we have developed in the Wattenberg Field to increase the efficiency of our Delaware Basin completions activities. Additionally, acreage consolidation, particularly in the Wattenberg Field, increases our ability to drill longer length lateral wells. Longer laterals allow us to develop our properties with a smaller number of wells and less truck traffic, with resulting benefits for our operations and for the communities in which we operate. 

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 in effectively operating in today’s intensive regulatory climate. For the year ended December 31, 2019, we achieved our strategic priorities around our environment, health and safety programs. 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.

Experienced management team with proven track record. We have a strong executive management team that has an average of 25 years of experience in the oil and gas industry. Collectively, this experience includes technical, operational, commercial, financial and strategic aspects of the oil and gas industry. This team has a proven track record of executing on value-added capital investment programs that have been implemented with a focus on financial discipline and improving on an already strong balance sheet, while growing production and proved reserves. Additionally, our team's experience has helped us continue to achieve our strategic objectives through periods of commodity price volatility, cost inflation and other challenging operating environments.

Operating Areas

Wattenberg Field. In the Wattenberg Field, we have identified a gross operated inventory of approximately 1,600 horizontal drilling locations (including locations received as part of the SRC Acquisition) that we expect to generate acceptable rates of return based on forward strip pricing, with an average lateral length of approximately 8,300 feet. In addition to these drilling locations, we entered 2020 with approximately 230 gross operated DUCs, including 88 gross operated DUCs received as part of the SRC Acquisition. Our Wattenberg Field horizontal drilling locations have been substantially de-risked through multiple years of successful development in the field. We continue to analyze and test various wellbore spacing configurations in areas of the field that we believe have the potential to increase our gross operated inventory. Substantially all of our Wattenberg Field acreage is held by production. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface.

Delaware Basin. In the Delaware Basin, we have identified a gross operated inventory of approximately 190 horizontal drilling locations that we expect to generate acceptable rates of return based on forward strip pricing, primarily targeting the Wolfcamp A and Wolfcamp B zones, within the oilier eastern and north central portions of our acreage. The average lateral length of these locations is approximately 8,600 feet, compared to an average lateral length of approximately 7,900 feet as of year-end 2018. Some of these locations are within untested target zones that may be subject to a higher degree of uncertainty or may depend upon additional delineation and testing. Our gross operated inventory in the Delaware Basin decreased from year-end 2018, primarily due to the removal of several standard-reach lateral, higher gas-to-oil ratio locations that were negatively impacted by decreased NYMEX natural gas pricing and higher Waha natural gas differentials. We continue to pursue various business development initiatives, with a focus on acreage swaps and joint development projects, designed to increase our Delaware Basin project inventory by establishing longer lateral drilling units capable of delivering attractive economic returns. In addition to these drilling locations, we entered 2020 with approximately 27 gross operated DUCs. Wells in the Delaware Basin typically have productive horizons at depths of approximately 8,000 to 11,500 feet below the surface.


6



Midstream Asset Divestitures

In the second quarter of 2019, we sold Delaware Basin produced water gathering and disposal, crude oil gathering and natural gas gathering assets (the "Midstream Asset Divestitures") for an aggregate cash purchase price of $345.6 million, subject to certain customary post-closing adjustments, plus potential future long-term incentive payments. We do not currently expect to meet the conditions to receive these incentive payments. Concurrent with the Midstream Asset Divestitures, we entered into agreements with the purchasers which provide us with certain gathering, processing, transportation and water disposal services. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets, with $179.6 million allocated to the acreage dedication agreements.
    
Significant Customers

Our most significant customers are Occidental Marketing, Inc., DCP Midstream, LP ("DCP"), Mercuria Energy Trading, Inc. and United Energy Trading, LLC. Sales to each of these customers contributed more than 10 percent of our 2019 revenues. However, given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers.

Properties

Productive Wells

The following table presents our productive wells:
    
 
 
Productive Wells
 
 
As of December 31, 2019
 
 
Crude Oil
 
Natural Gas
 
Total
Operating Region/Area
 
 Gross
 
 Net
 
Gross
 
 Net 
 
 Gross
 
 Net
Wattenberg Field (1)
 
1,163

 
809.7

 
1,385

 
1,212.8

 
2,548

 
2,022.5

Delaware Basin
 
48

 
27.6

 
53

 
50.7

 
101

 
78.3

Total productive wells
 
1,211

 
837.3

 
1,438

 
1,263.5

 
2,649

 
2,100.8


(1) Amounts do not include 950 gross (516 net) productive crude oil wells or 579 gross (442 net) productive natural gas wells received in the
SRC Acquisition.
    
Proved Reserves

The following table presents our proved reserve estimates as of December 31, 2019, based on reserve reports prepared by our independent petroleum engineering consulting firms, Ryder Scott and NSAI and related information:
 
Proved Reserves at December 31, 2019
 
 
 
 
 
 
 
Proved Reserves (MMBoe)
 
% of Total Proved Reserves
 
% Proved Developed
 
% Liquids
 
Proved Reserves to Production Ratio (in years)(2)
 
2019 Production (MBoe)
 
 
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
492.1

(1
)
81
%
 
33
%
 
55
%
 
13.0

 
37,984

Delaware Basin
118.8

 
19
%
 
44
%
 
69
%
 
10.4

 
11,430

Total
610.9

 
100
%
 
35
%
 
57
%
 
12.4

 
49,414


(1) Amount does not include 295.0 MMBoe of proved reserves received in the SRC Acquisition.
(2) Based on 2019 PDC production.
          
Our proved reserves are sensitive to future crude oil, natural gas and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or the recognition of more economically viable proved undeveloped ("PUD") reserves, while decreases in commodity prices may result in corresponding negative impacts. All of our proved reserves are located in the U.S.

Controls Over Reserve Report Preparation. 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. Inputs and major assumptions related to

7



our proved reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land and management for adherence to SEC guidelines through a detailed review of land and accounting records, available geological and reservoir data and production performance data. The internal team compiles the reviewed data and forwards the applicable data to Ryder Scott or NSAI. Our proved reserves in the Wattenberg Field as of December 31, 2019 were estimated by Ryder Scott and our proved reserves in the Delaware Basin as of that date were estimated by NSAI.

When preparing our reserve estimates, neither Ryder Scott nor NSAI independently verifies the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties 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.

Letters which identify the professional qualifications of the individuals at Ryder Scott and NSAI who are responsible for overseeing the preparation of our reserve estimates as of December 31, 2019 have been filed as Exhibits 99.1 and 99.2 to this report.
 
Internally, the professional qualifications of our 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 Masters of Petroleum Engineering from the Colorado School of Mines and a Bachelors of Geology from the University of Colorado and has over 19 years of oil and gas experience.

In determining our proved reserves estimates, we used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies and seismic data and interpretation. 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.

Commodity Pricing. 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 indicated index prices for our reserves, by commodity, are presented below.
 
 
Average Benchmark Prices (1)
As of December 31,
 
Crude Oil
(per Bbl) (2)
 
Natural Gas
(per Mcf) (2)
 
NGLs
(per Bbl) (3)
 
 
 
 
 
 
 
2019
 
$
55.69

 
$
2.58

 
$
55.69

2018
 
65.56

 
3.10

 
65.56

2017
 
51.34

 
2.98

 
51.34


The netted back price used to estimate our reserves, by commodity, are presented below.
 
 
Price Used to Estimate Reserves (4)
As of December 31,
 
Crude Oil
(per Bbl)
 
Natural Gas
(per Mcf)
 
NGLs
(per Bbl)
 
 
 
 
 
 
 
2019
 
$
52.63

 
$
1.50

 
$
12.21

2018
 
61.14

 
2.15

 
23.04

2017
 
48.68

 
2.31

 
20.21

(1)
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.
(2) Our benchmark prices for crude oil and natural gas are West Texas Intermediate ("WTI") and Henry Hub, respectively.
(3)
For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.
(4)
These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity.


8



Commodities and Standardized Measure. Reserve estimates involve judgments and reserves 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.

The following tables provide information regarding our estimated proved reserves:
 
As of December 31,
 
2019
 
2018
 
2017
Proved reserves
 
 
 
 
 
Crude oil and condensate (MMBbls)
197

 
190

 
155

Natural gas (Bcf)
1,558

 
1,336

 
1,154

NGLs (MMBbls)
154

 
132

 
106

Total proved reserves (MMBoe)
611

 
545

 
453

 
 
 
 
 
 
Proved developed reserves (MMBoe)
214

 
180

 
143

 
 
 
 
 
 
Estimated undiscounted future net cash flows (in millions) (1)
$
5,896

 
$
7,735

 
$
5,453

 
 
 
 
 
 
Standardized measure (in millions)
$
3,310

 
$
4,448

 
$
2,880

 
 
 
 
 
 
PV-10 (in millions) (2)
$
3,837

 
$
5,321

 
$
3,212


(1)
Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI, of approximately $6.8 billion, $9.1 billion and $6.2 billion as of December 31, 2019, 2018 and 2017, respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.9 billion, $1.4 billion and $0.7 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.

The additions to our proved reserves at December 31, 2019 as compared to December 31, 2018 were primarily a result of an extended reserve life in the Delaware Basin due to an improved operating cost structure, increased production forecasts for Wattenberg Field proved developed wells due to improved line pressures and an addition of proved undeveloped locations in the Wattenberg Field.
 

9



The following table presents our estimated proved developed and undeveloped reserves by category and area:
 
 
As of December 31, 2019
Operating Region/Area
 
Crude Oil and Condensate (MMBbls)
 
Natural Gas
(Bcf)
 
NGLs
(MMBbls)
 
Crude Oil
Equivalent
(MMBoe)
 
Percent
Proved developed
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
47.1

 
443.4

 
40.7

 
161.7

 
26
%
Delaware Basin
 
19.1

 
110.8

 
14.7

 
52.3

 
9
%
Total proved developed
 
66.2

 
554.2

 
55.4

 
214.0

 
35
%
Proved undeveloped
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
94.6

 
891.7

 
87.2

 
330.4

 
54
%
Delaware Basin
 
36.4

 
111.9

 
11.4

 
66.5

 
11
%
Total proved undeveloped
 
131.0

 
1,003.6

 
98.6

 
396.9

 
65
%
Total proved reserves
 
 
 
 
 
 
 
 
 
 
Wattenberg Field
 
141.7

 
1,335.1

 
127.9

 
492.1

 
81
%
Delaware Basin
 
55.5

 
222.7

 
26.1

 
118.8

 
19
%
Total proved reserves
 
197.2

 
1,557.8

 
154.0

 
610.9

 
100
%
    
Proved Reserves Sensitivity Analysis. We have performed an analysis of our proved reserve estimates as of December 31, 2019 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 2019 NYMEX price for crude oil used in estimating our reported proved reserves with $50.00 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, 2019 Estimated Reserves
PV-10 (in Millions)
PV-10 % Change from December 31, 2019 Estimated Reserves
2019 SEC Reserve Report (1)
$
55.69

 
$
2.58

 
610.9

 

$
3,837.0


Alternate Price Scenario
$
50.00

 
$
2.58

 
604.6

 
(1
)%
$
3,201.8

(17
)%
(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 Btu adjustments we experienced for the relevant commodity.

Developed and Undeveloped Acreage

The following table presents our developed and undeveloped lease acreage:
 
 
As of December 31, 2019
 
 
Developed
 
Undeveloped
 
Total
Operating Region/Area
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wattenberg Field (1) (2)
 
101,400

 
95,900

 
42,900

 
40,600

 
144,300

 
136,500

Delaware Basin
 
28,100

 
25,500

 
2,400

 
300

 
30,500

 
25,800

 Total acreage
 
129,500

 
121,400

 
45,300

 
40,900

 
174,800

 
162,300

 
 
 
 
 
 
 
 
 
 
 
 
 
(1)
Of the amounts shown, 78,800 gross (74,200 net) developed lease acres and 23,000 gross (22,100 net) undeveloped lease acres are associated with our approximately 1,600 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 believe to be economic to develop; therefore, we have not currently identified any potential drilling locations on these acres.
(2)
Amounts do not include approximately 65,000 gross (61,000 net) developed lease acres and 27,000 gross (22,000 net) undeveloped lease acres received in the SRC Acquisition.



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Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held by production. Our Wattenberg Field leaseholds at risk to expire in 2020, 2021 and 2022 are not material. In the Delaware Basin, there are drilling obligations or continuous drilling clauses associated with the majority of our acreage. We believe that our current Delaware Basin drilling plan should provide sufficient development to meet these obligations in our core areas over the next few years. In the event that we do not meet the obligations for certain leases, we plan to make any necessary bonus extension payments, changes to our drilling schedule or seek to renew or re-lease the relevant properties. However, we may not be successful in such efforts and may in some cases elect to allow the lease to expire. Our Delaware Basin leaseholds at risk to expire in 2020, 2021 and 2022 are not material. 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 substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Drilling Activity. The following tables set forth a summary of our developmental and exploratory well drilling activity for the periods presented. 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. We utilize pad drilling operations where multiple wells are developed from the same well pad in both the Wattenberg Field and Delaware Basin. Because we may operate multiple drilling rigs in each operating area, we expect to have in-process wells at any given time. Wells may be in-process for up to a year.
 
 
Gross Development Well Drilling Activity
 
 
Year Ended December 31,
 
 
2019
 
2018
 
2017
Operating Region/Area
 
Productive (1)
 
In-Process (1)
 
Non-Productive
 
Productive
 
In-Process
 
Non-Productive (2)
 
Productive
 
In-Process
 
Non-Productive (2)
Wattenberg Field, operated wells
 
114

 
145

 

 
139

 
133

 

 
130

 
87

 

Wattenberg Field, non-operated wells
 
12

 
41

 

 
20

 
5

 

 
12

 
14

 
1

Delaware Basin, operated wells
 
21

 
26

 

 
26

 
22

 
1

 
9

 
10

 

Delaware Basin, non-operated wells
 
9

 

 

 
11

 

 

 
2

 
8

 

Total gross development wells
 
156

 
212



 
196

 
160

 
1

 
153

 
119

 
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1
)
Amounts do not include 82 and 46 gross productive operated and non-operated development wells, respectively, and 88 and seven gross in-process operated and non-operated development wells, respectively, received in the SRC Acquisition.
(2
)
Represents mechanical failures that resulted in the plugging and abandonment of the well.
 
 
Net Development Well Drilling Activity
 
 
Year Ended December 31,
 
 
2019
 
2018
 
2017
Operating Region/Area
 
Productive (1)
 
In-Process (1)
 
Non-Productive
 
Productive
 
In-Process
 
Non-Productive (2)
 
Productive
 
In-Process
 
Non-Productive (2)
Wattenberg Field, operated wells
 
105.1

 
135.0

 

 
126.8

 
122.4

 

 
112.8

 
80.1

 

Wattenberg Field, non-operated wells
 
1.1

 
3.7

 

 
2.5

 
0.9

 

 
1.6

 
2.6

 
0.1

Delaware Basin, operated wells
 
20.1

 
25.3

 

 
24.5

 
16.3

 
1.0

 
10.1

 
9.4

 

Delaware Basin, non-operated wells
 
1.3

 

 

 
1.2

 

 

 
0.4

 
1.0

 

Total net development wells
 
127.6

 
164.0

 

 
155.0

 
139.6

 
1.0

 
124.9

 
93.1

 
0.1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1
)
Amounts do not include 76 and seven net productive operated and non-operated development wells, respectively, and 80 and one net in-process operated and non-operated development wells, respectively, received in the SRC Acquisition.
(2
)
Represents mechanical failures that resulted in the plugging and abandonment of the well.



11




 
 
Gross Exploratory Well Drilling Activity
 
 
Year Ended December 31,
 
 
2019
 
2018
 
2017
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
 
2

 
4

 

 
3

 
2

 

 
5

 
3

 
2

Total gross development wells
 
2

 
4

 

 
3

 
2

 

 
5

 
3

 
2

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 
Net Exploratory Well Drilling Activity
 
 
Year Ended December 31,
 
 
2019
 
2018
 
2017
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
 
2.0

 
3.9

 

 
2.8

 
2.0

 

 
3.1

 
2.8

 
2.0

Total gross development wells
 
2.0

 
3.9

 

 
2.8

 
2.0

 

 
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 have been mortgaged or pledged as security for our revolving credit facility.

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.

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, location, spacing and density of wells, water discharge and disposal, prevention of waste, bonding requirements, surface use and restoration, public health and environmental protection and well plugging and abandonment. The primary state-level regulatory authority regarding these matters in Colorado is the COGCC and the primary authority in Texas is the Texas Railroad Commission. Prior to preparing a surface location and commencing drilling operations on a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. In addition, 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

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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. These risks also exist in Colorado, where a recent rule change has imposed new limits on forced pooling. State laws may also prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our wells. Leases covering state or federal lands often include additional laws, regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs.

Regulation of Transportation of Commodities. We move natural gas through pipelines owned by other entities and sell natural gas to other entities 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 ("NGPA"). 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.

In addition to regulation of natural gas pipeline interstate transmission and storage activities, under the Energy Policy Act of 2005 (the “EPAct 2005”) it is unlawful for “any entity” to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC. The EPAct 2005 provides FERC with substantial enforcement authority to prohibit such manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
FERC Order 704 requires that any market participant, including natural gas producers, gatherers and marketers, that engaged in wholesale sales or purchases of natural gas that equaled or exceeded 2.2 MMBtus of physical natural gas in the previous calendar year to report to FERC the aggregate volumes of natural gas produced or sold at wholesale in such calendar year. Order 704 applies only to those transactions that utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the market participant to determine which individual transactions are to be reported under the guidance of Order 704. Additional information that must be reported includes whether the price in the relevant transaction was reported to any index publisher, and if so, whether such reporting complied with FERC’s policy statement on price reporting. To the extent that we engage in wholesale sales or purchases of natural gas that equal or exceed 2.2 MMBtus of physical natural gas in a calendar year pursuant to transactions utilizing, contributing or having the potential to contribute to the formation of price indices, we may be subject to the reporting requirements of Order 704.

Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are, however, subject to state regulation, which includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and rate regulation on a complaint basis. We own certain pipeline facilities in the Delaware Basin that we believe are exempt from regulation under the NGA as “gathering facilities,” but which may in some cases be subject to state regulation.

Although FERC has set forth a general test to determine whether facilities are exempt from regulation under the NGA as “gathering” facilities, FERC’s determinations as to the classification of facilities are performed on a case-by-case basis. With respect to facilities owned by third parties and on which we move natural gas, to the extent that FERC subsequently issues an order reclassifying facilities previously thought to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of moving natural gas to the point of sale may be increased. Further, to the extent that FERC issues an order reclassifying facilities that we own that were previously thought to be non-jurisdictional gathering facilities as subject to FERC jurisdiction, we could be subject to additional regulatory requirements under the NGA and the NGPA.

Transportation and safety of natural gas is also subject to regulation by the U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under 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, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act 2006”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “PIPES Act 2011”). We own certain pipeline facilities in the Delaware Basin that are subject to such regulation by PHMSA.

In addition to natural gas, we move crude oil, condensate and natural gas liquids (collectively, “liquids”) through pipelines owned by other entities and sell such liquids to other entities that also utilize pipeline facilities that may be subject to

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regulation by FERC. FERC regulates the rates and terms and conditions of service for the interstate transportation of liquids under the Interstate Commerce Act, as it existed on October 1, 1977 (the “ICA”), and the rules and regulations promulgated thereunder. This includes movements of liquids through any pipelines, including those located solely within one state, that are providing part of the continuous movement of such liquids in interstate commerce for a shipper. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC, setting forth established rates and the rules and regulations governing transportation service, which must be “just and reasonable.” The ICA also requires that services be provided in a manner that is not unduly discriminatory or unduly preferential; in some cases, this may result in the proration of capacity among shippers in an equitable manner.

The intrastate transportation of crude oil and NGLs is subject to regulation by state regulatory commissions, which in some cases require the provision of intrastate transportation on a nondiscriminatory basis and the prorationing of capacity on such pipelines under policies set forth in published tariffs. These state-level regulations may also impose certain limitations on the rates that the pipeline owner may charge for transportation.

Transportation of liquids by pipeline is subject to regulation by PHMSA pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as well as the PIPES Act 2006 and the PIPES Act 2011, which govern the design, installation, testing, construction, operation, replacement and management of liquids pipeline facilities. Liquids that are transported by rail may also be subject to additional regulation by PHMSA.

The availability, terms and cost of transportation affect the amounts we receive for our commodities. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen an 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.

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. We also operate under a number of environmental permits and authorizations. The issuing agencies may take the position that some or all of these permits and authorizations are subject to modification, suspension, or revocation under certain circumstances, but any such action would have to comply with applicable procedures and requirements.

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. In April 2019, the EPA, pursuant to the consent decree, determined that revision of the regulations is not necessary. Information comprising the EPA’s review and decision is contained in a document entitled Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels.

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

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that disposed of, transported or arranged for the disposal of the hazardous substances found at the site. Parties 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. In addition, 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.
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 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 us, 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; however, the BLM’s rescission of the rule has been challenged in the United States District Court for the Northern District of California.

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. These 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.

In November 2018, the EPA and the non-profit organization known as the State Review of Oil and Natural Gas Environmental Regulations (“STRONGER”) entered into a Memorandum of Understanding pursuant to which the EPA has affirmed its commitment to meaningful participation in STRONGER’s efforts to develop guidelines for state oil and natural gas environmental regulatory programs, conduct reviews of such programs and publish reports of those reviews.
  

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State Regulation

The states in which we currently operate have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control, chemical disclosure, wastewater disposal, baseline sampling, seismic monitoring, well monitoring and materials handling requirements on hydraulic fracturing and/or well construction and well location requirements and more stringent notification or consultation processes that relate to hydraulic fracturing. Similarly, some states, including Texas, have implemented rules requiring the submission of detailed information related to seismicity in connection with injection well permit applications for the disposal of wastewater.

In 2019, Colorado enacted Senate Bill 19-181 (“SB 19-181”), which changes the mission of the COGCC from fostering responsible and balanced development to regulating development to protect public health and the environment and directs the COGCC to undertake rulemaking on various operational matters including environmental protection, facility siting and wellbore integrity. Pursuant to this direction, in December 2019 the COGCC proposed new regulatory requirements to enhance safety and environmental protection during hydraulic fracturing and to enhance wellbore integrity.

Colorado and Texas require that 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.

Concerns about hydraulic fracturing have contributed to support for 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 sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities. In Colorado, the Colorado Supreme Court ruled in 2016 that the cities of Fort Collins and Longmont did not have the authority to prohibit or impose five-year moratoria on hydraulic fracturing. SB 19-181 gives local governmental authorities increased authority to regulate oil and gas development. The authors of the legislation were clear that SB 19-181 was not intended to allow an outright ban on oil and gas development. However, anti-industry activists in Longmont, Colorado, have argued in court that SB 19-181 permits a local governmental authority to impose such a ban. We primarily operate in the rural areas of the core Wattenberg Field in Weld County, a jurisdiction in which there has historically been significant support for the oil and gas industry. In Texas, legislation enacted in 2015 generally prohibits political subdivisions from banning, limiting or otherwise regulating oil and gas operations. 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, alleging contamination of drinking water as a result of hydraulic fracturing activities.

Greenhouse Gases

The EPA has published 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. To date, Congress has not adopted any such significant legislation, 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, November 2017 and December 2019, 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 U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG

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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 U.S. would initiate the formal process to withdraw from the Paris Agreement. In November 2019, the U.S. formally notified the United Nations of its intentions to withdraw from the Paris Agreement. The notification begins a one-year process to complete the withdrawal.

Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations.
    
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 make 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 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. In September 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. In September 2019, the EPA proposed certain policy amendments to the 2016 rules that would remove all sources in the transmission and storage segment of the oil and natural gas industry from regulation. The proposed amendments would also rescind the methane requirements in the 2016 rules that apply to sources in the production and processing segments of the industry. The EPA is also proposing, in the alternative, to rescind the methane requirements that apply to all sources in the oil and natural gas industry, without removing any sources from the current source category.

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. In September 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.

In 2016, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment ("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. In 2019, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro/North Front Range NAA area from “moderate” to “serious” under the 2008 NAAQS. This “serious” classification will trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements, which may in turn result in significant costs, and delays in obtaining necessary permits applicable to our operations. 

SB 19-181 also requires, among other things, that the Air Quality Control Commission (“AQCC”) adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle. The AQCC anticipates holding several rulemakings over the next several years to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. In December 2019, the AQCC held the first of several rulemakings that are anticipated as a result of SB 19-181. As part of that rulemaking, the AQCC adopted significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements and increased LDAR frequencies for facilities in certain proximity to occupied areas.


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State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public Health and Environment's ("CDPHE") Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping and reporting matters. In October 2019, the CDPHE published a human health risk assessment for oil and gas operations in Colorado, which used oil and gas emission data to model possible human exposure and found a possibility of negative health impacts at distances up to 2,000 feet away under worst case conditions. In response, the COGCC announced that it will more rigorously scrutinize permit applications for wells within 2,000 feet of a building unit, work with CDPHE to obtain better site-specific data on oil and gas emissions, and consider the resulting data for possible future rulemaking.

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 certain wetlands or other waters of the U.S. In June 2015, the EPA issued a final rule that attempted to clarify the CWA’s jurisdictional reach over “waters of the United States” (“2015 Clean Water Rule”) and replace the pre-existing 1986 rule and guidance. In February 2018, the EPA issued a rule to delay the applicability of the 2015 Clean Water Rule until February 2020, but this delay rule was struck following a court challenge. Other federal district courts, however, issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself in several states. Taken together, the 2015 Clean Water Rule has been in effect in 22 states, including Colorado, and temporarily stayed in 27 states (the 2015 Clean Water Rule was in effect in certain counties in New Mexico and not in others). In those remaining states, the 1986 rule and guidance remained in effect. In October 2019, the EPA and the USACE issued a final rule to repeal the 2015 Clean Water Rule (the “2019 Repeal Rule”). With the 2019 Repeal Rule, the agencies report that they will implement the pre-2015 Clean Water Rule regulations and guidance nationwide. The 2019 Repeal Rule became effective on December 23, 2019; accordingly, the 2015 Clean Water Rule is no longer in effect in any state. However, numerous legal challenges to the 2019 Repeal Rule have already been filed in federal court.

In February 2019, the EPA and the USACE published a proposed new rule that would differently revise the definition of “waters of the United States” and essentially replace both the 1986 rule and the 2015 Clean Water Rule. On January 23, 2020, the EPA and USACE announced the final new rule, titled the Navigable Waters Protection Rule (“2020 Rule”). The 2020 Rule will go into effect sixty days after publication in the Federal Register. The 2020 Rule will generally regulate four categories of “jurisdictional” waters: (i) territorial seas and traditional navigable waters (i.e., large rivers); (ii) perennial and intermittent tributaries of these waters; (iii) certain lakes, ponds and impoundments; and (iv) wetlands to jurisdictional waters. The 2020 Rule also includes 12 categories of exclusions, or “non-jurisdictional” waters, including groundwater, ephemeral features and diffuse stormwater run-off over upland areas. In particular, the 2020 Rule will likely regulate fewer wetlands areas than were regulated under the 1986 rule and the 2015 Clean Water Rule because it does not regulate wetlands that are not adjacent to jurisdictional waters. Following publication, this new definition of “waters of the United States” will likely be challenged and sought to be enjoined in federal court. If and when the 2020 Rule goes into effect, it will change the scope of the CWA’s jurisdiction, which could result in increased costs and delays with respect to obtaining permits for discharges of pollutants or dredge and fill activities in waters of the U.S., including regulated wetland areas.

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 U.S. 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 repair of pipelines, roads and drill pads, respectively, and related structures in waters of the U.S. that impact less than a half-acre of waters of the U.S. 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.

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.


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Other

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.
    
In February 2018, the COGCC comprehensively amended its regulations for oil, gas and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection and other matters. In November 2019, the COGCC further amended its flowline regulations pursuant to SB 19-181 to impose additional requirements regarding flowline mapping, operational status, certification and abandonment, among other things. The COGCC has also adopted or amended numerous other rules in recent years, including rules relating to safety, flood protection and spill reporting.

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. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016.
 
Employees

As of December 31, 2019, we had approximately 540 full-time employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be positive.

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 our website at www.pdce.com as soon as reasonably practicable after such material is filed with, or furnished to, the SEC. 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 (303) 860-5800.

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 the value of an investment in our common stock or other securities.

Risks Relating to SRC Acquisition

We may not achieve the anticipated benefits of the SRC Acquisition.

The success of the SRC Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and SRC’s businesses, and there can be no assurance that we will be able to successfully integrate SRC or otherwise realize the anticipated benefits of the SRC Acquisition. Difficulties in integrating SRC into our company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:

the inability to successfully integrate SRC into our company in a manner that permits us to achieve the anticipated benefits and cost savings from the SRC Acquisition;
complexities associated with managing a larger, more complex, integrated business;
not realizing anticipated operating synergies;
integrating personnel from the two companies and the loss of key employees;
potential unknown liabilities and unforeseen expenses associated with the SRC Acquisition;
integrating relationships with customers, vendors and business partners;
performance shortfalls as a result of the diversion of management’s attention caused by the SRC Acquisition and the integration of SRC’s operations into our company;
managing expanded environmental and other regulatory compliance obligations related to SRC's facilities and operations;
consolidating information technology systems; and
the disruption of, or the loss of momentum in, our business or inconsistencies in standards, controls, procedures and policies.

Our results may suffer if we do not effectively manage our expanded operations following the SRC Acquisition.
        
Following completion of the SRC Acquisition, the size of our business has increased significantly. Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of SRC into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with various business partners. Failure to successfully manage the combined company may have an adverse effect on our financial condition, results of operations or cash flows.

Sales of substantial amounts of our common stock in the open market, by former SRC shareholders or otherwise, could depress our stock price.

            Former SRC shareholders may not wish to continue to invest in our common stock, or for other reasons may wish to dispose of some or all of their interests in our common stock, and as a result may seek to sell their shares of our common stock. Shares of our common stock that were issued to former holders of SRC common stock in the SRC Acquisition are freely tradable by such stockholders without restrictions or further registration under the Securities Act, provided, however, that any stockholders who are our affiliates will be subject to certain resale restrictions under the Securities Act. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of our common stock, may affect the market for, and the market price of, our common stock in an adverse manner. We issued approximately 39 million shares of our common stock to SRC shareholders. As of February 18, 2020, we had approximately 100 million shares of common stock outstanding and approximately 1.7 million shares of common stock subject to outstanding stock-based compensation arrangements and other rights to purchase or acquire our shares.
        
If our stockholders, including former SRC shareholders, sell substantial amounts of PDC common stock in the public market, the market price of our common stock may decrease. These sales might also make it more difficult for us to raise capital by selling equity or equity-related securities at a time and price that we otherwise would deem appropriate.



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Following the SRC Acquisition, we are proportionately more exposed to regulatory and operational risks associated with oil and gas operations in Colorado and other risks associated with a more geographically-concentrated asset base.

All of SRC’s properties, production and reserves immediately prior to the SRC Acquisition were located in Colorado. As a result of the SRC Acquisition, the percentage of our properties, production and reserves that are located in Colorado have increased and our exposure to the risk of unfavorable regulatory developments in the state have therefore increased as well. Similarly, the operations of both our company and SRC have been adversely affected in recent years by limitations in the availability of adequate midstream infrastructure in the Wattenberg Field. The increased percentage of our combined production located in the Wattenberg Field following the SRC Acquisition has proportionately increased our exposure to this risk, as well as other risks associated with operating in a more concentrated geographic area.                     

The market price of our common stock will continue to fluctuate, and may decline if the benefits of the SRC Acquisition do not meet the expectations of financial analysts.

            The market price of our common stock may fluctuate significantly, including if we do not achieve the anticipated benefits of the SRC Acquisition as rapidly, or to the extent anticipated by, financial analysts or if the effect of the SRC Acquisition on our financial results is not consistent with the expectations of financial analysts.

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 ("OPEC"), and global events, such as the ongoing COVID-19 outbreak; and
regulatory changes.

The price of oil has historically been volatile, due in recent years to a combination of factors including increased U.S. supply and global economic concerns. In 2019, oil prices ranged from highs of over $65 per barrel to lows of approximately $45 per barrel. Prices for natural gas and NGLs have also experienced substantial 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.


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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 have restricted our production in the area and reduced our revenue. Similarly, rapid production growth in the Permian Basin has strained the available midstream infrastructure there, at times presenting the potential for adverse effects on our operations. The use of alternative forms of transportation for oil production, such as trucks or rail, involves 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;
Some upstream energy companies have 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; and
The possibility that new or amended regulations, including regulations that increase mandatory setbacks or enhance local control of oil and gas development, could result in severely curtailed drilling activities in Colorado may discourage investment in midstream facilities.

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.
 
We have pursued a variety of strategies to alleviate some of the risks associated with the midstream services and facilities upon which we rely. There can be no assurance that the strategies we pursue will be successful or adequate to meet our needs. For example, our principal midstream provider in the Wattenberg Field commenced operation of a new facility in the third quarter of 2019 and the benefits to us of that facility were less than we expected.

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, cost 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:

From time to time ballot initiatives have been proposed in Colorado that would adversely affect our operations. For example, Proposition 112, a voter initiative that qualified for the ballot for the general election in November 2018, would have effectively prohibited the vast majority of our planned drilling activity in Colorado by imposing mandatory 2,500 foot setbacks between new oil and gas wells and any occupied structure or designated "vulnerable area." Although Proposition 112 was defeated at the polls, subsequent legislation significantly amended existing state law to, among other things, require the COGCC to prioritize public health and environmental concerns in its decisions, instruct the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and authorize local governmental authorities to impose limitations on oil and gas development activities more stringent than those imposed at the state level. In October 2019, the CDPHE released a study of potential health risks that modeled certain exposure scenarios at distances up to 2,000 feet, based on

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data collected at oil and gas development and production sites. The study concluded that modeling results “support increased concern for short-term adverse effects” in a very narrow set of hypothetical circumstances associated with the development phase of oil and gas operations. As a result, the COGCC has determined that permit applications for locations and wells up to 2,000 feet from building units will be subject to additional agency review to ensure that the application complies with the new legislation. We may therefore experience significant delays in obtaining permits and approvals for some wells and drilling locations. As a result of the SRC Acquisition, the percentage of our combined properties, production and reserves located in Colorado have increased and our exposure to the risk of unfavorable regulatory developments in the state has therefore increased as well.
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 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 U.S. 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 U.S. 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. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits.
Proposals are made from time to time to amend U.S. federal and state 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, 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.

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. Unexpected lease expirations could occur if our actual drilling activities differ materially from our current expectations, and this could result in impairment charges. The risk of lease expiration is greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop the locations necessary to maintain our leases 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, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.


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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;
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.

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 often increase as well. 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. All of the producing properties and reserves we acquired in the SRC Acquisition are located in the Wattenberg Field. As a result, the transaction increased the risks we face with respect to the geographic concentration of our properties.

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.

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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.
From time to time, we have been subject to sanctions and lawsuits relating to alleged noncompliance with regulatory requirements. For example, in October 2017, in order to settle a lawsuit brought against us by the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, we entered into a consent decree pursuant to which we paid a fine and agreed to implement certain operational changes. The lawsuit claimed that we failed to operate and maintain certain equipment in compliance with applicable law. In addition, as a result of the SRC Acquisition, we are subject to the obligations and requirements of a 2018 Compliance Order on Consent (“COC”) entered into by SRC with CDPHE, applicable to certain SRC oil and gas production facilities. That COC resolved SRC’s alleged violations related to storage tank emissions and contains requirements similar to those contained in our consent decree. The CDPHE has agreed to revise the COC to make the inspection and monitoring requirements, among others, consistent with those contained in our consent decree. This COC will apply only to those facilities formerly subject to the SRC COC.
In May 2019, WildEarth Guardians filed a complaint against several oil and gas operators, including us, in the U.S. District Court for the District of Colorado. The complaint seeks civil penalties and injunctive relief and alleges, among other things, that we failed to obtain a major source air quality permit for two of our production facilities. We have filed a motion to dismiss the complaint.
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, the receipt of a permit with unreasonable or unexpected conditions or costs or the revocation of a previously granted permit, could have a material adverse effect on our ability to explore or develop our properties.
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, in a timely manner 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, supply concerns and regulatory issues, particularly in relatively arid climates such as eastern Colorado and western Texas. For example, increased drilling activity in the Delaware Basin in recent years has led to heightened concerns about water supply issues in the area and this may lead to regulatory actions, including rules providing local governments greater authority over water use, that adversely impact our operations.

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. Wells in the Delaware Basin typically produce relatively large amounts of water that require disposal and 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. 

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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 $38.5 million and $458.4 million in 2019 and 2018, respectively, to write down assets. 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;
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, in part because 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, 2019, approximately 65 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 $3.3 billion during the five years ending December 31, 2024, as estimated in the calculation of our 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

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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;
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, though Colorado now requires applicants to own or secure consent from the owners of more than 45 percent of the minerals to be pooled. Other states, notably Texas, restrict involuntary pooling to a much narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and leases. In states such as Texas where pooling is accomplished primarily on a voluntary basis, or in states such as Colorado if we cannot meet the minimum requirement for ownership and consent, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than all (or cannot secure the ownership or consent of the required minimum amount) of the leasehold in the proposed units or one or more of our leases in the proposed units does not provide the necessary pooling authority. If third parties in the proposed units are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, which would limit the total horizontal wells we can drill. Further, the number of available locations will depend in part on the expected lateral lengths of the horizontal wells we drill. Because the intended lateral length of a horizontal 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. In addition, our Wattenberg Field inventory was further reduced by recent acreage exchange transactions in which we received, among other things, increased working interests in certain locations in exchange for our right to develop other locations. We anticipate that our remaining locations in the field will not, on average, be as productive or as economic as many those we have drilled in recent years, due to lower anticipated overall production or higher gas-to-oil ratios.

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In the Delaware Basin, our inventory is subject to, among other things, lease expiration issues and our continued analysis of geologic issues in certain areas.

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. 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. For example, the data we use to model anticipated results from wells in a particular area may prove to be not representative of actual results from typical wells in the area, and this could result in production that falls short of estimates reflected in our internal business plans and/or guidance, "type curve" or other disclosures we make to the public. This risk is higher for us in certain areas in the Delaware Basin that have relatively complex geological characteristics and correspondingly greater variability in well results. 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.

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

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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.
In addition, certain technical risks relating to the drilling of horizontal wells - including those relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - have increased in recent years because we have increased the average lateral length of the horizontal wells we drill. Longer-lateral wells are also typically more expensive and require more time for preparation. 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 using multi-well pads with longer lateral wells, 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.

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, extreme temperatures 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.
Including wells that we received in the SRC Acquisition, we currently operate approximately 78 percent of all the wells in which we have 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 of an operator to conduct drilling activities properly, or its 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 activities that we bel