SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to _________
Commission File Number 001-37419
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)
|(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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
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, 2020 was $1.2 billion (based on the closing price of $12.44 per share as of the last business day of the fiscal quarter ending June 30, 2020).
As of February 16, 2021, there were 99,781,332 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 2021 Annual Meeting of Stockholders.
PDC ENERGY, INC.
2020 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
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.
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 Annual Report on Form 10-K 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") and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 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; impacts of Colorado political matters, including recent rulemaking initiatives, given our geographic concentration; 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; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; ability to meet our volume commitments to midstream providers and timing and adequacy of midstream infrastructure; the potential return of capital to shareholders through buyback of shares and/or issuance of a dividend; ongoing compliance with our consent decree; risk of our counterparties non-performance on derivative instruments; and our ability to repay our 1.125% convertible notes due 2021 (the "2021 Convertible Notes") and fund planned activities.
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 our 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:
•the COVID-19 pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters;
•changes in global production volumes and demand, including economic conditions that might impact demand and prices for the products we produce;
•impact of political and regulatory developments in Colorado, particularly with respect to additional permit scrutiny;
•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;
•volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices, including risks relating to decreased revenue, income and cash flow, write-downs and impairments and availability of capital;
•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 of those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;
•declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments;
•changes in estimates of proved reserves;
•inaccuracy of reserve estimates and expected production rates;
•potential for production decline rates from our wells being greater than expected;
•timing and extent of our success in discovering, acquiring, developing and producing reserves;
•availability and cost 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;
•risks incidental to the drilling and operation of crude oil and natural gas wells;
•difficulties in integrating our operations and potential effects on capital requirements as a result of any significant acquisitions or acreage exchanges;
•increases 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;
•success in marketing our crude oil, natural gas and NGLs;
•effect of crude oil and natural gas derivative 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;
•our ability to replace our oil and natural gas reserves;
•title defects in our oil and natural gas properties;
•civil unrest, terrorist attacks and cyber threats;
•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 prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
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 west 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 horizontal Wolfcamp zones.
The following map presents the general locations of our development and production activities as of December 31, 2020:
The following table presents selected information regarding our results of operations for the periods presented:
|Year Ended/As of|
|December 31,||Percent Change|
|(production and reserves in MMBoe, dollars in millions)|
|Gross productive wells||3,727 ||2,649 ||41 ||%|
|Net productive wells||2,841 ||2,101 ||35 ||%|
|Horizontal percentage||57 ||%||48 ||%||19 ||%|
|Gross operated wells turned-in-line||137 ||135 ||1 ||%|
|Net operated wells turned-in-line||129.5 ||125.0 ||4 ||%|
|Wattenberg Field||57.5 ||38.0 ||51 ||%|
|Delaware Basin||10.8 ||11.4 ||(5)||%|
|Total||68.4 ||49.4 ||38 ||%|
|Proved reserves||731.1 ||610.9 ||20 ||%|
|Proved developed reserves percentage||44 ||%||35 ||%||26 ||%|
|Standardized measure ||$||3,282.2 ||$||3,310.3 ||(1)||%|
|$||3,454.6 ||$||3,837.0 ||(10)||%|
|Liquidity ||$||1,400 ||$||1,291 ||8 ||%|
|Leverage ratio||1.7 ||1.4 ||21 ||%|
(1)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. generally accepted accounting principles (“U.S. GAAP”), but rather should be considered in addition to the standardized measure. See 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 included elsewhere in this report.
Significant 2020 Events
In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt (the “SRC Acquisition”). Upon closing, we issued approximately 38.9 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"). SRC's acreage was located on large, contiguous acreage blocks in the core Wattenberg Field. The acquisition added approximately 83,000 net acres to our asset portfolio.
In connection with the completion of the SRC Acquisition, we paid off and terminated SRC's revolving credit facility and we assumed $550.0 million aggregate principal amount of 6.25% senior notes due December 1, 2025 (the "SRC Senior Notes"). On January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes at 101 percent of the principal amount. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. An aggregate principal amount of approximately $102.3 million of the SRC Senior Notes remains outstanding. We funded the aforementioned payment and termination of SRC's credit facility and repurchase of SRC Senior Notes with proceeds from our revolving credit facility.
Senior Notes Offering
In September 2020, we issued an additional $150.0 million principal amount of our 5.75% Senior Notes due in May 2026 (the "2026 Senior Notes"). The net proceeds from the offering were used to repay a portion of the amount outstanding under our revolving credit facility.
Business Strategy and Key Strengths
Our long-term business strategy focuses on creating shareholder value by: (i) delivering attractive returns from responsible development of our crude oil and natural gas properties; (ii) maintaining financial strength; (iii) generating sustainable cash flows from operations in excess of our capital investments in crude oil and natural gas properties; and (iv) returning capital to shareholders. Our key strengths 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 cash flows year-over-year, even through challenging commodity price environments. As of December 31, 2020, we had total liquidity of $1.4 billion, a leverage ratio, as defined in our revolving line of credit facility agreement, of 1.7x and commodity derivative positions covering approximately 14.2 MMBbls and 5.8 MMBbls of crude oil production for 2021 and 2022, respectively. As of the same date, we had hedged approximately 94,400 BBtu and 26,100 BBtu of natural gas production for 2021 and 2022, respectively.
•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. Our adjusted free cash flows, a non-GAAP measure, is used as a measure of our ability to return capital to shareholders, reduce debt levels and maintain strong liquidity. In 2020, we generated cash flows from operations of $870.1 million and adjusted free cash flows of $399.3 million.
•Absolute debt reduction, conservative total leverage targets and return of capital to shareholders. Through successful execution of our business plan, we meaningfully reduced our indebtedness to below $1.5 billion as of the date of this report. Consistent with our strategic goals, PDC reinstated its Stock Repurchase Program in late February 2021 and our board of directors recently approved a quarterly dividend program expected to commence mid-2021. PDC is positioned to focus on returning capital to shareholders and continued additional debt reductions, with a long-term target leverage ratio of 1.0x or below.
•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. We currently operate approximately 77 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.
•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. 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. We also strive to achieve continuous improvement in our corporate governance and have a demonstrated commitment to being responsive to investor input. In September of 2020, we released our inaugural Sustainability Report, which
aligned with a formal Environmental, Social, and Governance ("ESG") reporting framework – Sustainability Accounting Standards Board – and increased transparency into our operations.
•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 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. We continue to make progress towards improved capital efficiency through various drilling initiatives and completion designs in the Delaware Basin. 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. We continually optimize the expertise we have developed in the Wattenberg Field, to increase the efficiency of our Delaware Basin processes and procedures. 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.
•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, legal and strategic aspects of the oil and gas industry. This team has a proven track record of executing value-added capital investment programs 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.
Wattenberg Field. In the Wattenberg Field, we have identified a gross operated inventory of approximately 2,000 horizontal drilling locations that we expect to generate acceptable rates of return based on forward strip pricing, with an average lateral length of approximately 9,000 feet. Our inventory consists of approximately 200 gross operated DUCs, 300 approved permits, reflecting approximately 3.5 years of turn-in-line activity based on our current drilling plan, and 1,500 unpermitted locations. 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. We continue to pursue various business development initiatives, with a focus on acreage exchanges or acquisitions, designed to increase our Wattenberg Field project inventory or to increase our ownership in our operated wells.
Delaware Basin. In the Delaware Basin, we have identified a gross operated economic inventory of approximately 115 horizontal drilling locations and 20 gross operated DUCs that we expect to generate acceptable rates of return based on forward strip pricing, targeting the Wolfcamp A and Wolfcamp B zones, within the oilier eastern and north central portions of our acreage. We continue to analyze and test various wellbore spacing configurations in areas of the field. Additionally, we have the possibility of adding inventory locations, outside of our target zones, in the future if the return on the wells meet our required economics. The average lateral length of these locations is approximately 8,900 feet. Wells in the Delaware Basin typically have productive horizons at depths of approximately 9,000 to 11,500 feet below the surface. We continue to pursue
various business development initiatives, with a focus on acreage exchanges and joint development projects, designed to increase our Delaware Basin project inventory by establishing longer lateral drilling units capable of delivering attractive economic returns.
Oil and Gas Production and Operations
Proved Oil and Gas Reserves
The following table presents our proved reserve estimates as of December 31, 2020, 2019 and 2018:
Crude oil and condensate (MMBbls)
|212 ||197 ||190 |
Natural gas (Bcf)
|1,901 ||1,558 ||1,336 |
|203 ||154 ||132 |
Total proved reserves (MMBoe)
|731 ||611 ||545 |
Proved developed reserves (MMBoe)
|322 ||214 ||180 |
Standardized measure (in millions)
|$||3,282.2 ||$||3,310.3 ||$||4,447.7 |
Estimated undiscounted future net cash flows (in millions) (1)
|$||5,633.1 ||$||5,895.9 ||$||7,735.0 |
PV-10 (in millions) (2)
|$||3,454.6 ||$||3,837.0 ||$||5,321.3 |
(1)Amount represents aggregate undiscounted future net cash flows, before income taxes approximately $5.9 billion, $6.8 billion and $9.1 billion as of December 31, 2020, 2019 and 2018, respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.3 billion, $0.9 billion and $1.4 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, 2020 as compared to December 31, 2019 were primarily due to the SRC Acquisition which were partially offset by downward revisions as a result of decreases in realized prices and revised drilling plans following the completion of the SRC Acquisition.
The following table presents our proved reserve estimates by category as of December 31, 2020:
|As of December 31, 2020|
|Operating Region/Area||Crude Oil and Condensate (MMBbls)||Natural Gas (Bcf)||NGLs (MMBbls)||Crude Oil Equivalent (MMBoe)||Percent|
|Wattenberg Field||69.1 ||752.3 ||80.9 ||275.5 ||38 ||%|
|Delaware Basin||17.2 ||108.6 ||10.8 ||46.0 ||6 ||%|
|Total proved developed||86.3 ||860.9 ||91.7 ||321.5 ||44 ||%|
|Wattenberg Field||105.7 ||958.8 ||102.7 ||368.1 ||50 ||%|
|Delaware Basin||19.7 ||81.5 ||8.1 ||41.5 ||6 ||%|
|Total proved undeveloped||125.4 ||1,040.3 ||110.8 ||409.6 ||56 ||%|
|Total proved reserves|
|Wattenberg Field||174.8 ||1,711.1 ||183.6 ||643.6 ||88 ||%|
|Delaware Basin||36.9 ||190.1 ||18.9 ||87.5 ||12 ||%|
|Total proved reserves||211.7 ||1,901.2 ||202.5 ||731.1 ||100 ||%|
Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Positive impacts of these variables and assumptions may result in a longer economic productive life of a property or the recognition of more economically viable proved undeveloped ("PUD") reserves, while negative impacts of these variables and assumptions may result in corresponding negative impacts. All of our proved reserves are located in the United States.
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.
|Average Benchmark Prices|
Crude Oil (per Bbl) (1)
Natural Gas (per MMBtu) (1)
NGLs (per Bbl) (2)
|2020||$||39.57 ||$||1.99 ||$||39.57 |
|2019||55.69 ||2.58 ||55.69 |
|2018||65.56 ||3.10 ||65.56 |
(1)Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively.
(2)For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.
The netted back price used to estimate our reserves, by commodity, are presented below.
Price Used to Estimate Reserves (1)
|December 31,||Crude Oil |
|Natural Gas |
NGLs (per Bbl)
|2020||$||37.52 ||$||1.26 ||$||10.55 |
|2019||52.63 ||1.50 ||12.21 |
|2018||61.14 ||2.15 ||23.04 |
(1)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.
Proved Reserves Sensitivity Analysis. We have performed an analysis of our proved reserve estimates as of December 31, 2020 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 2020 NYMEX price for crude oil used in estimating our reported proved reserves with $35.00 as shown on the table below, and leaving all other parameters unchanged, results in changes to our estimated proved reserves as shown.
|Pricing Scenario - NYMEX|
|Crude Oil (per Bbl) ||Natural Gas (per MMBtu) ||Proved Reserves (MMBoe)||% Change from December 31, 2020 Estimated Reserves||PV-10 |
|PV-10 % Change from December 31, 2020 Estimated Reserves|
2020 SEC Reserve Report (1)
|$||39.57 ||$||1.99 ||731.1 ||— ||$||3,454.6 ||— |
|Alternate Price Scenario||$||35.00 ||$||1.99 ||723.4 ||(1)||%||$||2,921.4 ||(15)||%|
(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.
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 our standardized measures, as well as other information regarding our proved reserves, see Supplemental Information- Crude Oil and Natural Gas Properties included in Item 8. Financial Statements and Supplementary Data provided with our consolidated financial statements included elsewhere in this report.
Preparation of Reserve Estimates
Our proved reserves estimates as of December 31, 2020 were based on evaluations prepared by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. ("Ryder Scott") and Netherland, Sewell & Associates, Inc. ("NSAI") (collectively, our "external engineers"). Our proved reserve estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (the "FASB").
Controls Over Reserve Report Preparation. Inputs and major assumptions related to 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 our external engineers.
Annually, the Director of Reservoir Engineering & Technology reviews the reserves to ensure all the necessary significant inputs and steps are completed within our reserve process. After final approval from the Director of Reservoir Engineering & Technology, the results are presented to senior management and to our board of directors for their review.
Together, these internal controls are designed to promote a comprehensive, objective, and accurate reserves estimation process. As an additional confirmation of the reasonableness of our internal estimates, Ryder Scott and NSAI performed an independent evaluation of our estimated proved reserves in the Wattenberg Field and Delaware Basin, respectively, as of December 31, 2020.
When preparing our reserve estimates, our external engineers do not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties or sales of production. Our external engineers 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 our external engineers and reviewed by our engineering staff and management prior to issuance by those firms.
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.
Qualifications of Responsible Technical Persons. 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 20 years of oil and gas experience.
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, 2020 have been filed as Exhibits 99.1 and 99.2 to this report.
Production, Prices and Costs
Production and operating data for the years ended December 31, 2020, 2019 and 2018 was included in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this report.
The following table presents our productive wells by operating area as of December 31, 2020:
|Crude Oil||Natural Gas||Total|
|Operating Region/Area|| Gross|| Net||Gross|| Net || Gross|| Net|
|Wattenberg Field||2,062 ||1,439.2 ||1,552 ||1,310.4 ||3,614 ||2,749.6 |
|Delaware Basin||50 ||31.7 ||63 ||59.2 ||113 ||90.9 |
|Total productive wells||2,112 ||1,470.9 ||1,615 ||1,369.6 ||3,727 ||2,840.5 |
Developed and Undeveloped Acreage
The following table presents our developed and undeveloped lease acreage as of December 31, 2020:
|Operating Region/Area||Gross ||Net||Gross||Net||Gross||Net|
|Wattenberg Field||166,166 ||154,958 ||70,797 ||64,720 ||236,963 ||219,678 |
|Delaware Basin||27,525 ||25,401 ||1,362 ||635 ||28,887 ||26,036 |
|Total acreage||193,691 ||180,359 ||72,159 ||65,355 ||265,850 ||245,714 |
Developed lease acreage are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells. Undeveloped acreage are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
Substantially all of our undeveloped acreage in the Wattenberg Field and Delaware Basin are related to leaseholds that are held by production. Our Wattenberg Field leaseholds at risk to expire in 2021, 2022 and 2023 are not material. In the Delaware Basin, the majority of the drilling obligations or continuous drilling clauses associated with the asset have been met. Our Delaware Basin leaseholds at risk to expire in 2021, 2022 and 2023 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.
The following tables set forth a summary of our developmental and exploratory well drilling results 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 two years.
|Gross Development Well Drilling Activity|
|Year Ended December 31,|
|Wattenberg Field, operated wells||124 ||214 ||— ||114 ||145 ||— ||139 ||133 ||— |
|Wattenberg Field, non-operated wells||27 ||48 ||— ||12 ||41 ||— ||20 ||5 ||— |
|Delaware Basin, operated wells||13 ||18 ||— ||21 ||26 ||— ||26 ||22 ||1 |
|Delaware Basin, non-operated wells||— ||— ||— ||9 ||— ||— ||11 ||— ||— |
|Total gross development wells||164 ||280 ||— ||156 ||212 ||— ||196 ||160 ||1 |
(1)Amounts include 88 and seven gross in-process operated and non-operated development wells, respectively, received in the SRC Acquisition, of which a portion were completed during the period.
|Net Development Well Drilling Activity|
|Year Ended December 31,|
|Wattenberg Field, operated wells||116.5 ||201.8 ||— ||105.1 ||135.0 ||— ||126.8 ||122.4 ||— |
|Wattenberg Field, non-operated wells||0.9 ||3.5 ||— ||1.1 ||3.7 ||— ||2.5 ||0.9 ||— |
|Delaware Basin, operated wells||13.0 ||17.2 ||— ||20.1 ||25.3 ||— ||24.5 ||16.3 ||1.0 |
|Delaware Basin, non-operated wells||— ||— ||— ||1.3 ||— ||— ||1.2 ||— ||— |
|Total net development wells||130.4 ||222.5 ||— ||127.6 ||164.0 ||— ||155.0 ||139.6 ||1.0 |
(1)Amounts include 80 and one net in-process operated and non-operated development wells, respectively, received in the SRC Acquisition, of which a portion were completed during the period.
|Exploratory Well Drilling Activity|
|Year Ended December 31,|
|Delaware Basin||2 ||2.0 ||2 ||1.9 ||2 ||2.0 ||4 ||3.9 ||3 ||2.8 ||2 ||2.0 |
There were no exploratory drilling activities in the Wattenberg Field during 2020, 2019 and 2018.
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 amounts borrowed under our revolving credit facility.
As of December 31, 2020, we leased corporate space in 1775 Sherman Street, Suite 3000, Denver, Colorado, where our corporate headquarters is located. We also maintain offices in Evans, Colorado and Midland, Texas. We anticipate closing on the sale of our office building we own in Bridgeport, West Virginia in the first half of 2021.
We sell our crude oil and natural gas production to marketers and other purchasers which have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. The majority of our crude oil and natural gas production is transported through pipelines.
We made sales to four customers that each contributed to 10 percent or more of our 2020 total crude oil, natural gas and NGLs 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.
Seasonality of Business
Weather conditions affect the demand for and prices of crude oil and natural gas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of our annual results.
Certain of our firm sales agreements for crude oil include delivery commitments. We believe our current production and reserves are sufficient to fulfill these delivery commitments. See Note 12 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data for more information.
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 Colorado Oil and Gas Conservation Commission ("COGCC") and 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 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.
In addition, the Energy Policy Act of 2005 (the "EPAct 2005") prohibits “any entity” from using 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 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.
Democratic control of the House, Senate and White House could lead to increased regulatory oversight and increased regulation and legislation, particularly around oil and gas development on federal lands, climate impacts and taxes.
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 April 2019, the EPA, pursuant to a consent decree between the EPA and a coalition of environmental groups and a related review of RCRA regulations, determined that revision of the regulations is not necessary. 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 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 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.
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, Senate Bill 19-181 ("SB 19-181"), gives local governmental authorities increased authority to regulate the siting and surface impacts of oil and gas development. 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.
The states in which we currently operate have adopted or may adopt laws and regulations that impose or could impose, among other requirements, more stringent permitting processes and increased environmental protection and monitoring.
SB 19-181 changed the mission of the COGCC from fostering responsible and balanced development to regulating development to protect public health and the environment and directed the COGCC to undertake rulemaking on various operational matters. Pursuant to this direction, the COGCC conducted a series of rulemaking hearings during 2020 which resulted in updated regulatory and permitting requirements, including siting requirements. The COGCC commissioners determined that locations with residential or high occupancy building units within 2,000 feet would be subject to additional siting requirements, but also supported “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. However, during the proceedings around SB 19-181, top Democratic leaders in the Colorado House and Senate, who served as authors and sponsors of the bill, made public statements indicating SB 19-181 was not intended to allow an outright ban on oil and gas development. At least one COGCC commissioner has publicly indicated his agreement with that interpretation.
In late July 2020, Governor Polis authored an op-ed stating that both industry and mainstream environmental groups have communicated a willingness to stand down on ballot initiatives in 2020, and to work together to prevent initiatives in 2022, while the regulatory process associated with SB 19-181 is in progress. As part of that agreement, Governor Polis stated that he would “actively oppose” ballot initiatives around the oil and gas industry and acknowledged the importance of regulatory certainty.
It is nevertheless possible that future ballot initiatives will be proposed 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.
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. The BLM’s rescission of the rule was challenged in the United States District Court for the Northern District of California and in March 2020 the court issued a ruling upholding BLM’s rescission of the rule. That court ruling is currently being appealed.
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.
Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities.
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. Since 2014, Colorado has engaged in multiple rulemakings to adopt significant additional adopted rules regulating methane emissions from the oil and gas sector, and Colorado is expected to continue these efforts over the next several years.
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 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 intention to withdraw from the Paris Agreement. The notification began a one-year process for withdrawal on November 4, 2020. On January 20, 2021, President Joe Biden executed an executive order to re-enter the Paris Agreement.
Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations.
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 2020, the EPA issued a new rule which amended the 2016 requirements. In this rule, the EPA removed all sources in the transmission and storage segment of the oil and natural gas industry from regulation. The rule also rescinded the methane requirements in the 2016 regulations and loosened monitoring and repair regulations aimed at preventing methane leaks. The new rule was challenged in the U.S. Court of Appeals for the D.C. Circuit, but in October 2020 the Court declined to issue a permanent stay of the new rule while it considered the merits of the challenge. The new rule therefore is currently in effect. However, the future of the new rule is in flux as the Court could vacate the rule such that the original 2016 regulations would go back into effect.
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 “2016 Rule”). The 2016 Rule required 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 revised the 2016 Rule (the “2018 Revised Rule”). The 2018 Revised Rule, among other things, rescinded 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 2018 Revised Rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico filed challenges to the 2018 rule in the United States District Court for the Northern District of California, and in July 2020, the United States District Court for the Northern District of California vacated BLM’s 2018 Revised Rule. However, in October 2020, the United States District Court for the District of Wyoming issued a ruling vacating the 2016 Rule, holding that BLM exceeded its statutory authorities and acted arbitrarily. That ruling is expected to be appealed.
In 2019, 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 "moderate" to “serious” under the 2008 national ambient air quality standard ("NAAQS"). This increase in non-attainment status to "serious" triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in December 2020 that are applicable to our operations. Based on current air quality monitoring data, it is expected that the Denver Metro/North Front Range NAA will be further "bumped-up" to "severe" status in 2021 or 2022. This will trigger additional obligations for the state under the CAA and will result in new and more stringent air quality permitting and 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 has undertaken a multi-year rulemaking process to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. Between December 2019 and December 2020, the AQCC completed several rulemakings as a result of SB 19-181, adopting significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements, increased LDAR frequencies for facilities in certain proximity to occupied areas, and emission control requirements for certain large natural gas fired engines. The AQCC plans to conduct additional rulemakings related to SB 19-181 in 2021.
Additionally, in response to HB 19-1261, which established statewide greenhouse gas reduction targets, Colorado, on September 30, 2020, released a public comment draft of its Greenhouse Gas Pollution Reduction Roadmap, which details early action steps the state can take toward meeting the near-term goals of reducing greenhouse gas (GHG) pollution 26% by 2025 and 50% by 2030 from 2005 levels. On October 23, 2020, the AQCC issued the Resolution to Ensure Greenhouse Gas Reduction Goals Are Met in support of the roadmap, which estimates emission reductions needed from the oil and gas sector of 36% by 2025 and 50% by 2030. To meet these targets, the CDPHE has also initiated a stakeholder process to develop and consider additional greenhouse gas reduction strategies from the oil and gas sector, to be finalized in a 2021 AQCC rulemaking.
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 2020, the COGCC relied in part on a previously-performed human health risk assessment in adopting new siting requirements. The COGCC also generally prohibited the venting or flaring of natural gas during drilling, completion, and production operations.
While the State of Texas has not formally conducted a recent rulemaking related to air emissions, scrutiny of oil and gas operations and the rules affecting them have increased in recent years. For example, EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and gas production facilities and transmission infrastructure. In addition, the Texas Railroad Commission has increased oversight related to flaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future.
The federal Clean Water Act ("CWA") and analogous state laws impose strict controls concerning the discharge into regulated waterbodies and wetlands 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 federally regulated waters of the U.S. ("WOTUS"). In October 2019, the EPA and the Army Corps of Engineers ("USACE") issued a final rule to repeal previous regulations (the "2019 Repeal Rule") and implement the 1986 WOTUS regulations and guidance nationwide, until a new replacement rule could be adopted. The 2019 Repeal Rule became effective on December 23, 2019. However, numerous legal challenges to the 2019 Repeal Rule have been filed in federal court.
On April 21, 2020, the EPA and USACE issued a final new replacement on the scope of regulated WOTUS, titled the Navigable Waters Protection Rule ("2020 Rule"). The 2020 Rule was judicially challenged in several different lawsuits, which are still pending, but it was preliminarily enjoined only in Colorado and went into effect in all other states on June 22, 2020. In Colorado only, the former 1986 WOTUS rule and related guidance will control until the lawsuit there is resolved. In all other states, the 2020 Rule will remain in effect unless it is invalidated in one or more of the pending lawsuits, or unless it is replaced by the incoming Biden administration, which would take many months. The 2020 Rule generally regulates 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 adjacent 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 regulates 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. If the 2020 WOTUS Rule is invalidated in one or more pending lawsuits, or if it is replaced by a new, more stringent rule on the scope of WOTUS by the incoming administration, it would likely 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 USACE issued revised and renewed streamlined general nationwide permits that are available to satisfy permitting requirements for certain work in streams, wetlands and other regulated 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.
In May 2020, a federal court in Montana enjoined the use of Nationwide Permit 12 to construct new oil and gas-related pipelines, on the basis that the USACE had not properly consulted with the U.S. Fish and Wildlife Service when that permit was renewed in 2017. The U.S. Supreme Court in July 2020 significantly narrowed the Montana court’s injunction to cover only the challenged XL Pipeline. The Montana court’s substantive decision is now on appeal to the Ninth Circuit, whose ultimate ruling could affect the oil and gas industry’s ability to use this streamlined permit. In the meantime, in September 2020, the USACE issued a proposal to revise and reissue all 52 current nationwide permits, including No. 12, to lessen the burden on the energy industry and address the flaws alleged in the Montana lawsuit. Among other things, under that proposal existing Nationwide Permit 12 would be broken up into three new separate nationwide permits, with the proposed new Nationwide Permit 12 being limited solely to construction and maintenance of oil and gas pipelines, with other utility-related structures covered by the two new nationwide permits. The proposed new No. 12 would also have decreased requirements for pre-construction notification to the USACE. It is unknown at this time whether that proposed rule will be finalized by the end of the current administration or, if not, whether it will be abandoned or revised by the incoming administration. If the current or revised version of Nationwide Permit 12 is invalidated or stayed by the courts, it would increase the costs and delays for oil and gas operators to construct or maintain pipelines that cross jurisdictional waters of the U.S.
The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment, load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak.
The 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.
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.
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.
Human Capital Resources
As of December 31, 2020, we had 520 full-time employees, 235 of whom are employed in field operations.
Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. Therefore, we recognize and support the growth of our employees by offering internal and external development programs. We utilize an online training platform to allocate and track employee trainings, as well as offering on-demand developmental training content. Lastly, to remind our employees of PDC's values, we require all employees to attend an annual harassment awareness training.
We conduct an annual employee satisfaction survey where employees from each of our offices are provided an opportunity for their opinions to be voiced on how we can improve as a company. We report results back to our board of directors, management team and employees and take actions to address areas of employee concern. On a company-wide level, we encourage a culture of volunteerism and have an annual day of service which garners participation from the vast majority of our employees. Additionally, we believe diversity and inclusion provides a business with innovation and a successful workforce. We formed an employee-led diversity and inclusion project team in 2020 that will identify areas for growth and improvement that will build on our current efforts in respect of diversity and inclusion.
We are committed to the health, safety, and welfare of our employees, contractors, and neighbors. We regularly update our safety policies and procedures to ensure we are meeting or exceeding new requirements and adopting new technologies that improve our responsible operations. Additionally, all PDC field employees receive safety training upon hire, along with frequent meetings and refreshers to reinforce safety as a core value and our most important strategic priority.
PDC utilizes a field monitoring room, which is tied into our field automation, that is staffed 24 hours a day and 365 days a year to identify emergency situations and allows for quick field response. The automation capabilities on a facility can vary from measuring tank levels to security cameras to remote emergency shut-down capabilities. The field monitoring room, in combination with our daily inspections performed on producing locations, facilitates proactive response to events that need attention.
Our continual commitment to safety has resulted in improving safety records, even as operations have grown. At least since the time Occupational Safety and Health Administration ("OSHA") began requiring record-keeping and publication of health and safety information in 1972, we have not had any employee work-related fatalities. A commonly used measure of an organization’s safety performance is Total Recordable Incident Rate ("TRIR"), which equates to the number of injuries requiring medical treatment per 100 full-time employees during a one-year period. We monitor this performance measure and communicate it broadly across the company. We also include both TRIR and Preventable Vehicle Accident Rate ("PVAR") as part of our quantitative performance metrics within our annual incentive program, to prioritize the importance of safety within our company. Our TRIR and PVAR remained notably low for 2020 and 2019.
Employee Compensation and Benefits
Our compensation program is designed to provide the proper incentives to attract, retain and reward employees to achieve results related to our core values and strategic priorities. The structure of our compensation program provides incentives for both short-term and long-term performance. We also seek fairness in total compensation and benefits with reference to external benchmarking against our peers within the industry. All full-time employees are eligible for health insurance, paid and unpaid leaves, a retirement plan and life and disability/accident coverage.
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, which are maintained and available at www.sec.gov. Our SEC filings are also 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, sustainability report 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.
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 the Global COVID-19 Pandemic
Our operations have been adversely affected as a result of the ongoing global COVID-19 pandemic and its impacts on crude oil demand and pricing. We expect those impacts to continue in the near-term and we may experience additional impacts in the future. For example:
•Prolonged depressed crude oil prices may have adverse effects on the financial wellbeing of our business, including with respect to revenue, profitability, cash flows and liquidity; quantity and present value of our reserves; the borrowing base under our revolving credit facility; and access to other sources of capital;
•Negative financial impacts may lead to distress and restructuring events affecting working interest partners, vendors, contractors, service providers and other counterparties;
•Negative financial impacts to our business partners may cause delays or failure to pay service providers, which could result in liens being filed against our real and personal property;
•Reduced capital spending and declines in revenues have led to temporary and permanent reductions in our work force and decreases to our director, executive and employee compensation, which may affect our ability to attract and retain experienced technical and other professional personnel;
•Our reduced drilling program may result in losses of acreage due to lease expirations, which could result in impairment charges and the loss of future drilling opportunities;
•State and local orders, ordinances and guidance related to COVID-19 have forced a significant portion of our employees to work remotely, which may result in decreased productivity and continuity among the employee base;
•Current market conditions and impacts on our business generally may lead to an increased risk of litigation; and
•The cumulative effects of COVID-19 on the economy may result in a long-term global recession or depression.
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;
•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 pandemic; and
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. As a result of the ongoing impact of the COVID-19 pandemic and actions of members of OPEC, in 2020, oil prices ranged from highs of approximately $59 per barrel to lows of approximately negative $40 per barrel
(due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location in Cushing, Oklahoma). 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.
We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us.
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. A summary of certain laws and regulations that apply to us and some potential changes to those laws and regulations is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation. Any of the currently applicable laws and regulations could be amended, including in ways that we do not anticipate, and those changes could adversely affect our operations.
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 we acquired from SRC. The COC resolved SRC’s alleged violations related to storage tank emissions and contains requirements similar to those contained in our consent decree.
The regulatory environment in which we operate also changes frequently, often through the imposition of new or more stringent environmental and other requirements, some of which may apply retroactively. 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:
•As discussed in Items 1 and 2, Business and Properties - Governmental Regulation, the COGCC completed extensive rulemaking hearings under SB 19-181 in 2020, which resulted in the adoption of new requirements for setbacks, permitting, siting cumulative and surface impacts, asset transfers, venting and flaring, and remediation. The implementation of the final rules, particularly as they relate to mandatory setbacks between wells and building units, could have a significant adverse effect on our unpermitted locations and therefore on our future inventory and reserves. Other final rules could have a significant adverse effect on our future operations as well. The COGCC is still in the process of issuing guidance and direction regarding the new requirements, and we cannot predict the impact of these requirements on our inventory and operations.
•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. 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.
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 natural disasters, government regulations and midstream interruptions.
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. Any shortages or increased costs 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.
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 may be curtailed and our results of operations will be adversely affected. 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 and 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.
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.
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.
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. For example, in November 2020, the COGCC adopted various new requirements on the underground injection of fluid waste.
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 in the future. For example, we incurred impairment charges in a number of recent periods, including charges of $882.4 million and $38.5 million in 2020 and 2019, respectively, to write down assets. Similarly, the significant decline in commodity pricing during 2020 resulted in a reduced year-end proved reserve NYMEX price of $39.57 per barrel of crude and $1.99 per MMBtu of natural gas, a decrease of 29% and 23% respectively from 2019. The decline in pricing resulted in a downward revision of 28.2 MMBoe to reserves for year-end 2020 when compared to year-end 2019. 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 is made for each producing basin. A significant decrease in long-term forward prices could result in a significant impairment for our properties.
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.
The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. In determining the estimates of reserve and economic evaluations, management utilizes independent petroleum engineers. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. 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, 2020, approximately 56 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.3 billion during the five years ending December 31, 2025, 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 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 may vary over time and exceed our estimates depending upon reservoir characteristics and other factors. 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 and cost of drilling rigs, and equipment, supplies, chemicals, personnel and oilfield services;
•lease expirations or limitations as to depth;
•access to and availability of water sourcing and distribution systems;
•regulatory approvals; and
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 and 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. We anticipate that our remaining locations in the field will not, on average, be as productive or as economic as many of those we have drilled in recent years, due to lower anticipated overall production or higher gas-to-oil ratios. In the Delaware Basin, our inventory is subject to, among other things, potential lease expirations and our continued analysis of geologic challenges 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. 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. 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:
•pressures or irregularities in geological formations;
•floods, winter storms and other natural disasters and adverse weather conditions;
•loss of well control;
•loss of drilling fluid circulation and other facility or equipment malfunctions;
•facility or equipment malfunctions;
•unexpected operational events;
•shortages or delays in the delivery of equipment and services;
•unanticipated environmental liabilities; and
•compliance with environmental and other governmental requirements.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third-party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites.
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.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We frequently own less than all of the working interest in the oil and gas leases on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay its share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover the costs from the partner. This could materially adversely affect our financial position.
We may not be able to keep pace with technological developments in our industry.
Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced technology, our business, financial condition and results of operations could be materially adversely affected.
Competition in our industry is intense, which may adversely affect our ability to succeed.
Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect our operations and our profitability.
Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.
Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
A failure to complete successful acquisitions would limit our ability to replace our reserves and impact our financial condition.
Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. We may not be able to identify attractive acquisition opportunities, and if we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. If we are unable to complete suitable acquisitions on acceptable terms, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations.
Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties.
Acquisitions of producing and undeveloped properties, including the SRC Acquisition, have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological and geophysical reviews of the acquired properties that we believe are generally consistent with customary industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor.
When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire.
Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price and any related increase in interest expense or other related charges.
The SRC Acquisition presented a number of the foregoing risks - for example, because closing has occurred, we have no recourse if we discover unanticipated liabilities or other problems with the properties we acquired in the transaction. In addition, those risks are greater than they were in the case of most of our previous acquisitions given the larger size of the SRC Acquisition.
Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected.
We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, employment litigation, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, on January 18, 2021, a purported class action lawsuit was filed against us by a royalty owner alleging we have been improperly deducting certain post-production costs from the owner’s oil royalty payments. While we intend to vigorously defend this suit, the outcome of legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management attention and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. Information regarding legal proceedings can be found in Note 12 - Commitments and Contingencies - Litigation and Legal
Items included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report.
Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions.
We face various security threats, including attempts by third parties to gain unauthorized access to, or control of, competitive information or to render data or systems corrupted or unusable; threats to the safety of our employees; threats to the security of our infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient to prevent them from materializing.
Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to store, transmit, process and record sensitive information (including but not limited to trade secrets, employee information and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. In addition, computer systems control the oil and gas production and processing equipment that are necessary to deliver our production to market. A disruption or failure of these systems, or of the networks and infrastructure on which they rely, may cause damage to critical production, distribution and/or storage assets, delay or prevent delivery to markets, or make it difficult to accurately account for production and settle transactions. The continuing and evolving threat of cybersecurity attacks has resulted in increased regulatory focus on prevention, which could potentially elevate costs, and failure to comply with these regulations could result in penalties and potential legal liability.
As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and unintentional events, have also increased. Our systems and infrastructure are, and those of our business partners, including vendors, service providers, operating partners, purchasers of our production and financial institutions may be, subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We and our business partners also face various other cyber-security threats from criminal hackers, state-sponsored intrusion, industrial espionage and employee malfeasance, including threats to gain access to sensitive information or to render data or systems unusable.
Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Although we have not suffered material losses related to cyber-attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.
The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
Many scientists believe that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth's atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such events were to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance.
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. As a result, if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
Risks Relating to Financial Matters
Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. Lender hesitancy to offer financing to our industry may increase this risk.
Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated from operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including:
•our proved reserves;
•the amount of crude oil, natural gas and NGLs we are able to produce from existing wells;
•the prices at which crude oil, natural gas and NGLs are sold;
•the costs to produce crude oil, natural gas and NGLs; and
•our ability to acquire, locate and produce new reserves.
If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense.
Additionally, due to recent default rates in the oil and gas industry and other factors, some lenders have expressed a hesitancy to lend to oil and gas producers, and may require terms less favorable to the producers or, in some cases, may refuse to provide financing to the industry altogether. We anticipate that the number of lenders willing to participate in the lending syndicate under our revolving credit facility may decline in the future. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability.
We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt.
We have a substantial amount of indebtedness outstanding. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs.
Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving credit facility or otherwise, to fund our liquidity needs.
A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing. In addition, we might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which
could further restrict our business operations. In addition, the terms of our debt agreements could restrict us from implementing some of these alternatives.
Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions.
Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to:
•incur additional debt;
•pay dividends on, redeem or repurchase stock;
•make specified types of investments;
•apply net proceeds from certain asset sales;
•engage in transactions with our affiliates;
•engage in sale and leaseback transactions;
•merge or consolidate;
•restrict dividends or other payments from restricted subsidiaries;
•sell equity interests of restricted subsidiaries; and
•sell, assign, transfer, lease, convey or dispose of assets.
Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that subject us to additional restrictive covenants.
Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices.
We expect to depend on our revolving credit facility for part of our future capital needs. Our ability to comply with covenants and restrictions in our credit agreement in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of these restrictions and covenants could result in a default under our credit agreement, and cause all of our existing indebtedness to become immediately due and payable.
The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results.
If we are unable to comply with the restrictions and covenants in our debt agreements, the resulting default could lead to an acceleration of payment of funds that we have borrowed and we may not have or be able to obtain the funds necessary to repay those amounts.
Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness.
In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs and no waiver is obtained, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.
We may be adversely affected by the phaseout of the London Interbank Offered Rate ("LIBOR") or the replacement of LIBOR with a different reference rate.
On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it would phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is in the process of assessing replacing U.S. dollar LIBOR with a newly created index (e.g. secured overnight financing rate). Changes in the method of calculating LIBOR, or the replacement of LIBOR with an alternative rate or benchmark, may adversely affect interest rates and result in higher borrowing costs. This could materially and adversely affect our results of operations, cash flows and liquidity. It is not possible to predict the effect of these changes or the establishment of alternative reference rates in the United States or elsewhere.
Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income.
We use commodity derivatives for a portion of the production from our own wells to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity.
At December 31, 2020, we had hedged a total of 20.0 MMBbls crude oil and 120.5 MMBtu of natural gas for 2021 and 2022. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices.
Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income.
Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.
The occurrence of a significant accident or other event that is not fully covered by insurance, not properly or timely noticed to our carrier, or that is in excess of our insurance coverage, could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. In addition, pollution and environmental risks are generally not fully insurable. The cost of obtaining insurance has increased as a result of the SRC Acquisition because of the increased size of our asset base.
The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.
The market price of our common stock is highly volatile and we expect it to continue to be volatile for the foreseeable future. Adverse events including changes in production volumes, worldwide demand and prices for crude oil and natural gas, regulatory developments, and changes in securities analysts’ estimates of our financial performance could negatively impact the market price of our common stock. General market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes.
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 3. LEGAL PROCEEDINGS
Information regarding our legal proceedings can be found in Note 12 - Commitments and Contingencies - Litigation and Legal Items included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report.
ITEM 4. MINE SAFETY DISCLOSURES
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol "PDCE."
As of February 16, 2021, we had approximately 430 stockholders of record.
While we have not declared any cash dividends on our common stock, our board of directors recently approved a quarterly dividend program expected to commence mid-2021. The dividend program and payment of any future dividends thereunder will be made at the discretion of our board of directors and will depend on our results of operations, cash flows, financial position and capital requirements, as well as general business conditions, legal, tax and regulatory restrictions and other factors our board of directors deems relevant at the time it determines to declare such dividends.
Additionally, our revolving credit facility, as well as the indentures governing our 6.125% senior notes due 2024 (the "2024 Senior Notes"), 2025 Senior Notes and 2026 Senior Notes, the terms of which are summarized in Note 9 - Long-term Debt in Item 8. Financial Statements and Supplementary Data included elsewhere in this report, include restrictions based on our leverage and other certain financial metrics that could impact our ability to pay cash dividends. As we declare dividends in the future, we will monitor compliance with such restrictions.
The following table presents information about our purchases of our common stock during the year ended December 31, 2020:
Total Number of Shares Purchased (1) (3)
|Average Price Paid per Share|
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)
Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions)
|485,948 ||$||23.72 ||217,500 ||$||366.0 |
|February ||585,455 ||20.95 ||552,500 ||354.5 |
|March ||500,782 ||15.41 ||496,000 ||346.8 |
|April ||49,064 ||6.29 ||— ||346.8 |
|May ||14,134 ||11.27 ||— ||346.8 |
|June||1,021 ||16.02 ||— ||346.8 |
|July ||6,902 ||13.34 ||— ||346.8 |
|August||6,619 ||14.80 ||— ||346.8 |
|September||3,121 ||13.26 ||— ||346.8 |
|October ||68,112 ||13.28 ||— ||346.8 |
|November ||1,209 ||15.06 ||— ||346.8 |
|December||628 ||18.40 ||— ||346.8 |
|Total purchases||1,722,995 ||$||19.25 ||1,266,000 ||$||346.8 |
(1)In April 2019, the board of directors approved a program to acquire up to $200.0 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525.0 million (the "Stock Repurchase Program"). The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the board of directors at any time. We reinstated our Stock Repurchase Program in late February 2021. Repurchases may extend until December 31, 2023.
(2)In January 2020, we merged with SRC, and upon closing, issued approximately 38.9 million shares of our common stock to SRC shareholders. Of the issued shares, 244,333 shares were withheld in lieu of tax liabilities related to the issuance of the stock.
(3)Purchases outside of the Stock Repurchase Program and not in connection with the SRC Acquisition represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not considered common stock repurchased under the Stock Repurchase Program.
Stockholder Performance Graph
The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2020 with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 196 crude petroleum and natural gas companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2015, and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance.
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
Among PDC Energy, Inc., the S&P 500 Index, and a Peer Group
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below should be read in conjunction with Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data of this report.
|Year Ended/As of December 31,|
|(in millions, except per share data and as noted)|
|Statement of Operations:|
|Crude oil, natural gas and NGLs sales||$||1,152.6 ||$||1,307.3 ||$||1,390.0 ||$||913.1 ||$||497.4 |
|Commodity price risk management gain (loss), net ||180.3 ||(162.8)||145.2 ||(3.9)||(125.7)|
|Total revenues||1,339.2 ||1,156.1 ||1,548.7 ||921.6 ||382.9 |
|Net income (loss)||(724.3)||(56.7)||2.0 ||(127.5)||(245.9)|
|Earnings (loss) per share:|
|Statement of Cash Flows:|
|Net cash flows from:|
|Operating activities||$||870.1 ||$||858.2 ||$||889.3 ||$||597.8 ||$||486.3 |
|Financing activities||(181.3)||(188.9)||18.1 ||65.0 ||1,266.1 |
|Capital expenditures for development of crude oil and natural gas properties||(551.0)||(855.9)||(946.4)||(737.2)||(436.9)|
|Acquisition of crude oil and natural gas properties||(139.8)||(13.2)||(180.0)||(15.6)||(1,073.7)|
|Total assets||$||5,238.0 ||$||4,448.7 ||$||4,544.1 ||$||4,420.4 ||$||4,485.8 |
|Working capital (deficit)||(471.6)||(57.2)||(166.6)||(16.4)||129.2 |
|Total debt, net of unamortized discount and debt issuance costs||1,602.6 ||1,177.2 ||1,194.9 ||1,151.9 ||1,044.0 |
|Total stockholders' equity||2,615.5 ||2,335.5 ||2,526.7 ||2,507.6 ||2,622.8 |
|Average Pricing and Production Expenses (per Boe and as a percent of sales for production taxes):|
|Sales price (excluding net settlements on derivatives)||$||16.86 ||$||26.46 ||$||34.61 ||$||28.69 ||$||22.43 |
|Lease operating expenses||2.36 ||2.88 ||3.26 ||2.82 ||2.70 |
|Production taxes||0.87 ||1.63 ||2.25 ||1.91 ||1.42 |
|Production taxes (as a percent of sales)||5.2 ||%||6.2 ||%||6.5 ||%||6.6 ||%||6.3 ||%|
|Transportation, gathering and processing||1.14 ||0.94 ||0.93 ||1.04 ||0.83 |
|Total production||68,368 ||49,414 ||40,160 ||31,830 ||22,176 |
|Total proved reserves (MMBoe)||731.1 ||610.9 ||544.9 ||452.9 ||341.4 |
(1)In 2020, we closed the SRC Acquisition for aggregate consideration of approximately $1.2 billion.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data and also with Item 1A. Risk Factors of this report. A discussion of changes in our results of operations from 2018 to 2019 has been omitted from this report but may be found in Item 7. Management's Discussion and Analysis, of our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 27, 2020. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements in Part I of this report.
2020 Financial Overview of Operations and Liquidity
During 2020, the effects of the coronavirus 2019 (“COVID-19”) pandemic led to a significant decline in global demand for crude oil and natural gas, contributing to a drastic reduction in commodity prices and negatively impacting oil and natural gas producers located in the United States, including PDC. The commodity price environment may remain volatile for an extended period as a result of reduced global oil and natural gas demand and the global economic recession. We expect to be able to fund our operations, planned capital expenditures, working capital and other requirements during the next 12 months and for the foreseeable future. See Item 1A. Risk Factors for additional information regarding the potential impacts of the COVID-19 pandemic.
Production volumes increased 38 percent to 68.4 MMBoe in 2020 compared to 2019. The majority of the increase is attributed to producing properties acquired in the SRC Acquisition. Total liquids production of crude oil and NGLs comprised 60 percent of production in 2020. For the month ended December 31, 2020, we maintained an average production rate of approximately 178,000 Boe per day, up from approximately 139,000 Boe per day for the month ended December 31, 2019.
Crude oil, natural gas and NGLs sales revenue decreased to $1.2 billion in 2020 compared to $1.3 billion in 2019, driven by a 36 percent decrease in weighted-average realized commodity prices, partially offset by the 38 percent increase in production.
We had positive net settlements from commodity derivative contracts of $279.3 million for 2020 as compared to negative net settlements of $17.6 million for 2019.
The combined revenue from crude oil, natural gas and NGLs sales and net settlements received on our commodity derivative instruments was $1.4 billion in 2020 and $1.3 billion in 2019.
In 2020, we generated a net loss of $724.3 million or, $7.37 per diluted share, compared to net loss of $56.7 million, or $0.89 per diluted share, in 2019. Our net loss for the year ended December 31, 2020 as compared to December 31, 2019 was most significantly impacted by the increase in impairment of properties and equipment and the decrease in crude oil, natural gas and NGLs sales, partially offset by the net commodity price risk management gain.
Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $990.6 million and $882.7 million, in 2020 and 2019, respectively. Cash flows from operations were $870.1 million and $858.2 million in 2020 and 2019, respectively, and adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $921.6 million and $825.4 million, respectively. Adjusted free cash flow, a non-U.S. GAAP financial measure, was $399.3 million for 2020 as compared to $37.7 million for 2019.
See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.
In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt. Upon closing, we issued approximately 38.9 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 share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the Merger Agreement.
Available liquidity as of December 31, 2020 was $1.4 billion, which was comprised of $2.6 million of cash and cash equivalents and $1.4 billion available for borrowing under our revolving credit facility. In September 2020, we issued an additional $150.0 million principal amount of 2026 Senior Notes. The net proceeds from the offering were used to repay a portion of the amount outstanding under our revolving credit facility. In October 2020, as part of our fall 2020 semi-annual redetermination, the borrowing base of our credit facility was reduced from $1.7 billion to $1.6 billion, with a corresponding automatic reduction of our elected commitment level to $1.6 billion. Looking into 2021, based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to repay our 2021 Convertible Notes, which mature in September 2021, and to fund our planned activities through the 12-month period following the filing of this report. We exited 2020 with a debt balance of $1.6 billion.
Stock Repurchase Program
As previously noted, our board of directors has approved a Stock Repurchase Program of $525 million, of which approximately $346.8 million remains available. We suspended the program in March 2020 but recently reinstated it in light of our reduced level of indebtedness. The program may extend until December 31, 2023.
Drilling and Completion Overview
We ran three drilling rigs in the Wattenberg Field through the middle of April 2020, when we dropped to a two-rig pace. We released a second rig at the end of May 2020 and continued at a one-rig pace for the remainder of the year. We also released our only completion crew in the Wattenberg Field in early May 2020 but resumed completion activities in September 2020. In the Delaware Basin, we ran one drilling rig through early May 2020 and we released our only active completion crew in March 2020. We did not have material activity in the Delaware Basin for the remainder of 2020. Our total 2020 capital investments in crude oil and natural gas properties was $522.3 million.
The following tables summarize our drilling and completion activity for the year ended December 31, 2020:
|Operated Wells |
Delaware Basin (1)
| Gross|| Net||Gross||Net||Gross||Net|
|In-process as of December 31, 2019||145 ||134.3 ||30 ||29.1 ||175 ||163.4 |
|Wells spud ||105 ||99.3 ||3 ||2.9 ||108 ||102.2 |
Acquired in-process (2)
|88 ||84.7 ||— ||— ||88 ||84.7 |
|In-process as of December 31, 2020||214 ||201.8 ||20 ||19.0 ||234 ||220.8 |
(1)In the Delaware Basin, we had eight operated batch drilled wells that were spud in late December 2019 with final laterals being reached in early 2020.
(2)Represents in-process wells and wells being completed that we received as part of the SRC Acquisition.
Our 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. Our in-process wells are generally completed and turned-in-line within two years of drilling.
2021 Operational and Financial Outlook
We anticipate that our total production for 2021 will range between 190,000 Boe to 200,000 Boe per day, approximately 64,000 Bbls to 68,000 Bbls of which are expected to be crude oil. Our planned 2021 capital investments in crude
oil and natural gas properties, which we expect to be between $500 million and $600 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin.
We believe that we maintain a degree of operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate strategy. We may revise our 2021 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities.
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie, Plains, and Summit development areas. Our 2021 capital investment program for the Wattenberg Field is approximately 75 percent of our expected total capital investments in crude oil and natural gas properties, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. In 2021, we plan to drill standard-reach lateral ("SRL"), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells in the Wattenberg Field. In 2021, we anticipate spudding approximately 75 to 85 operated wells and turning-in-line approximately 150 to 175 operated wells. As of December 31, 2020, we have approximately 214 gross operated DUCs and 300 approved permitted locations. In 2021,we expect to operate with one full-time horizontal rig and completion crew along with a part-time spudder rig. Our program is expected to have an average development cost per well between $2.5 million and $3.6 million, depending upon the lateral length of the well. The remainder of the Wattenberg Field capital investment program is expected to be used for land, capital workovers, facilities projects and non-operated drilling.
Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2021 are expected to be approximately 25 percent of our total capital investments, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. In 2021, we anticipate spudding and turning-in-line approximately 15 to 20 operated wells. The majority of the wells we plan to drill in 2021 in the Delaware Basin are MRL and XRL wells. We expect to drill at a one-rig pace in 2021 along with a completion crew for four months starting towards the end of the first quarter, with an average development costs per well between $6.7 million and $8.0 million for MRL and XRL wells, depending upon the lateral length of the well.
We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2021 and assumed average NYMEX prices of $45.00 per Bbl of crude oil and $2.50 per Mcf of natural gas and an assumed average composite price of $12.00 per Bbl for NGLs, we expect 2021 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Any excess cash flows from operations will be used towards reducing our indebtedness as well as returning capital to our shareholders.
Colorado Political Update
Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have historically advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Senate Bill 19-181 ("SB19-181") was enacted by the Colorado legislature in 2019 to address concerns underlying the ballot initiatives. The COGCC conducted a series of rulemaking hearings pursuant to SB 19-181 during 2020 which resulted in updated regulatory and permitting requirements, including setbacks and siting requirements. The COGCC commissioners determined that locations with residential or high occupancy building units, schools or child care facilities within 2,000 feet would be subject to additional siting requirements, but also supported “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from residential or high occupancy building units (excluding schools and child care facilities) in certain circumstances. The 2020 rulemaking hearings also resulted in the adoption of a number of other new regulatory requirements, including requirements regarding permitting, cumulative and surface impacts, asset transfers, venting and flaring, and remediation. However, third-party proposals which were presented to the COGCC prohibit or dramatically restrict oil and gas development were not adopted by the Commissioners. Governor Polis has publicly stated his opposition to further ballot initiatives in 2022 while rulemaking under SB 19-181 is in process and has acknowledged the importance of regulatory certainty.
It is nevertheless possible that future ballot initiatives will be proposed that would dramatically limit the areas of the state in which drilling would be permitted to occur. See Part I, Item1A. Risk Factors- 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.
Results of Operations
Summary of Operating Results
The following table presents selected information regarding our operating results:
|Year Ended December 31,|
|(dollars in millions, except per unit data)|
|Crude oil (MBbls)||23,720 ||19,166 ||16,963 ||24 ||%||13 ||%|
|Natural gas (MMcf)||165,637 ||115,950 ||88,017 ||43 ||%||32 ||%|
|NGLs (MBbls)||17,042 ||10,923 ||8,527 ||56 ||%||28 ||%|
|Crude oil equivalent (MBoe)||68,368 ||49,414 ||40,160 ||38 ||%||23 ||%|
|Average Boe per day (Boe)||186,798 ||135,381 ||110,027 ||38 ||%||23 ||%|
|Crude Oil, Natural Gas and NGLs Sales:|
|Crude oil||$||816.8 ||$||1,020.7 ||$||1,038.0 ||(20)||%||(2)||%|
|Natural gas||178.8 ||151.0 ||163.2 ||18 ||%||(7)||%|
|NGLs||157.0 ||135.6 ||188.8 ||16 ||%||(28)||%|
|Total crude oil, natural gas and NGLs sales||$||1,152.6 ||$||1,307.3 ||$||1,390.0 ||(12)||%||(6)||%|
|Net Settlements on Commodity Derivatives: |
|Crude oil||294.4 ||(18.3)||(124.4)||*||(85)||%|
|Natural gas||(15.1)||0.7 ||13.9 ||*||(95)||%|
|NGLs ||— ||— ||(5.0)||*||*|
|Total net settlements on derivatives||279.3 ||(17.6)||(115.5)||*||(85)||%|
|Average Sales Price (excluding net settlements on derivatives):|
|Crude oil (per Bbl)||$||34.44 ||$||53.26 ||$||61.19 ||(35)||%||(13)||%|
|Natural gas (per Mcf)||1.08 ||1.30 ||1.85 ||(17)||%||(30)||%|
|NGLs (per Bbl)||9.21 ||12.41 ||22.14 ||(26)||%||(44)||%|
|Crude oil equivalent (per Boe)||16.86 ||26.46 ||34.61 ||(36)||%||(24)||%|
|Average Costs and Expenses (per Boe):|
| Lease operating expenses||$||2.36 ||$||2.88 ||$||3.26 ||(18)||%||(12)||%|
| Production taxes||0.87 ||1.63 ||2.25 ||(47)||%||(28)||%|
| Transportation, gathering and processing expenses||1.14 ||0.94 ||0.93 ||21 ||%||1 ||%|
| General and administrative expense||2.36 ||3.27 ||4.25 ||(28)||%||(23)||%|
| Depreciation, depletion and amortization||9.06 ||13.04 ||13.94 ||(31)||%||(6)||%|
|Lease Operating Expenses by Operating Region (per Boe):|
|Wattenberg Field||$||2.15 ||$||2.50 ||$||2.99 ||(14)||%||(16)||%|
|Delaware Basin||3.48 ||4.15 ||4.14 ||(16)||%||— ||%|
Utica Shale (1)
|— ||— ||3.46 ||*||*|
* Percent change is not meaningful.
(1)In March 2018, we completed the disposition of our Utica Shale properties.
Crude Oil, Natural Gas and NGLs Sales
Crude oil, natural gas and NGLs sales revenue for the year ended December 31, 2020 decreased compared to the year ended December 31, 2019 due to the following:
|Year Ended December 31,|
|Production ||$||383.2 ||$||239.6 |
|Average crude oil price||(446.4)||(152.0)|
|Average natural gas price||(37.0)||(64.0)|
|Average NGLs price||(54.5)||(106.3)|
|Total change in crude oil, natural gas and NGLs sales revenue||$||(154.7)||$||(82.7)|
Crude Oil, Natural Gas and NGLs Production
The following table presents crude oil, natural gas and NGLs production.
|Year Ended December 31,|
|Production by Operating Region||2020||2019||2018||2020-2019||2019-2018|
|Crude oil (MBbls)|
|Wattenberg Field||19,552 ||14,489 ||12,809 ||35 ||%||13 ||%|
|Delaware Basin||4,168 ||4,677 ||4,108 ||(11)||%||14 ||%|
Utica Shale (1)
|— ||— ||46 ||*||*|
|Total||23,720 ||19,166 ||16,963 ||24 ||%||13 ||%|
| Natural gas (MMcf)|
|Wattenberg Field||140,845 ||91,785 ||68,326 ||53 ||%||34 ||%|
|Delaware Basin||24,792 ||24,165 ||19,277 ||3 ||%||25 ||%|
Utica Shale (1)