UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20192020
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to _________
Commission File Number 001-37419
PDC ENERGY, INC.
(Exact name of registrant as specified in its charter)
| Delaware | 95-2636730 | ||||
| (State of incorporation) | (I.R.S. Employer Identification No.) | ||||
1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (303) 860-5800
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | 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 | ☐ | ||||||||
| 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, 20192020 was $2.3$1.2 billion (based on the closing price of $36.06$12.44 per share as of the last business day of the fiscal quarter ending June 30, 2019)2020).
As of February 18, 2020,16, 2021, there were 100,121,53999,781,332 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 20202021 Annual Meeting of Stockholders.
PDC ENERGY, INC.
TABLE OF CONTENTS
| PART I | Page | ||||||||||
| PART II | |||||||||||
| PART III | |||||||||||
| PART IV | |||||||||||
PART I
REFERENCES TO THE REGISTRANT
Unless the context otherwise requires, references in this report to "PDC," the "Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and our wholly-owned subsidiaries consolidated for the purposes of our financial statements. PDC Energy, Inc. is a Delaware corporation, having reincorporated from Nevada in 2015.
GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS
Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This reportAnnual 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; our stock repurchase program, which may be modified or discontinued at any time; potential additional payments from the sale of our midstream assets; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; timing and adequacy of infrastructure projects of our midstream providers and the related impact on our midstream capacity and related curtailments; fractionation capacity; impacts of Colorado political matters and expected timing of rulemakings; ability to meet our volume commitments to midstream providers; abilityproviders and timing and adequacy of midstream infrastructure; the potential return of capital to obtain permits from the Colorado Oil and Gas Conservation Commission ("COGCC") inshareholders through buyback of shares and/or issuance of a timely manner;dividend; ongoing compliance with our consent decreedecree; risk of our counterparties non-performance on derivative instruments; and expected timing of certain litigation;our ability to repay our 1.125% convertible notes due 2021 (the "2021 Convertible Notes") and reclassification of the Denver Metro/North Front Range NAA ozone classification to serious.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 theour 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 periodsperiod of depressed prices;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;
1
•impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related toof 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, and natural gas and NGLs properties resulting in impairments;
•changes in estimates of proved reserves;
•inaccuracy of estimated reservesreserve 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 including the merger with SRC Energy, Inc. ("SRC"), or acreage exchanges;
•increases or changes in costs and expenses;
•limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells;
•potential losses of acreage due to lease expirations or otherwise;
•future cash flows, liquidity and financial condition;
•competition within the oil and gas industry;
•availability and cost of capital;
•effect of crude oil and natural gas and NGLs derivativesderivative 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;
•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 cash flows.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.
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ITEMS 1. AND 2. BUSINESS AND PROPERTIES
The Company
We are a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in westTexas. 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, 2019:2020:
3
The following table presents selected information regarding our results of operations for the periods presented:
| Year Ended/As of | Year Ended/As of | ||||||||||||||||||||||||||||||||||||||||||
| December 31, | Percent Change | December 31, | Percent Change | ||||||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2019-2018 | 2020 | 2019 | 2020-2019 | ||||||||||||||||||||||||||||||||||||||
| (production and reserves in MMBoe, dollars in millions) | (production and reserves in MMBoe, dollars in millions) | ||||||||||||||||||||||||||||||||||||||||||
| Wells: | Wells: | ||||||||||||||||||||||||||||||||||||||||||
| Gross productive wells | 2,649 | 2,876 | (7.9 | )% | Gross productive wells | 3,727 | 2,649 | 41 | % | ||||||||||||||||||||||||||||||||||
| Net productive wells | 2,101 | 2,284 | (8.0 | )% | Net productive wells | 2,841 | 2,101 | 35 | % | ||||||||||||||||||||||||||||||||||
| Horizontal percentage | 48 | % | 39 | % | 23 | % | Horizontal percentage | 57 | % | 48 | % | 19 | % | ||||||||||||||||||||||||||||||
| Gross operated wells turned-in-line | 135 | 165 | (18.2 | )% | Gross operated wells turned-in-line | 137 | 135 | 1 | % | ||||||||||||||||||||||||||||||||||
| Net operated wells turned-in-line | 125 | 151 | (17.2 | )% | Net operated wells turned-in-line | 129.5 | 125.0 | 4 | % | ||||||||||||||||||||||||||||||||||
| Production: | Production: | ||||||||||||||||||||||||||||||||||||||||||
| Wattenberg Field | 38.0 | 30.7 | 23.9 | % | Wattenberg Field | 57.5 | 38.0 | 51 | % | ||||||||||||||||||||||||||||||||||
| Delaware Basin | 11.4 | 9.4 | 22.1 | % | Delaware Basin | 10.8 | 11.4 | (5) | % | ||||||||||||||||||||||||||||||||||
| Utica Shale (1) | — | 0.1 | * | ||||||||||||||||||||||||||||||||||||||||
| Total | 49.4 | 40.2 | 23.0 | % | Total | 68.4 | 49.4 | 38 | % | ||||||||||||||||||||||||||||||||||
| Reserves: | Reserves: | ||||||||||||||||||||||||||||||||||||||||||
| Proved reserves | 610.9 | 544.9 | 12.1 | % | Proved reserves | 731.1 | 610.9 | 20 | % | ||||||||||||||||||||||||||||||||||
| Proved developed reserves percentage | 35 | % | 33 | % | 6 | % | Proved developed reserves percentage | 44 | % | 35 | % | 26 | % | ||||||||||||||||||||||||||||||
| Standardized measure | $ | 3,310 | $ | 4,448 | (25.6 | )% | Standardized measure | $ | 3,282.2 | $ | 3,310.3 | (1) | % | ||||||||||||||||||||||||||||||
| PV-10 (2) | $ | 3,837 | $ | 5,321 | (27.9 | )% | |||||||||||||||||||||||||||||||||||||
PV-10 (1) | PV-10 (1) | $ | 3,454.6 | $ | 3,837.0 | (10) | % | ||||||||||||||||||||||||||||||||||||
| Liquidity | $ | 1,291.0 | $ | 1,268.9 | 1.7 | % | Liquidity | $ | 1,400 | $ | 1,291 | 8 | % | ||||||||||||||||||||||||||||||
| Leverage ratio | 1.4 | 1.4 | — | % | Leverage ratio | 1.7 | 1.4 | 21 | % | ||||||||||||||||||||||||||||||||||
_____________
(1) (1) In March 2018, we completed the disposition of our Utica Shale properties.
reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in
accordance with U.S. GAAP,generally accepted accounting principles (“U.S. GAAP”), but rather should be considered in addition to the standardized measure. See Part II,
Item 7,7. 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.
Significant 2020 Events
SRC Acquisition
In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt (the “SRC Acquisition”). WeUpon closing, we issued approximately 3938.9 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.
| Year Ended/As of December 31, 2019 | |||||||||
| PDC | SRC | Combined | |||||||
| (production in MBoe, reserves in MMBoe and dollars in millions) | |||||||||
| Wells: | |||||||||
| Gross productive wells | 2,649 | 1,529 | 4,178 | ||||||
| Net productive wells | 2,101 | 958 | 3,059 | ||||||
| Production: | |||||||||
| Crude oil (MBbls) | 19,166 | 9,813 | 28,979 | ||||||
| Natural gas (MMcf) | 115,950 | 49,471 | 165,421 | ||||||
| NGLs (MBbls) | 10,923 | 4,526 | 15,449 | ||||||
| Crude oil equivalent (MBoe) | 49,414 | 22,584 | 71,998 | ||||||
| Average Boe per day (Boe) | 135,381 | 61,874 | 197,255 | ||||||
| Crude oil production percentage | 38.8 | % | 43.5 | % | 40.2 | % | |||
| Reserves: | |||||||||
| Proved reserves (1) | 610.9 | 295.0 | 905.9 | ||||||
| Proved developed reserves percentage | 35 | % | 42 | % | 37 | % | |||
| Crude oil and condensate percentage | 32 | % | 27 | % | 31 | % | |||
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Senior Notes Offering
In September 2020, we expect 2020 adjusted cash flowsissued 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 operations,the offering were used to repay a non-U.S. GAAP financial measure, to exceedportion of the amount outstanding under our capital investments in crude oil and natural gas properties by approximately $250 million. Assuming consistent realization percentages, we estimate that for every:revolving credit facility.
Our long termlong-term business strategy focuses on creating shareholder value byby: (i) delivering attractive returns from responsible development of our crude oil and natural gas properties,properties; (ii) maintaining financial strength,strength; (iii) generating sustainable cash flows from operations in excess of our capital investments in crude oil and natural gas propertiesproperties; and (iv) returning capital to shareholders. We seek toOur 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 5 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. |
Operating Areas
Wattenberg Field. In the Wattenberg Field, we have identified a gross operated inventory of approximately 1,6002,000 horizontal drilling locations (including locations received as part of the SRC Acquisition) that we expect to generate acceptable rates of return based on forward strip pricing, with an average lateral length of approximately 8,3009,000 feet. In addition to these drilling locations, we entered 2020 withOur inventory consists of approximately 230200 gross operated DUCs, including 88 gross operated DUCs received as part300 approved permits, reflecting approximately 3.5 years of the SRC Acquisition.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 190115 horizontal drilling locations and20gross operated DUCs that we expect to generate acceptable rates of return based on forward strip pricing, primarily targeting the Wolfcamp A and Wolfcamp B zones, within the oilier eastern and north central portions of our acreage. 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 8,600 feet, compared to an average lateral length of approximately 7,900 feet as of year-end 2018. Some of these locations are within untested target zones that may be subject to a higher degree of uncertainty or may depend upon additional delineation and testing. Our gross operated inventory8,900 feet.Wells in the Delaware Basin decreased from year-end 2018, primarily duetypically have productive horizons at depths of approximately 9,000 to 11,500feet below the removal of several standard-reach lateral, higher gas-to-oil ratio locations that were negatively impacted by decreased NYMEX natural gas pricing and higher Waha natural gas differentials.surface. We continue to pursue
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various business development initiatives, with a focus on acreage swapsexchanges and joint development projects, designed to increase our Delaware Basin project inventory by establishing longer lateral drilling units capable of delivering attractive economic returns. In addition to these drilling locations, we entered 2020 with approximately 27 gross operated DUCs. Wells in the Delaware Basin typically have productive horizons at depths of approximately 8,000 to 11,500 feet below the surface.
| Productive Wells | ||||||||||||||||||
| As of December 31, 2019 | ||||||||||||||||||
| Crude Oil | Natural Gas | Total | ||||||||||||||||
| Operating Region/Area | Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Wattenberg Field (1) | 1,163 | 809.7 | 1,385 | 1,212.8 | 2,548 | 2,022.5 | ||||||||||||
| Delaware Basin | 48 | 27.6 | 53 | 50.7 | 101 | 78.3 | ||||||||||||
| Total productive wells | 1,211 | 837.3 | 1,438 | 1,263.5 | 2,649 | 2,100.8 | ||||||||||||
Proved Oil and Gas Reserves
The following table presents our proved reserve estimates as of December 31, 2020, 2019 based on reserve reports prepared byand 2018:
| December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Proved reserves | |||||||||||||||||
Crude oil and condensate (MMBbls) | 212 | 197 | 190 | ||||||||||||||
Natural gas (Bcf) | 1,901 | 1,558 | 1,336 | ||||||||||||||
NGLs (MMBbls) | 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 independent petroleum engineering consulting firms, Ryder Scottestimated 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 NSAIAnalysis of Financial Condition and related information: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.
| Proved Reserves at December 31, 2019 | ||||||||||||||||||
| Proved Reserves (MMBoe) | % of Total Proved Reserves | % Proved Developed | % Liquids | Proved Reserves to Production Ratio (in years)(2) | 2019 Production (MBoe) | |||||||||||||
| Wattenberg Field | 492.1 | (1 | ) | 81 | % | 33 | % | 55 | % | 13.0 | 37,984 | |||||||
| Delaware Basin | 118.8 | 19 | % | 44 | % | 69 | % | 10.4 | 11,430 | |||||||||
| Total | 610.9 | 100 | % | 35 | % | 57 | % | 12.4 | 49,414 | |||||||||
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 | |||||||||||||||||||||||||||
| Proved developed | ||||||||||||||||||||||||||||||||
| 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 | % | ||||||||||||||||||||||||||
| Proved undeveloped | ||||||||||||||||||||||||||||||||
| 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 | % | ||||||||||||||||||||||||||
7
Estimates of economically recoverable oil and natural gas and NGLs salesof 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 the related effect on the economic productive lifefuture production rates and costs. Positive impacts of producing properties. Increases in commodity pricesthese 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 decreases in commodity pricesnegative impacts of these variables and assumptions may result in corresponding negative impacts. All of our proved reserves are located in the U.S.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 | ||||||||||||||||||||
| December 31, | 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 (per Bbl) | Natural Gas (per MMBtu) | 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 (in Millions) | 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
8
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. Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. Inputs and major assumptions related to
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 or NSAI. Ourand NSAI performed an independent evaluation of our estimated proved reserves in the Wattenberg Field and Delaware Basin, respectively, as of December 31, 2019 were estimated by Ryder Scott and our proved reserves in the Delaware Basin as of that date were estimated by NSAI.2020.
When preparing our reserve estimates, neither Ryder Scott nor NSAIour external engineers do not independently verifiesverify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties or sales of production. Ryder Scott and NSAIOur 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 Ryder Scott and NSAIour external engineers and reviewed by our engineering staff and management prior to issuance by those firms.
Qualifications of our reserve estimates as of December 31, 2019 have been filed as Exhibits 99.1 and 99.2 to this report.
Production, Prices and Costs
Production and operating data for the preceding 12 months. The NYMEX prices usedyears ended December 31, 2020, 2019 and 2018 was included in preparing the reserves are then adjusted based on energy content, locationItem 7. Management's Discussion and basis differentialsAnalysis of Financial Condition and other marketing deductions to arrive at the net realized price.
Results of OperationsThe indicated index prices for our reserves, by commodity, are presented below.
| Average Benchmark Prices (1) | ||||||||||||
| As of December 31, | Crude Oil (per Bbl) (2) | Natural Gas (per Mcf) (2) | NGLs (per Bbl) (3) | |||||||||
| 2019 | $ | 55.69 | $ | 2.58 | $ | 55.69 | ||||||
| 2018 | 65.56 | 3.10 | 65.56 | |||||||||
| 2017 | 51.34 | 2.98 | 51.34 | |||||||||
| Price Used to Estimate Reserves (4) | ||||||||||||
| As of December 31, | Crude Oil (per Bbl) | Natural Gas (per Mcf) | NGLs (per Bbl) | |||||||||
| 2019 | $ | 52.63 | $ | 1.50 | $ | 12.21 | ||||||
| 2018 | 61.14 | 2.15 | 23.04 | |||||||||
| 2017 | 48.68 | 2.31 | 20.21 | |||||||||
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| As of December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| Proved reserves | |||||||||||
Crude oil and condensate (MMBbls) | 197 | 190 | 155 | ||||||||
Natural gas (Bcf) | 1,558 | 1,336 | 1,154 | ||||||||
NGLs (MMBbls) | 154 | 132 | 106 | ||||||||
Total proved reserves (MMBoe) | 611 | 545 | 453 | ||||||||
Proved developed reserves (MMBoe) | 214 | 180 | 143 | ||||||||
Estimated undiscounted future net cash flows (in millions) (1) | $ | 5,896 | $ | 7,735 | $ | 5,453 | |||||
Standardized measure (in millions) | $ | 3,310 | $ | 4,448 | $ | 2,880 | |||||
PV-10 (in millions) (2) | $ | 3,837 | $ | 5,321 | $ | 3,212 | |||||
The following table presents our estimated proved developed and undeveloped reservesproductive wells by category and area:
| As of December 31, 2019 | |||||||||||||||
| Operating Region/Area | Crude Oil and Condensate (MMBbls) | Natural Gas (Bcf) | NGLs (MMBbls) | Crude Oil Equivalent (MMBoe) | Percent | ||||||||||
| Proved developed | |||||||||||||||
| Wattenberg Field | 47.1 | 443.4 | 40.7 | 161.7 | 26 | % | |||||||||
| Delaware Basin | 19.1 | 110.8 | 14.7 | 52.3 | 9 | % | |||||||||
| Total proved developed | 66.2 | 554.2 | 55.4 | 214.0 | 35 | % | |||||||||
| Proved undeveloped | |||||||||||||||
| Wattenberg Field | 94.6 | 891.7 | 87.2 | 330.4 | 54 | % | |||||||||
| Delaware Basin | 36.4 | 111.9 | 11.4 | 66.5 | 11 | % | |||||||||
| Total proved undeveloped | 131.0 | 1,003.6 | 98.6 | 396.9 | 65 | % | |||||||||
| Total proved reserves | |||||||||||||||
| Wattenberg Field | 141.7 | 1,335.1 | 127.9 | 492.1 | 81 | % | |||||||||
| Delaware Basin | 55.5 | 222.7 | 26.1 | 118.8 | 19 | % | |||||||||
| Total proved reserves | 197.2 | 1,557.8 | 154.0 | 610.9 | 100 | % | |||||||||
| 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 | ||||||||||||||||||||||||||||||||
| Pricing Scenario - NYMEX | ||||||||||||||||||
| Crude Oil (per Bbl) | Natural Gas (per MMBtu) | Proved Reserves (MMBoe) | % Change from December 31, 2019 Estimated Reserves | PV-10 (in Millions) | PV-10 % Change from December 31, 2019 Estimated Reserves | |||||||||||||
| 2019 SEC Reserve Report (1) | $ | 55.69 | $ | 2.58 | 610.9 | — | $ | 3,837.0 | — | |||||||||
| Alternate Price Scenario | $ | 50.00 | $ | 2.58 | 604.6 | (1 | )% | $ | 3,201.8 | (17 | )% | |||||||
Developed and Undeveloped Acreage
The following table presents our developed and undeveloped lease acreage:
| As of December 31, 2019 | ||||||||||||||||||
| Developed | Undeveloped | Total | ||||||||||||||||
| Operating Region/Area | Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Wattenberg Field (1) (2) | 101,400 | 95,900 | 42,900 | 40,600 | 144,300 | 136,500 | ||||||||||||
| Delaware Basin | 28,100 | 25,500 | 2,400 | 300 | 30,500 | 25,800 | ||||||||||||
| Total acreage | 129,500 | 121,400 | 45,300 | 40,900 | 174,800 | 162,300 | ||||||||||||
| Developed | Undeveloped | Total | ||||||||||||||||||||||||||||||||||||
| 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 isand Delaware Basin are related to leaseholds that are held by production. Our Wattenberg Field leaseholds at risk to expire in 2020, 2021, 2022 and 20222023 are not material. In the Delaware Basin, there arethe majority of the drilling obligations or continuous drilling clauses associated with the majority of our acreage. We believe that our current Delaware Basin drilling plan should provide sufficient development to meet these obligations in our core areas over the next few years. In the event that we do not meet the obligations for certain leases, we plan to make any necessary bonus extension payments, changes to our drilling schedule or seek to renew or re-lease the relevant properties. However, we may not be successful in such efforts and may in some cases elect to allow the lease to expire.asset have been met. Our Delaware Basin leaseholds at risk to expire in 2020, 2021, 2022 and 20222023 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.
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Drilling Results
The following tables set forth a summary of our developmental and exploratory well drilling activityresults 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 totwo years.
| Gross Development Well Drilling Activity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating Region/Area | Productive (1) | In-Process (1) | Non-Productive | Productive | In-Process | Non-Productive | Productive | In-Process | Non-Productive | |||||||||||||||||||||||||||||||||||||||||||||||
| 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 year.portion were completed during the period.
| Gross Development Well Drilling Activity | |||||||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||
| Operating Region/Area | Productive (1) | In-Process (1) | Non-Productive | Productive | In-Process | Non-Productive (2) | Productive | In-Process | Non-Productive (2) | ||||||||||||||||||
| Wattenberg Field, operated wells | 114 | 145 | — | 139 | 133 | — | 130 | 87 | — | ||||||||||||||||||
| Wattenberg Field, non-operated wells | 12 | 41 | — | 20 | 5 | — | 12 | 14 | 1 | ||||||||||||||||||
| Delaware Basin, operated wells | 21 | 26 | — | 26 | 22 | 1 | 9 | 10 | — | ||||||||||||||||||
| Delaware Basin, non-operated wells | 9 | — | — | 11 | — | — | 2 | 8 | — | ||||||||||||||||||
| Total gross development wells | 156 | 212 | — | 196 | 160 | 1 | 153 | 119 | 1 | ||||||||||||||||||
_____________ (1)Amounts 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.
There were no exploratory drilling activities in the Wattenberg Field during 2020, 2019 and 2018. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
11
| Net Development Well Drilling Activity | |||||||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||
| Operating Region/Area | Productive (1) | In-Process (1) | Non-Productive | Productive | In-Process | Non-Productive (2) | Productive | In-Process | Non-Productive (2) | ||||||||||||||||||
| Wattenberg Field, operated wells | 105.1 | 135.0 | — | 126.8 | 122.4 | — | 112.8 | 80.1 | — | ||||||||||||||||||
| Wattenberg Field, non-operated wells | 1.1 | 3.7 | — | 2.5 | 0.9 | — | 1.6 | 2.6 | 0.1 | ||||||||||||||||||
| Delaware Basin, operated wells | 20.1 | 25.3 | — | 24.5 | 16.3 | 1.0 | 10.1 | 9.4 | — | ||||||||||||||||||
| Delaware Basin, non-operated wells | 1.3 | — | — | 1.2 | — | — | 0.4 | 1.0 | — | ||||||||||||||||||
| Total net development wells | 127.6 | 164.0 | — | 155.0 | 139.6 | 1.0 | 124.9 | 93.1 | 0.1 | ||||||||||||||||||
| Gross Exploratory Well Drilling Activity | |||||||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||
| Operating Region/Area | Productive | In-Process | Non-Productive | Productive | In-Process | Non-Productive | Productive | In-Process | Non-Productive | ||||||||||||||||||
| Wattenberg Field, operated wells | — | — | — | — | — | — | — | — | — | ||||||||||||||||||
| Wattenberg Field, non-operated wells | — | — | — | — | — | — | — | — | — | ||||||||||||||||||
| Delaware Basin | 2 | 4 | — | 3 | 2 | — | 5 | 3 | 2 | ||||||||||||||||||
| Total gross development wells | 2 | 4 | — | 3 | 2 | — | 5 | 3 | 2 | ||||||||||||||||||
| Net Exploratory Well Drilling Activity | |||||||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||
| Operating Region/Area | Productive | In-Process | Non-Productive | Productive | In-Process | Non-Productive | Productive | In-Process | Non-Productive | ||||||||||||||||||
| Wattenberg Field, operated wells | — | — | — | — | — | — | — | — | — | ||||||||||||||||||
| Wattenberg Field, non-operated wells | — | — | — | — | — | — | — | — | — | ||||||||||||||||||
| Delaware Basin | 2.0 | 3.9 | — | 2.8 | 2.0 | — | 3.1 | 2.8 | 2.0 | ||||||||||||||||||
| Total gross development wells | 2.0 | 3.9 | — | 2.8 | 2.0 | — | 3.1 | 2.8 | 2.0 | ||||||||||||||||||
Title to Properties
We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties, in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties.
The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties.
Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for amounts borrowed under our revolving credit facility.
Offices
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.
Significant Customers
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.
Delivery Commitments
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.
Governmental Regulation
The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us.
Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are subject to a variety of rules and regulations concerning drilling permits, location, spacing and density of wells, water discharge and disposal, prevention of waste, bonding requirements, surface use and restoration, public health and environmental protection and well plugging and abandonment. The primary state-level regulatory authority regarding these matters in Colorado is the COGCCColorado Oil and the primary authorityGas Conservation Commission ("COGCC") and in Texas is the Texas Railroad Commission.
12
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. Natural gas pipeline companies hold certificates of public convenience and necessity issued by FERC authorizing ownership and operation of certain pipelines, facilities and properties.
In addition, to regulation of natural gas pipeline interstate transmission and storage activities, under the Energy Policy Act of 2005 (the “EPAct 2005”"EPAct 2005") it is unlawful forprohibits “any entity” to usefrom 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”("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"PIPES Act 2006”2006"), and
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the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “PIPES"PIPES Act 2011”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”"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”"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.
Environmental Matters
Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes. We also operate under a number of environmental permits and authorizations. The issuing agencies may take the position that some or all of these permits and authorizations are subject to modification, suspension, or revocation under certain circumstances, but any such action would have to comply with applicable procedures and requirements.
Hazardous Substances and Wastes
We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements. In December 2016,April 2019, the U.S. District Court for the District of Columbia approvedEPA, pursuant to a consent decree between the EPA and a coalition of environmental groups. The consent decree requires the EPA togroups and a related review and determine whether it will revise theof RCRA regulations, for exploration and production waste to treat such waste as hazardous waste. In April 2019, the EPA, pursuant to the consent decree, determined that revision of the regulations is not necessary. Information comprising the EPA’s review and decision is contained in a document entitled Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels.
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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”("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
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.
Local Regulation
Various local and municipal bodies in each of the states in which we operate have sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities. In Colorado, 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.
State Regulation
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.
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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.
Federal Regulation
Beginning in 2012, the EPA implemented Clean Air Act (“CAA”("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”"BLM"), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017; however, the2017. The BLM’s rescission of the rule has beenwas challenged in the United States District Court for the Northern District of California.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.
Private Lawsuits
Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities.
Greenhouse Gases
The EPA has published findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”("GHGs") present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources.
In the past, Congress has considered proposed legislation to reduce emissions of GHGs. To date, Congress has not adopted any such significant legislation, but could do so in the future. In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. In FebruarySince 2014, November 2017 and December 2019, Colorado has engaged in multiple rulemakings to adopt significant additional adopted rules regulating methane emissions from the oil and gas sector.sector, and Colorado is expected to continue these efforts over the next several years.
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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 intentionsintention to withdraw from the Paris Agreement. The notification beginsbegan a one-year process for withdrawal on November 4, 2020. On January 20, 2021, President Joe Biden executed an executive order to completere-enter the withdrawal.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.
Air Quality
Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be required to make certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding the Clean Air Act Section 114 Information Request that we received from the EPA.
In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. In September 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. In September 2019,2020, the EPA proposed certain policy amendments toissued a new rule which amended the 2016 rules that would removerequirements. In this rule, the EPA removed all sources in the transmission and storage segment of the oil and natural gas industry from regulation. The proposed amendments wouldrule also rescindrescinded the methane requirements in the 2016 rules that apply to sourcesregulations and loosened monitoring and repair regulations aimed at preventing methane leaks. The new rule was challenged in the production and processing segmentsU.S. Court of Appeals for the D.C. Circuit, but in October 2020 the Court declined to issue a permanent stay of the industry.new rule while it considered the merits of the challenge. The EPAnew rule therefore is also proposing,currently in effect. However, the alternative, to rescindfuture of the methane requirementsnew rule is in flux as the Court could vacate the rule such that apply to all sources in the oil and natural gas industry, without removing any sources from the current source category.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.leases (the “2016 Rule”). The rules require2016 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 revisesrevised the 2016 rules.Rule (the “2018 Revised Rule”). The new rule,2018 Revised Rule, among other things, rescindsrescinded the 2016 ruleRule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The new rule2018 Revised Rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.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 2016,2019, 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 “marginal”"moderate" to “moderate”“serious” under the 2008 national ambient air quality standard (“NAAQS”("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 November 2017December 2020 that are applicable to our operations. In 2019, the EPA increased the state of Colorado’s non-attainment ozone classification forBased on current air quality monitoring data, it is expected that the Denver Metro/North Front Range NAA area from “moderate”will be further "bumped-up" to “serious” under the 2008 NAAQS."severe" status in 2021 or 2022. This “serious” classification will trigger significant additional obligations for the state under the CAA and couldwill 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.
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SB 19-181 also requires, among other things, that the Air Quality Control Commission (“AQCC”("AQCC") adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle. The AQCC anticipates holding several rulemakings over the next several yearshas 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. InBetween December 2019 and December 2020, the AQCC held the first ofcompleted several rulemakings that are anticipated as a result of SB 19-181. As part of that rulemaking, the AQCC adopted19-181, adopting significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements, and increased LDAR frequencies for facilities in certain proximity to occupied areas.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 October 2019,2020, the CDPHE published COGCC relied in part on a previously-performed human health risk assessment for 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 Colorado, which usedrecent years. For example, EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and gas emission dataproduction facilities and transmission infrastructure. In addition, the Texas Railroad Commission has increased oversight related to modelflaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible human exposure and found a possibility of negative health impacts at distances up to 2,000 feet away under worst case conditions. In response,rulemaking in the COGCC announced that it will more rigorously scrutinize permit applications for wells within 2,000 feet of a building unit, work with CDPHE to obtain better site-specific data on oil and gas emissions, and consider the resulting data for possible future rulemaking.
Water Quality
The federal Clean Water Act (“CWA”("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. In June 2015, the EPA issued a final rule that attempted to clarify the CWA’s jurisdictional reach over “waters of the United States” (“2015 Clean Water Rule”("WOTUS") and replace the pre-existing 1986 rule and guidance. In February 2018, the EPA issued a rule to delay the applicability of the 2015 Clean Water Rule until February 2020, but this delay rule was struck following a court challenge. Other federal district courts, however, issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself in several states. Taken together, the 2015 Clean Water Rule has been in effect in 22 states, including Colorado, and temporarily stayed in 27 states (the 2015 Clean Water Rule was in effect in certain counties in New Mexico and not in others). In those remaining states, the 1986 rule and guidance remained in effect. In October 2019, the EPA and the USACEArmy Corps of Engineers ("USACE") issued a final rule to repeal the 2015 Clean Water Ruleprevious regulations (the “2019"2019 Repeal Rule”Rule"). With the 2019 Repeal Rule, the agencies report that they will and implement the pre-2015 Clean Water Rule1986 WOTUS regulations and guidance nationwide.nationwide, until a new replacement rule could be adopted. The 2019 Repeal Rule became effective on December 23, 2019; accordingly, the 2015 Clean Water Rule is no longer in effect in any state.2019. However, numerous legal challenges to the 2019 Repeal Rule have already been filed in federal court.
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In January 2017, the Army Corps of EngineersUSACE 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 permitsNationwide 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”("SPCC") requirements of the CWA require appropriate secondary containment, load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak.
Endangered Species
The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles or golden eagles.
Other
In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016.
Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 (“OPA”("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems.
In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing and certification requirements.
In February 2018, the COGCC comprehensively amended its regulations for oil, gas and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection and other matters. In November 2019, the COGCC further amended its flowline regulations pursuant to SB 19-181 to impose additional requirements regarding flowline mapping, operational status, certification and abandonment, among other things. The COGCC has also adopted or amended numerous other rules in recent years, including rules relating to safety, flood protection and spill reporting.
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We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“OSHA”("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.
Employee Headcount
As of December 31, 2019,2020, we had approximately 540520 full-time employees, 235of whom are employed in field operations.
Employee Engagement
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.
Safety Culture
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.
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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.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.
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ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as the value of an investment in our common stock or other securities.
Risks Relating to SRC Acquisition
•Prolonged depressed crude oil prices may have adverse effects on the financial wellbeing of management’s attention caused byour business, including with respect to revenue, profitability, cash flows and liquidity; quantity and present value of our reserves; the SRC Acquisitionborrowing base under our revolving credit facility; and the integrationaccess to other sources of SRC’s operations into our company;capital;
•Negative financial impacts to SRC's facilitiesour business partners may cause delays or failure to pay service providers, which could result in liens being filed against our real and operations;personal property;
•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 or inconsistencies in standards, controls, procedures and policies.
•The cumulative effects of COVID-19 on the state have therefore increased as well. Similarly, the operations of both our company and SRC have been adversely affected in recent years by limitations in the availability of adequate midstream infrastructure in the Wattenberg Field. The increased percentage of our combined production located in the Wattenberg Field following the SRC Acquisition has proportionately increased our exposure to this risk, as well as other risks associated with operatingeconomy may result in a more concentrated geographic area. 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;
•our liquidity;
•the quantity and present value of our reserves;
•the borrowing base under our revolving credit facility and access to other sources of capital; and
•the nature and scale of our operations.
The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things:
•relatively minor changes in regional, national or global supply and demand;
•regional, national or global economic conditions, and perceived trends in those conditions;
•geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries ("OPEC"), and global events, such as the ongoing COVID-19 outbreak;pandemic; and
•regulatory changes.
The price of oil has historically been volatile, due in recent years to a combination of factors including increased U.S. supply and global economic concerns. In 2019,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 over $65approximately $59 per barrel to lows of approximately $45negative $40 per barrel.barrel
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(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 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 isare subject to a variety of risks. For example:
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 bythe 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.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:
•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.
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•Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other GHGs. For example, the EPA has made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. In addition, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline (although President Trump subsequently announced that the U.S. is withdrawing from the Paris Agreement). Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits.
•Proposals are made from time to time to amend U.S. federal and state tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling.
•The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage and use of surface water or groundwater or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition.
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.
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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:
•Items 1Decreases 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 2, Businessparticularly pipelines near water bodies, in various places throughout the country, and Properties - Governmental Regulationprotests have at times physically interrupted pipeline construction activities;
• for a summarySome 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 certain lawsreducing investment in midstream infrastructure; and
•The possibility that new or amended regulations, including regulations that currently applyincrease 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 us. Any of such laws and regulationstime 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 amended, and new laws or regulations could be implemented, in a way that adversely affects our operations.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
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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.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 is calculated. However, abasin. A significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges of $38.5 million and $458.4 million in 2019 and 2018, respectively, to write down assets. Similar charges could occur in the future.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 NGLs requires subjectiveeconomic 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 remainingreserves volumes, of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels andfuture operating and development costs, overfuture commodity prices, and a market based weighted average cost of capital rate. In determining the estimates of reserve and economic life of the properties.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. Independent petroleum engineers prepare our estimates of crude oil, natural gas and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on assumptions regarding commodity prices, production levels and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual results could greatly affect:
•the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties;
•future depreciation, depletion and amortization (“DD&A”) rates and amounts;
•impairments in the value of our assets;
•the classifications of reserves based on risk of recovery;
•estimates of future net cash flows;
•timing of our capital expenditures; and
•the amount of funds available for us to borrow under our revolving credit facility.
Some of our reserve estimates must be made with limited production histories, which renders these estimates less reliable than those based on longer production histories. Further, reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates, in part because they will not be produced under the same economic conditions as are used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons.
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At December 31, 2019,2020, approximately 6556 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $3.3$2.3 billionduring the five years ending December 31, 2024,2025, 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. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations.
We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including:
•crude oil, natural gas and NGL prices;
•the availability and cost of capital;
•drilling and production costs;
•availability and cost of drilling servicesrigs, and equipment;equipment, supplies, chemicals, personnel and oilfield services;
•drilling results;
•lease expirations or limitations as to depth;
•midstream constraints;
•access to and availability of water sourcing and distribution systems;
•regulatory approvals; and
•other factors.
Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances in order to facilitate exploration, though Colorado now requires applicants to own or
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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 orand numerous other reasons, our actual drilling activities may materially differ from those presently identified.
Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related inventory of drilling locations. In addition, our Wattenberg Field inventory was further reduced by recent acreage exchange transactions in which we received, among other things, increased working interests in certain locations in exchange for our right to develop other locations. We anticipate that our remaining locations in the field will not, on average, be as productive or as economic as many 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 expiration issuesexpirations and our continued analysis of geologic issueschallenges in certain areas.
The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect.
A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the hydrocarbons in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. For example, the data we use to model anticipated results from wells in a particular area may prove to be not representative of actual results from typical wells in the area, and this could result in production that falls short of estimates reflected in our internal business plans and/or guidance, "type curve" or other disclosures we make to the public. This risk is higher for us in certain areas in the Delaware Basin that have relatively complex geological characteristics and correspondingly greater variability in well results. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase, the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period.
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Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.
Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including:
•loss of well control;
•loss of drilling fluid circulation;
circulation and other facility or equipment malfunctions;
•title problems;
•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; andrequirements.
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.
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We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We frequently own less than all of the working interest in the oil and gas leases on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay 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 define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect our operations and our profitability.
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. Uncertainties created by the SRC Acquisition may make it more challenging for us to retain some employees. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
A failure to complete successful acquisitions would limit our growth.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. When attractive opportunities arise, acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. Ifopportunities, 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. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions 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.
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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 presentspresented a number of the foregoing risks - for example, because closing has occurred, we will have no recourse if we subsequently 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, in recent years,on January 18, 2021, a purported class action lawsuit was filed against us by a royalty owner alleging we have been subjectimproperly deducting certain post-production costs from the owner’s oil royalty payments. While we intend to lawsuits regarding royalty practices and payments, matters relating to certain of our affiliated partnerships and our environmental compliance programs. Thevigorously 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 the
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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. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our production could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
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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 byfrom 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, and have recently increased our indebtedness as part of the SRC Acquisition, including through the assumption of $550 million aggregate principal amount of 6.25% Senior Notes issued by SRC due December 2025 (the “SRC Senior Notes”). On January 17, 2020, we commenced an offer to repurchase the SRC Senior Notes at 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. If the SRC Senior notes are tendered to us in full or in part,outstanding. As a result, a significant portion of our liquidity wouldcash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs.
Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving credit facility or otherwise, to fund our liquidity needs.
A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining 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
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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;
•create liens;
•make specified types of investments;
•apply net proceeds from certain asset sales;
•engage in transactions with our affiliates;
•engage in sale and leaseback transactions;
•merge or consolidate;
•restrict dividends or other payments from restricted subsidiaries;
•sell equity interests of restricted subsidiaries; and
•sell, assign, transfer, lease, convey or dispose of assets.
Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in 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. The terms of the credit agreement require us to comply with certain financial covenants. Our ability to comply with these 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 thethese restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which couldour 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.
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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. ItThe U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is unclear whether new methodsin the process of calculatingassessing replacing U.S. dollar LIBOR will be established such that it continues to exist after 2021, or if alternative rates or benchmarks will be adopted.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. We cannotIt is not possible to predict the effect of the potentialthese changes to LIBOR or the establishment and use of alternative reference rates or benchmarks. If LIBOR becomes unavailable, our revolving credit facility requires us to work with the administrative agent to establish an alternate rate of interest and amend our credit agreement to reflect that new rate of interest, and until any such amendment is effective, all loans outstanding under the credit facility will be priced at the alternate base rate set forth in the credit agreement. We will continue to monitor the phaseout of LIBOR and if changes are made to the method of calculating LIBORUnited States or LIBOR ceases to exist, we may also need to amend certain other contracts and cannot predict what alternative rate or benchmark would be negotiated. The phaseout of LIBOR and any amendments to our credit facility or other contracts may result in an increase to our interest expense. In addition, the discontinuance of LIBOR could also cause disruptions to the credit or derivatives markets that would be harmful to our business.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 and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly
makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity.
At December 31, 2019,2020, we had hedged a total of 10.820.0 MMBbls and 3.2 MMBbls of crude oil through 2020 and 2021, respectively, and 4.0 Bcf120.5 MMBtu of natural gas through 2020. Additionally, we assumed hedges covering 3.9 MMBbls of crude oil through 2020 in the SRC Acquisition.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.
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The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.
The market price of our common stock is highly volatile and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger declines in the price of our common stock, including among others:
changes in production volumes, worldwide demand and prices for crude oil and natural gas;
gas, regulatory developments, and changes in securities analysts’ estimates of our financial performance;
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
None.
ITEM 3. LEGAL PROCEEDINGS
Information regarding our legal proceedings can be found in the footnote titled 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
Not applicable.
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PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERSSTOCKHOLDER 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."PDCE."
As of February 18, 2020,16, 2021, we had approximately 433430 stockholders of record. Since inception, no
While we have not declared any cash dividends have been declared on our common stock. Cashstock, our board of directors recently approved a quarterly dividend program expected to commence mid-2021. The dividend program and payment of any future dividends are restricted underthereunder will be made at the termsdiscretion 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 September 15, 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 5.75% senior notes due May 15, 2026 (the "2026 Senior Notes")leverage and other certain financial metrics that could impact our ability to pay cash dividends. As we declare dividends in the SRC Senior Notes.future, we will monitor compliance with such restrictions.
The following table presents information about our purchases of our common stock during the three monthsyear ended December 31, 2019:2020:
| Period | 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) | ||||||||||||||||||||||
January (2) | 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.
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| Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2) | Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions) (3) | ||||||||||
| October 1 - 31, 2019 | 346,080 | $ | 26.02 | 341,423 | $ | 45.6 | ||||||||
| November 1 - 30, 2019 | — | — | — | — | ||||||||||
| December 1 - 31, 2019 | 173 | 23.87 | — | — | ||||||||||
| Total fourth quarter 2019 purchases | 346,253 | 26.02 | 341,423 | $ | 45.6 | |||||||||
The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 20192020 with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 233 196crude 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, 2014,2015, 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.
Among PDC Energy, Inc., the S&P 500 Index, and a Peer Group
| 12/15 | 12/16 | 12/17 | 12/18 | 12/19 | 12/20 | ||||||||||||||||||||||||||||||
| PDC Energy | 100.00 | 135.97 | 96.55 | 55.75 | 49.03 | 38.46 | |||||||||||||||||||||||||||||
| S&P 500 | 100.00 | 111.96 | 136.4 | 130.42 | 171.49 | 203.04 | |||||||||||||||||||||||||||||
| Peer Group | 100.00 | 137.64 | 131.01 | 94.81 | 85.35 | 52.16 | |||||||||||||||||||||||||||||
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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, | ||||||||||||||||||||||||||||||||
2020 (1) | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||
| (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: | ||||||||||||||||||||||||||||||||
| Basic | $ | (7.37) | $ | (0.89) | $ | 0.03 | $ | (1.94) | $ | (5.01) | ||||||||||||||||||||||
| Diluted | (7.37) | (0.89) | 0.03 | (1.94) | (5.01) | |||||||||||||||||||||||||||
| Statement of Cash Flows: | ||||||||||||||||||||||||||||||||
| Net cash flows from: | ||||||||||||||||||||||||||||||||
| Operating activities | $ | 870.1 | $ | 858.2 | $ | 889.3 | $ | 597.8 | $ | 486.3 | ||||||||||||||||||||||
| Investing activities | (687.2) | (677.8) | (1,087.9) | (717.0) | (1,509.1) | |||||||||||||||||||||||||||
| 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) | |||||||||||||||||||||||||||
| Balance Sheet: | ||||||||||||||||||||||||||||||||
| 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.
39
| Year Ended/As of December 31, | ||||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 (1) | 2015 | ||||||||||||||||
| (in millions, except per share data and as noted) | ||||||||||||||||||||
| Statement of Operations: | ||||||||||||||||||||
| Crude oil, natural gas and NGLs sales | $ | 1,307.3 | $ | 1,390.0 | $ | 913.1 | $ | 497.4 | $ | 378.7 | ||||||||||
| Commodity price risk management gain (loss), net | (162.8 | ) | 145.2 | (3.9 | ) | (125.7 | ) | 203.2 | ||||||||||||
| Total revenues | 1,156.1 | 1,548.7 | 921.6 | 382.9 | 595.3 | |||||||||||||||
| Net income (loss) | (56.7 | ) | 2.0 | (127.5 | ) | (245.9 | ) | (68.3 | ) | |||||||||||
| Earnings per share: | ||||||||||||||||||||
| Basic | $ | (0.89 | ) | $ | 0.03 | $ | (1.94 | ) | $ | (5.01 | ) | $ | (1.74 | ) | ||||||
| Diluted | (0.89 | ) | 0.03 | (1.94 | ) | (5.01 | ) | (1.74 | ) | |||||||||||
| Statement of Cash Flows: | ||||||||||||||||||||
| Net cash flows from: | ||||||||||||||||||||
| Operating activities | $ | 858.2 | $ | 889.3 | $ | 597.8 | $ | 486.3 | $ | 411.1 | ||||||||||
| Investing activities | (677.8 | ) | (1,087.9 | ) | (717.0 | ) | (1,509.1 | ) | (604.3 | ) | ||||||||||
| Financing activities | (188.9 | ) | 18.1 | 65.0 | 1,266.1 | 178.0 | ||||||||||||||
| Capital expenditures for development of crude oil and natural gas properties (2) | (855.9 | ) | (946.4 | ) | (737.2 | ) | (436.9 | ) | (599.5 | ) | ||||||||||
| Acquisition of crude oil and natural gas properties | (13.2 | ) | (180.0 | ) | (15.6 | ) | (1,073.7 | ) | — | |||||||||||
| Balance Sheet: | ||||||||||||||||||||
| Total assets | $ | 4,448.7 | $ | 4,544.1 | $ | 4,420.4 | $ | 4,485.8 | $ | 2,370.5 | ||||||||||
| Working capital (deficit) | (57.2 | ) | (166.6 | ) | (16.4 | ) | 129.2 | 30.7 | ||||||||||||
| Total debt, net of unamortized discount and debt issuance costs | 1,177.2 | 1,194.9 | 1,151.9 | 1,044.0 | 642.4 | |||||||||||||||
| Total stockholders' equity | 2,335.5 | 2,526.7 | 2,507.6 | 2,622.8 | 1,287.2 | |||||||||||||||
| Average Pricing and Production Expenses (per Boe and as a percent of sales for production taxes): | ||||||||||||||||||||
| Sales price (excluding net settlements on derivatives) | $ | 26.46 | $ | 34.61 | $ | 28.69 | $ | 22.43 | $ | 24.64 | ||||||||||
| Lease operating expenses | 2.88 | 3.26 | 2.82 | 2.70 | 3.71 | |||||||||||||||
| Production taxes | 1.63 | 2.25 | 1.91 | 1.42 | 1.20 | |||||||||||||||
| Production taxes (as a percent of sales) | 6.2 | % | 6.5 | % | 6.6 | % | 6.3 | % | 4.9 | % | ||||||||||
| Transportation, gathering and processing | 0.94 | 0.93 | 1.04 | 0.83 | 0.66 | |||||||||||||||
| Total production | 49,414 | 40,160 | 31,830 | 22,176 | 15,369 | |||||||||||||||
| Total proved reserves (MMBoe) | 610.9 | 544.9 | 452.9 | 341.4 | 272.8 | |||||||||||||||
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes thereto included elsewhere inItem 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 20172018 to 20182019 has been omitted from this report but may be found in Item 7,7. Management's Discussion and Analysis, of our Annual Report on Form 10-K for the year ended December 31, 2018,2019, filed with the SEC on February 28, 2019.27, 2020. Further, we encourage you to revisitreview the Special Note Regarding Forward-Looking Statements in Part I of this report.
EXECUTIVE SUMMARY
COVID-19 Impact
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.
Financial Matters
Production volumes increased 2338 percent to 49.468.4 MMBoe in 20192020 compared to 2018.2019. The majority of the increase in production volumes was primarily attributableis attributed to the continued success of our horizontal Niobrara and Codell drilling programproducing properties acquired in the Wattenberg Field and growing production from our horizontal Wolfcamp drilling program in our Delaware Basin properties.SRC Acquisition. Total liquids production of crude oil and NGLs comprised 6160 percent of production in 2019.2020. For the month ended December 31, 2019,2020, we maintained an average production rate of approximately 139,000178,000 Boe per day, up from approximately 129,000139,000 Boe per day for the month ended December 31, 2018.
Crude oil, natural gas and NGLs sales revenue decreased to $1.2 billion in 2020 compared to $1.3 billion in 2019, compared to $1.4 billion in 2018, driven by a 2436 percent decrease in weighted-average realized commodity prices, partially offset by the 2338 percent increase in production.
We had negativepositive net settlements from commodity derivative contracts of $17.6$279.3 million for 20192020 as compared to negative net settlements of $115.5$17.6 million for 2018. 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 both 2019 and 2018.2019.
In 2019,2020, 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 income of $2.0 million, or $0.03 per diluted share, in 2018. 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, up two percentrespectively. Cash flows from $868.7operations were $870.1 million and $858.2 million in 2018.
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.
40
SRC Acquisition
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 3938.9 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 held.and the cancellation of outstanding SRC equity awards pursuant to the Merger Agreement.
Liquidity
Available liquidity as of December 31, 20192020 was $1.3$1.4 billion, primarily due to $1.3which 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 2019,2020, as part of our fall 2020 semi-annual redetermination, the borrowing base onof our revolving credit facility was reaffirmed atreduced from $1.7 billion to $1.6 billion, and wewith a corresponding automatic reduction of our elected commitment level to retain our commitment amount at $1.3$1.6 billion.
Stock Repurchase Program
The following tables summarizessummarize our drilling and completion activity for the year ended December 31, 2019:
| Wells Operated by PDC | ||||||||||||||||||
| Wattenberg Field | Delaware Basin | Total | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||
| In-process as of December 31, 2018 | 133 | 122.4 | 18 | 17.4 | 151 | 139.8 | ||||||||||||
| Wells spud | 126 | 117.0 | 33 | 31.7 | 159 | 148.7 | ||||||||||||
| Wells turned-in-line | (114 | ) | (105.1 | ) | (21 | ) | (20.0 | ) | (135 | ) | (125.1 | ) | ||||||
| In-process as of December 31, 2019 | 145 | 134.3 | 30 | 29.1 | 175 | 163.4 | ||||||||||||
| Wells Operated by Others | ||||||||||||||||||
| Wattenberg Field | Delaware Basin | Total | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||
| In-process as of December 31, 2018 | 5 | 2.0 | 6 | 0.9 | 11 | 2.9 | ||||||||||||
| Wells spud | 55 | 4.4 | 3 | 0.4 | 58 | 4.8 | ||||||||||||
| Wells turned-in-line | (19 | ) | (1.1 | ) | (9 | ) | (1.3 | ) | (28 | ) | (2.4 | ) | ||||||
| In-process as of December 31, 2019 | 41 | 5.3 | — | — | 41 | 5.3 | ||||||||||||
2020:
| Operated Wells | ||||||||||||||||||||||||||||||||||||||
| Wattenberg Field | Delaware Basin (1) | Total | ||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||||
| Wells turned-in-line | (124) | (116.5) | (13) | (13.0) | (137) | (129.5) | ||||||||||||||||||||||||||||||||
| 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 and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our drilled uncompletedin-process wells are generally completed and turned-in-line within a yeartwo years of drilling.
We anticipate that our total production for 20202021 will range between 205,000190,000 Boe to 215,000200,000 Boe per day, approximately 78,00064,000 Bbls to 82,00068,000 Bbls of which are expected to be crude oil. Our planned 20202021 capital investments in crude
41
oil and natural gas properties, which we expect to be between $1.0 billion$500 million and $1.1 billion,$600 million, are focused on continued execution of our development plans in the Wattenberg Field including acreage received in the SRC Acquisition, and the Delaware Basin.
We believe that we maintain a degree of operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate strategy. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate.
We may revise our 20202021 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities.
| Low | High | ||||||
| Operating Expenses | |||||||
| Lease operating expenses ($/Boe) | $ | 2.70 | $ | 2.90 | |||
| Transportation, gathering and processing expenses ("TGP") ($/Boe) | $ | 0.95 | $ | 1.15 | |||
| Production taxes (percent of crude oil, natural gas and NGL sales) | 6.5 | % | 7.5 | % | |||
| Estimated Price Realizations | |||||||
| Crude oil (percent of NYMEX, excluding TGP) | 93 | % | 97 | % | |||
| Natural gas (percent of NYMEX, excluding TGP) | 50 | % | 55 | % | |||
| NGLs ($/Bbl, excluding TGP) | $ | 10.00 | $ | 12.00 | |||
Wattenberg Field.On a per unit basis We are drilling in the horizontal Niobrara and excluding transaction costs incurred relatedCodell 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 SRC AcquisitionWattenberg 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 $30 million, 214 gross operated DUCs and 300 approved permitted locations. In 2021,we expect our generalto operate with one full-time horizontal rig and administrative expensecompletion 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 rangeDelaware Basin for 2021 are expected to be approximately 25 percent of $1.90our total capital investments, of which approximately 90 percent is expected to $2.10be 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 Boewell between $6.7 million and $8.0 million for 2020.MRL and XRL wells, depending upon the lateral length of the well.
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. Proponents of such initiatives have begun the process of attempting to qualify six initiatives to appear on the ballot in November 2020. Five of the initiatives are focused on increased setbacks, with differing distances and criteria, and one is focused on bonding requirements.
It is nevertheless possible that future ballot initiatives will be proposed that would dramatically limit the subject of other procedural requirements. If those requirements are satisfied, proponentsareas of the initiatives can begin the process of collecting the signatures neededstate in which drilling would be permitted to qualify them for the November 2020 ballot. We do not know what the outcome of this process will be; however, a similar setback ballot initiative, Proposition 112, qualified for the ballot but failed to pass in 2018.
occur. See Part I, Item1A,Item1A. Risk Factors, for additional information regardingFactors- Relating to Our Business and the ballot initiatives.
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, | |||||||||||||||||||||||||||||
| Percent Change | |||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2020-2019 | 2019-2018 | |||||||||||||||||||||||||
| (dollars in millions, except per unit data) | |||||||||||||||||||||||||||||
| Production: | |||||||||||||||||||||||||||||
| 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.
43
| Year Ended December 31, | |||||||||||||||||
| Percent Change | |||||||||||||||||
| 2019 | 2018 | 2017 | 2019-2018 | 2018-2017 | |||||||||||||
| (dollars in millions, except per unit data) | |||||||||||||||||
| Production: | |||||||||||||||||
| Crude oil (MBbls) | 19,166 | 16,963 | 12,902 | 13.0 | % | 31.5 | % | ||||||||||
| Natural gas (MMcf) | 115,950 | 88,017 | 71,689 | 31.7 | % | 22.8 | % | ||||||||||
| NGLs (MBbls) | 10,923 | 8,527 | 6,981 | 28.1 | % | 22.1 | % | ||||||||||
| Crude oil equivalent (MBoe) | 49,414 | 40,160 | 31,830 | 23.0 | % | 26.2 | % | ||||||||||
| Average Boe per day (Boe) | 135,381 | 110,027 | 87,206 | 23.0 | % | 26.2 | % | ||||||||||
| Crude Oil, Natural Gas and NGLs Sales: | |||||||||||||||||
| Crude oil | $ | 1,020.7 | $ | 1,038.0 | $ | 625.0 | (1.7 | )% | 66.1 | % | |||||||
| Natural gas | 151.0 | 163.2 | 158.3 | (7.5 | )% | 3.1 | % | ||||||||||
| NGLs | 135.6 | 188.8 | 129.8 | (28.2 | )% | 45.5 | % | ||||||||||
| Total crude oil, natural gas and NGLs sales | $ | 1,307.3 | $ | 1,390.0 | $ | 913.1 | (5.9 | )% | 52.2 | % | |||||||
| Net Settlements on Commodity Derivatives: | |||||||||||||||||
| Crude oil | $ | (18.3 | ) | $ | (124.4 | ) | $ | (2.7 | ) | (85.3 | )% | * | |||||
| Natural gas | 0.7 | 13.9 | 23.3 | (95.0 | )% | (40.3 | )% | ||||||||||
| NGLs | — | (5.0 | ) | (7.3 | ) | * | (31.5 | )% | |||||||||
| Total net settlements on derivatives | $ | (17.6 | ) | $ | (115.5 | ) | $ | 13.3 | (84.8 | )% | * | ||||||
| Average Sales Price (excluding net settlements on derivatives): | |||||||||||||||||
| Crude oil (per Bbl) | $ | 53.26 | $ | 61.19 | $ | 48.45 | (13.0 | )% | 26.3 | % | |||||||
| Natural gas (per Mcf) | 1.30 | 1.85 | 2.21 | (29.7 | )% | (16.3 | )% | ||||||||||
| NGLs (per Bbl) | 12.41 | 22.14 | 18.59 | (43.9 | )% | 19.1 | % | ||||||||||
| Crude oil equivalent (per Boe) | 26.46 | 34.61 | 28.69 | (23.5 | )% | 20.6 | % | ||||||||||
| Average Costs and Expenses (per Boe): | |||||||||||||||||
| Lease operating expenses | $ | 2.88 | $ | 3.26 | $ | 2.82 | (11.7 | )% | 15.6 | % | |||||||
| Production taxes | 1.63 | 2.25 | 1.91 | (27.6 | )% | 17.8 | % | ||||||||||
| Transportation, gathering and processing expenses | 0.94 | 0.93 | 1.04 | 1.1 | % | (10.6 | )% | ||||||||||
| General and administrative expense | 3.27 | 4.25 | 3.78 | (23.1 | )% | 12.4 | % | ||||||||||
| Depreciation, depletion and amortization | 13.04 | 13.94 | 14.74 | (6.5 | )% | (5.4 | )% | ||||||||||
| Lease Operating Expenses by Operating Region (per Boe): | |||||||||||||||||
| Wattenberg Field | $ | 2.50 | $ | 2.99 | $ | 2.48 | (16.4 | )% | 20.6 | % | |||||||
| Delaware Basin | 4.15 | 4.14 | 5.16 | 0.2 | % | (19.8 | )% | ||||||||||
| Utica Shale (1) | — | 3.46 | 1.66 | * | 108.4 | % | |||||||||||
Crude Oil, Natural Gas and NGLs Sales
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2019 | 2018 | 2020 | 2019 | |||||||||||||||||||||
| (in millions) | (in millions) | |||||||||||||||||||||||
| Change in: | Change in: | |||||||||||||||||||||||
| Production | $ | 239.6 | $ | 261.6 | Production | $ | 383.2 | $ | 239.6 | |||||||||||||||
| Average crude oil price | (152.0 | ) | 216.1 | Average crude oil price | (446.4) | (152.0) | ||||||||||||||||||
| Average natural gas price | (64.0 | ) | (31.1 | ) | Average natural gas price | (37.0) | (64.0) | |||||||||||||||||
| Average NGLs price | (106.3 | ) | 30.3 | Average NGLs price | (54.5) | (106.3) | ||||||||||||||||||
| Total change in crude oil, natural gas and NGLs sales revenue | $ | (82.7 | ) | $ | 476.9 | 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, | ||||||||||||||||||||||||||||||||
| Percent Change | ||||||||||||||||||||||||||||||||
| 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) | — | — | 414 | * | * | |||||||||||||||||||||||||||
| Total | 165,637 | 115,950 | 88,017 | 43 | % | 32 | % | |||||||||||||||||||||||||
| NGLs (MBbls) | ||||||||||||||||||||||||||||||||
| Wattenberg Field | 14,495 | 8,198 | 6,455 | 77 | % | 27 | % | |||||||||||||||||||||||||
| Delaware Basin | 2,547 | 2,725 | 2,038 | (7) | % | 34 | % | |||||||||||||||||||||||||
Utica Shale (1) | — | — | 34 | * | * | |||||||||||||||||||||||||||
| Total | 17,042 | 10,923 | 8,527 | 56 | % | 28 | % | |||||||||||||||||||||||||
| Crude oil equivalent (MBoe) | ||||||||||||||||||||||||||||||||
| Wattenberg Field | 57,521 | 37,984 | 30,652 | 51 | % | 24 | % | |||||||||||||||||||||||||
| Delaware Basin | 10,847 | 11,430 | 9,359 | (5) | % | 22 | % | |||||||||||||||||||||||||
Utica Shale (1) | — | — | 149 | * | * | |||||||||||||||||||||||||||
| Total | 68,368 | 49,414 | 40,160 | 38 | % | 23 | % | |||||||||||||||||||||||||
| Average crude oil equivalent per day (Boe) | ||||||||||||||||||||||||||||||||
| Wattenberg Field | 157,161 | 104,066 | 83,978 | 51 | % | 24 | % | |||||||||||||||||||||||||
| Delaware Basin | 29,637 | 31,315 | 25,641 | (5) | % | 22 | % | |||||||||||||||||||||||||
Utica Shale (1) | — | — | 408 | * | * | |||||||||||||||||||||||||||
| Total | 186,798 | 135,381 | 110,027 | 38 | % | 23 | % | |||||||||||||||||||||||||
____________
* Percent change is not meaningful.
(1)In March 2018, we completed the disposition of our Utica Shale properties.
44
| Year Ended December 31, | |||||||||||||||
| Percent Change | |||||||||||||||
| Production by Operating Region | 2019 | 2018 | 2017 | 2019-2018 | 2018-2017 | ||||||||||
| Crude oil (MBbls) | |||||||||||||||
| Wattenberg Field | 14,489 | 12,809 | 10,922 | 13.1 | % | 17.3 | % | ||||||||
| Delaware Basin | 4,677 | 4,108 | 1,699 | 13.9 | % | 141.8 | % | ||||||||
| Utica Shale (1) | — | 46 | 281 | * | (83.6 | )% | |||||||||
| Total | 19,166 | 16,963 | 12,902 | 13.0 | % | 31.5 | % | ||||||||
| Natural gas (MMcf) | |||||||||||||||
| Wattenberg Field | 91,785 | 68,326 | 60,106 | 34.3 | % | 13.7 | % | ||||||||
| Delaware Basin | 24,165 | 19,277 | 9,410 | 25.4 | % | 104.9 | % | ||||||||
| Utica Shale (1) | — | 414 | 2,173 | * | (80.9 | )% | |||||||||
| Total | 115,950 | 88,017 | 71,689 | 31.7 | % | 22.8 | % | ||||||||
| NGLs (MBbls) | |||||||||||||||
| Wattenberg Field | 8,198 | 6,455 | 5,876 | 27.0 | % | 9.9 | % | ||||||||
| Delaware Basin | 2,725 | 2,038 | 917 | 33.7 | % | 122.2 | % | ||||||||
| Utica Shale (1) | — | 34 | 188 | * | (81.9 | )% | |||||||||
| Total | 10,923 | 8,527 | 6,981 | 28.1 | % | 22.1 | % | ||||||||
| Crude oil equivalent (MBoe) | |||||||||||||||
| Wattenberg Field | 37,984 | 30,652 | 26,815 | 23.9 | % | 14.3 | % | ||||||||
| Delaware Basin | 11,430 | 9,359 | 4,184 | 22.1 | % | 123.7 | % | ||||||||
| Utica Shale (1) | — | 149 | 831 | * | (82.1 | )% | |||||||||
| Total | 49,414 | 40,160 | 31,830 | 23.0 | % | 26.2 | % | ||||||||
| Average crude oil equivalent per day (Boe) | |||||||||||||||
| Wattenberg Field | 104,066 | 83,978 | 73,466 | 23.9 | % | 14.3 | % | ||||||||
| Delaware Basin | 31,315 | 25,641 | 11,463 | 22.1 | % | 123.7 | % | ||||||||
| Utica Shale (1) | — | 408 | 2,277 | * | (82.1 | )% | |||||||||
| Total | 135,381 | 110,027 | 87,206 | 23.0 | % | 26.2 | % | ||||||||
The following table presents our crude oil, natural gas and NGLs production ratio by operating region:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||||||||||
| Production Ratio by Operating Region | 2019 | 2018 | 2017 | Production Ratio by Operating Region | 2020 | 2019 | 2018 | ||||||||||||||||||||||
| Wattenberg Field | Wattenberg Field | ||||||||||||||||||||||||||||
| Crude oil | 38 | % | 42 | % | 41 | % | Crude oil | 34 | % | 38 | % | 42 | % | ||||||||||||||||
| Natural gas | 40 | % | 37 | % | 37 | % | Natural gas | 41 | % | 40 | % | 37 | % | ||||||||||||||||
| NGLs | 22 | % | 21 | % | 22 | % | NGLs | 25 | % | 22 | % | 21 | % | ||||||||||||||||
| Total | 100 | % | 100 | % | 100 | % | Total | 100 | % | 100 | % | 100 | % | ||||||||||||||||
| Delaware Basin | Delaware Basin | ||||||||||||||||||||||||||||
| Crude oil | 41 | % | 44 | % | 41 | % | Crude oil | 38 | % | 41 | % | 44 | % | ||||||||||||||||
| Natural gas | 35 | % | 34 | % | 37 | % | Natural gas | 38 | % | 35 | % | 34 | % | ||||||||||||||||
| NGLs | 24 | % | 22 | % | 22 | % | NGLs | 24 | % | 24 | % | 22 | % | ||||||||||||||||
| Total | 100 | % | 100 | % | 100 | % | Total | 100 | % | 100 | % | 100 | % | ||||||||||||||||
| Utica Shale (1) | Utica Shale (1) | ||||||||||||||||||||||||||||
| Crude oil | — | % | 31 | % | 34 | % | Crude oil | — | % | — | % | 31 | % | ||||||||||||||||
| Natural gas | — | % | 46 | % | 43 | % | Natural gas | — | % | — | % | 46 | % | ||||||||||||||||
| NGLs | — | % | 23 | % | 23 | % | NGLs | — | % | — | % | 23 | % | ||||||||||||||||
| Total | — | % | 100 | % | 100 | % | Total | — | % | — | % | 100 | % | ||||||||||||||||
____________
(1)In March 2018, we completed the disposition of our Utica Shale properties.
Midstream Capacity
Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, pipelinescompression and processing facilities, as well as transportation pipelines out of the basin, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. In recent years, there has beenresponse to the substantial development drilling in our current areas of operation in recent years, third-party midstream providers have significantly expanded their midstream facilities and this has made it more challenging for providers ofservices. These third-party midstream infrastructure and services to keep pacefacility expansions, in conjunction with the corresponding increasesmore recent slowdown in field-wide production. producer activity, have provided for improved and more stabilized line pressures and a production environment that is more favorable for producers, both currently and for the near term given anticipated producer activity levels.
The ultimate timing and availability of adequate infrastructure is not withinremains out of our control and we could experience capacity constraints for extended periods of time that could negatively impact our ability to meet our production targets.control. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. Like other producers, we from time to time we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to sufficiently meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls.
Our production in the Wattenberg Field is significantly dependent on DCP's gathering system, and this reliance increased considerably when we closed the SRC Acquisition. We continue to work with our midstream service providers in an
45
effort to ensure all of the existing in-basin infrastructure is fully utilized and that all options for system expansion are evaluated and implemented to the extent possible to accommodate projected future volume growth from the field.
Delaware Basin Delaware Basin. . Our production from the Delaware Basin was not materially affected by midstream or downstream capacity constraints during 2019. However, despite the completion and start-up of a new natural gas residue pipeline, natural gas takeaway capacity downstream of in-field gathering and processing facilitiesyear ended December 31, 2020. Similar to the Wattenberg Field, our crude oil netback pricing realizations were most negatively impacted by the demand reduction that resulted from COVID-19.
Pipeline utilization in the basin continues to operate close to capacity and near-term production constraints, and lower natural gas netback pricing, are likely until at leastPermian Basin has fallen from the constrained levels experienced during the first quarter of 2021, when the next2020. The COVID-19-induced downturn also forced widespread curtailments in natural gas residueproduction, which lowered pipeline out ofutilization and eventually improved pricing differentials in the basin is scheduled to be commissioned.
Crude Oil, Natural Gas and NGLs Pricing
Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially. Our realized sales prices for crude oil, natural gas and NGLs decreased 36 percent during 20192020 as compared to 2018.2019. The NYMEX average daily crude oil and NYMEX first-of-the-month natural gas prices decreased 1231 percent and 1521 percent, respectively, as compared to 2018.2019. The decreases were primarily due to the effects of the COVID-19 pandemic, geopolitical conditions and supply disruptions.
46
The following tables presenttable presents weighted-average sales prices of crude oil, natural gas and NGLs for the periods presented:
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| Weighted-Average Realized Sales Price by Operating Region | Percent Change | |||||||||||||||||||||||||||||||
| (excluding net settlements on derivatives) | 2020 | 2019 | 2018 | 2020-2019 | 2019-2018 | |||||||||||||||||||||||||||
| Crude oil (per Bbl) | ||||||||||||||||||||||||||||||||
| Wattenberg Field | $ | 34.21 | $ | 52.99 | $ | 61.14 | (35) | % | (13) | % | ||||||||||||||||||||||
| Delaware Basin | 35.48 | 54.08 | 61.37 | (34) | % | (12) | % | |||||||||||||||||||||||||
Utica Shale (1) | — | — | 58.10 | * | * | |||||||||||||||||||||||||||
| Weighted-average price | 34.44 | 53.26 | 61.19 | (35) | % | (13) | % | |||||||||||||||||||||||||
| Natural gas (per Mcf) | ||||||||||||||||||||||||||||||||
| Wattenberg Field | 1.22 | 1.49 | 1.90 | (18) | % | (22) | % | |||||||||||||||||||||||||
| Delaware Basin | 0.28 | 0.57 | 1.66 | (51) | % | (66) | % | |||||||||||||||||||||||||
Utica Shale (1) | — | — | 2.68 | * | * | |||||||||||||||||||||||||||
| Weighted-average price | 1.08 | 1.30 | 1.85 | (17) | % | (30) | % | |||||||||||||||||||||||||
| NGLs (per Bbl) | ||||||||||||||||||||||||||||||||
| Wattenberg Field | 8.84 | 11.51 | 20.58 | (23) | % | (44) | % | |||||||||||||||||||||||||
| Delaware Basin | 11.32 | 15.12 | 27.06 | (25) | % | (44) | % | |||||||||||||||||||||||||
Utica Shale (1) | — | — | 24.29 | * | * | |||||||||||||||||||||||||||
| Weighted-average price | 9.21 | 12.41 | 22.14 | (26) | % | (44) | % | |||||||||||||||||||||||||
| Crude oil equivalent (per Boe) | ||||||||||||||||||||||||||||||||
| Wattenberg Field | 16.84 | 26.31 | 34.13 | (36) | % | (23) | % | |||||||||||||||||||||||||
| Delaware Basin | 16.94 | 26.95 | 36.25 | (37) | % | (26) | % | |||||||||||||||||||||||||
Utica Shale (1) | — | — | 30.98 | * | * | |||||||||||||||||||||||||||
| Weighted-average price | 16.86 | 26.46 | 34.61 | (36) | % | (24) | % | |||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||
| Weighted-Average Realized Sales Price by Operating Region | Percent Change | |||||||||||||||||
| (excluding net settlements on derivatives) | 2019 | 2018 | 2017 | 2019-2018 | 2018-2017 | |||||||||||||
| Crude oil (per Bbl) | ||||||||||||||||||
| Wattenberg Field | $ | 52.99 | $ | 61.14 | $ | 48.48 | (13.3 | )% | 26.1 | % | ||||||||
| Delaware Basin | 54.08 | 61.37 | 48.68 | (11.9 | )% | 26.1 | % | |||||||||||
| Utica Shale (1) | — | 58.10 | 45.63 | * | 27.3 | % | ||||||||||||
| Weighted-average price | 53.26 | 61.19 | 48.45 | (13.0 | )% | 26.3 | % | |||||||||||
| Natural gas (per Mcf) | ||||||||||||||||||
| Wattenberg Field | 1.49 | 1.90 | 2.19 | (21.6 | )% | (13.2 | )% | |||||||||||
| Delaware Basin | 0.57 | 1.66 | 2.26 | (65.7 | )% | (26.5 | )% | |||||||||||
| Utica Shale (1) | — | 2.68 | 2.40 | * | 11.7 | % | ||||||||||||
| Weighted-average price | 1.30 | 1.85 | 2.21 | (29.7 | )% | (16.3 | )% | |||||||||||
| NGLs (per Bbl) | ||||||||||||||||||
| Wattenberg Field | 11.51 | 20.58 | 17.75 | (44.1 | )% | 15.9 | % | |||||||||||
| Delaware Basin | 15.12 | 27.06 | 22.64 | (44.1 | )% | 19.5 | % | |||||||||||
| Utica Shale (1) | — | 24.29 | 25.06 | * | (3.1 | )% | ||||||||||||
| Weighted-average price | 12.41 | 22.14 | 18.59 | (43.9 | )% | 19.1 | % | |||||||||||
| Crude oil equivalent (per Boe) | ||||||||||||||||||
| Wattenberg Field | 26.31 | 34.13 | 28.55 | (22.9 | )% | 19.5 | % | |||||||||||
| Delaware Basin | 26.95 | 36.25 | 29.80 | (25.7 | )% | 21.6 | % | |||||||||||
| Utica Shale (1) | — | 30.98 | 27.36 | * | 13.2 | % | ||||||||||||
| Weighted-average price | 26.46 | 34.61 | 28.69 | (23.5 | )% | 20.6 | % | |||||||||||
* Percent change is not meaningful.
Crude oil, natural gas and NGLs revenues are recognized when we transfer control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to occur when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received.
Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us based on a percent of proceeds or a sales price fixed at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index on which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transportation and processing on a per unit basis. Under this
method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses.
Beginning in the second quarter of 2020, COVID-19 led to government restrictions on movement and economic activity, triggering a dramatic reduction in crude oil demand. This negatively impacted crude oil netback pricing realizations, which resulted in meaningful production curtailments during the second quarter of 2020.We expect our realized crude oil prices to be volatile through 2021 due to market uncertainties in crude oil demand as a result of COVID-19.
47
As discussed above, we enter into agreements for the sale and transportation, gathering and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications in the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based on average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based on first-of-the-month index prices, as in each case this is the method used to sell the majority of these commodities pursuant to terms of the relevant sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after transportation, gathering and processing expenses shown in the table below represents our approximate composite per barrel price for NGLs.
| 2020 | Average NYMEX Price | Average Realized Price Before Transportation, Gathering and Processing Expenses | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | Average Transportation, Gathering and Processing Expenses | Average Realized Price After Transportation, Gathering and Processing Expenses | Average Realization Percentage After Transportation, Gathering and Processing Expenses | ||||||||||||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 39.40 | $ | 34.44 | 87 | % | $ | 2.34 | $ | 32.10 | 81 | % | ||||||||||||||||||||||||||
| Natural gas (per MMBtu) | 2.08 | 1.08 | 52 | % | 0.12 | 0.96 | 46 | % | ||||||||||||||||||||||||||||||
| NGLs (per Bbl) | 39.40 | 9.21 | 23 | % | — | 9.21 | 23 | % | ||||||||||||||||||||||||||||||
| Crude oil equivalent (per Boe) | 28.52 | 16.86 | 59 | % | 1.10 | 15.76 | 55 | % | ||||||||||||||||||||||||||||||
| 2019 | Average NYMEX Price | Average Realized Price Before Transportation, Gathering and Processing Expenses | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | Average Transportation, Gathering and Processing Expenses | Average Realized Price After Transportation, Gathering and Processing Expenses | Average Realization Percentage After Transportation, Gathering and Processing Expenses | ||||||||||||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 57.03 | $ | 53.26 | 93 | % | $ | 1.24 | $ | 52.02 | 91 | % | ||||||||||||||||||||||||||
| Natural gas (per MMBtu) | 2.63 | 1.30 | 49 | % | 0.17 | 1.13 | 43 | % | ||||||||||||||||||||||||||||||
| NGLs (per Bbl) | 57.03 | 12.41 | 22 | % | 0.10 | 12.31 | 22 | % | ||||||||||||||||||||||||||||||
| Crude oil equivalent (per Boe) | 40.95 | 26.46 | 65 | % | 0.90 | 25.56 | 62 | % | ||||||||||||||||||||||||||||||
| 2018 | Average NYMEX Price | Average Realized Price Before Transportation, Gathering and Processing Expenses | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | Average Transportation, Gathering and Processing Expenses | Average Realized Price After Transportation, Gathering and Processing Expenses | Average Realization Percentage After Transportation, Gathering and Processing Expenses | ||||||||||||||||||||||||||||||||
| Crude oil (per Bbl) | $ | 64.77 | $ | 61.19 | 94 | % | $ | 0.94 | $ | 60.25 | 93 | % | ||||||||||||||||||||||||||
| Natural gas (per MMBtu) | 3.09 | 1.85 | 60 | % | 0.22 | 1.63 | 53 | % | ||||||||||||||||||||||||||||||
| NGLs (per Bbl) | 64.77 | 22.14 | 34 | % | 0.21 | 21.93 | 34 | % | ||||||||||||||||||||||||||||||
| Crude oil equivalent (per Boe) | 47.87 | 34.61 | 72 | % | 0.93 | 33.68 | 70 | % | ||||||||||||||||||||||||||||||
| 2017 | Average NYMEX Price | Average Realized Price Before Transportation, Gathering and Processing Expenses | Average Realization Percentage Before Transportation, Gathering and Processing Expenses | Average Transportation, Gathering and Processing Expenses | Average Realized Price After Transportation, Gathering and Processing Expenses | Average Realization Percentage After Transportation, Gathering and Processing Expenses | ||||||||||||||||
| Crude oil (per Bbl) | $ | 50.95 | $ | 48.45 | 95 | % | $ | 1.41 | $ | 47.04 | 92 | % | ||||||||||
| Natural gas (per MMBtu) | 3.11 | 2.21 | 71 | % | 0.17 | 2.04 | 66 | % | ||||||||||||||
| NGLs (per Bbl) | 50.95 | 18.59 | 36 | % | 0.30 | 18.29 | 36 | % | ||||||||||||||
| Crude oil equivalent (per Boe) | 38.83 | 28.69 | 74 | % | 1.04 | 27.65 | 71 | % | ||||||||||||||
Our average realization percentages for crude oil decreased in 2019 were consistent with those for 2018. The realization percentage for our natural gas sales decreased2020 as compared to 2018,2019, primarily due to wideninghigher quantity deducts, larger negative roll realizations and oil storage constraints in the second quarter of the basis between NYMEX2020, and the indices upon which we sell our natural gas production. In the Delaware Basin, we experienced certain months during 2019 when the transportation, gathering and processing cost to deliver our natural gas to market exceeded the price we received. The realization percentages for our NGLs sales also decreased as compared to 2018, primarily due to reductionschanges in prices for the individual NGLs components for 2019 as compared to the same periods in 2018. As noted above, averagerevenue contracts.
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Commodity Price Risk Management
We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price swaps, collarsexchanges and basis protection swapsexchanges on a portion of our estimated crude oil and natural gas production. For our commodity swaps,exchanges, we ultimately realize the fixed price value related to the swaps.exchanges. See the footnote titled Note 6 - Commodity Derivative Financial Instruments to our accompanying consolidated financial statements in Item 8.Financial Statements and Supplementary Data included elsewhere in this report for a summary of our derivative positions as of December 31, 2019.2020.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, as well asand the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production.
Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward price curves and changes in certain differentials.
The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net:
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (in millions) | |||||||||||
| Commodity price risk management gain (loss), net: | |||||||||||
| Net settlements of commodity derivative instruments: | |||||||||||
| Crude oil fixed price swaps and collars | $ | (18.3 | ) | $ | (139.7 | ) | $ | (2.7 | ) | ||
| Crude oil basis protection swaps | — | 15.2 | — | ||||||||
| Natural gas fixed price swaps and collars | 8.8 | (7.0 | ) | 19.5 | |||||||
| Natural gas basis protection swaps | (8.1 | ) | 21.0 | 3.8 | |||||||
| NGLs fixed price swaps | — | (5.0 | ) | (7.3 | ) | ||||||
| Total net settlements of commodity derivative instruments | (17.6 | ) | (115.5 | ) | 13.3 | ||||||
| Change in fair value of unsettled commodity derivative instruments: | |||||||||||
| Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments | (81.1 | ) | 64.9 | 44.8 | |||||||
| Crude oil fixed price swaps, collars and rollfactors | (62.1 | ) | 197.0 | (77.9 | ) | ||||||
| Natural gas fixed price swaps and collars | 0.1 | 1.4 | 14.7 | ||||||||
| Natural gas basis protection swaps | (2.1 | ) | (2.6 | ) | 5.7 | ||||||
| NGLs fixed price swaps | — | — | (4.6 | ) | |||||||
| Net change in fair value of unsettled commodity derivative instruments | (145.2 | ) | 260.7 | (17.3 | ) | ||||||
| Total commodity price risk management gain (loss), net | $ | (162.8 | ) | $ | 145.2 | $ | (4.0 | ) | |||
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Commodity price risk management gain (loss), net: | |||||||||||||||||
| Net settlements of commodity derivative instruments: | |||||||||||||||||
| Crude oil collars and fixed price exchanges | $ | 294.4 | $ | (18.3) | $ | (139.7) | |||||||||||
| Crude oil basis protection exchanges | — | — | 15.2 | ||||||||||||||
| Natural gas collars and fixed price exchanges | (1.4) | 8.8 | (7.0) | ||||||||||||||
| Natural gas basis protection exchanges | (13.7) | (8.1) | 21.0 | ||||||||||||||
| NGLs fixed price exchanges | — | — | (5.0) | ||||||||||||||
| Total net settlements of commodity derivative instruments | 279.3 | (17.6) | (115.5) | ||||||||||||||
| Change in fair value of unsettled commodity derivative instruments: | |||||||||||||||||
| Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments | (19.9) | (81.1) | 64.9 | ||||||||||||||
| Crude oil collars and fixed price exchanges | (49.8) | (62.1) | 197.0 | ||||||||||||||
| Natural gas collars and fixed price exchanges | (7.8) | 0.1 | 1.4 | ||||||||||||||
| Natural gas basis protection exchanges | (21.5) | (2.1) | (2.6) | ||||||||||||||
| Net change in fair value of unsettled commodity derivative instruments | (99.0) | (145.2) | 260.7 | ||||||||||||||
| Total commodity price risk management gain (loss), net | $ | 180.3 | $ | (162.8) | $ | 145.2 | |||||||||||
Lease Operating Expenses
Lease operating expenses ("LOE") increased nineby 13 percent to $161.3 million in 2020 compared to $142.2 million in 2019 compared2019. The year-over-year increase in LOE is primarily attributable to $131.0 millionthe wells acquired from our SRC Acquisition in 2018,January 2020 and wells turned-in-line during 2020.Specifically, the increase was primarily due to wells turned-in-line during 2019. Significant changes$10.0 million in lease operating expenses included increasesadditional well services, an increase of $10.5$2.6 million related toin produced water disposal, expense, $4.7 related to additional compressor and equipment rental, $2.4a $2.7 million related to expense forincrease in non-operated wells, $2.1 million for payroll and employee benefits related to increases in headcount and $1.4 million related to chemical treatments.well expenses. The increases were partially offset by decreases of $6.3 million related to workover projects and $4.7 million related to midstream expense resulting from the sale of Delaware Basin midstream assetsoperational efficiencies achieved during the second quarter of 2019. Lease operating expense2020. LOE per Boe decreased by 1218 percent to $2.36 in 2020 from $2.88 forin 2019, from $3.26 for 2018.primarily due to a 38 percent increase in production volumes.
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Production Taxes
Production taxes which are comprised mainly of severance tax and ad valorem tax, and are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined bybased upon activity levels and relative commodity prices from year-to-year.prices.
Production taxes decreased 1126 percent to $59.4 million in 2020 compared to $80.8 million in 2019, compared to $90.4 million in 2018, primarily due to the six12 percent decrease in crude oil, natural gas and NGLs sales for 20192020 compared to 2018, refunds of ad valorem tax related to high-cost natural gas wells and a decrease2019, reductions in ad valoremeffective severance tax rates in the Wattenberg Field and well classifications in the Delaware Basin.Production taxes per Boe decreased 47 percent to $0.87 in 2020compared to $1.63in 2019 due to lower realized prices for crude oil, natural gas and NGLs and a 38 percent increase in production volumes between periods.
Transportation, Gathering and Processing Expenses
Transportation, gathering and processing expenses are primarily impacted by the volumes delivered through pipelines and for natural gas gathering and transportation operations. Transportation, gathering and processing expenses("TGP") increased 2468 percent to $77.8 million in 2020 compared to $46.4 million in 2019, primarily due to higher production volumes between periods as a result of the SRC Acquisition, as well as amendments to existing and new crude oil sales contracts, some of which resulted in a change in recognition from a net-back to a gross presentation of TGP.TGP per Boe increased to $1.14 for 2020 compared to $37.4 million in 2018,$0.94 for 2019. The increase of TGP per Boe between periods was primarily due to an increase in production. Transportation, gathering and processing expenses per Boe remained consistent at $0.94 for 2019 compared to $0.93 for 2018.TGP as discussed above, partially offset by an increase in production volume delivered.
Exploration, Geologic and Geophysical Expense
Impairment of Properties and Equipment
The following table sets forth the major components of our impairment of properties and equipment:
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (in millions) | |||||||||||
| Impairment of proved and unproved properties | $ | 10.6 | $ | 458.4 | $ | 285.5 | |||||
| Amortization of individually insignificant unproved properties | — | — | 0.4 | ||||||||
| Impairment of infrastructure and other | 27.9 | — | — | ||||||||
| Impairment of properties and equipment | $ | 38.5 | $ | 458.4 | $ | 285.9 | |||||
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Impairment of proved and unproved properties | $ | 881.2 | $ | 10.6 | $ | 458.4 | |||||||||||
| Impairment of infrastructure and other | 1.2 | 27.9 | — | ||||||||||||||
| Total impairment of properties and equipment | $ | 882.4 | $ | 38.5 | $ | 458.4 | |||||||||||
Impairment Charges. The significant decline in crude oil prices in the first quarter of 2020 was considered a triggering event that required us to assess our crude oil and 2018,natural gas properties for possible impairment. As a result of our assessment, we recorded impairment charges totaling $10.6of $881.1 million to our proved and $458.4unproved properties. Of these impairment charges, approximately $753.0 million respectively,was related to the divestiture of leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. We determinedproved properties. These impairment charges represented the fairamount by which the carrying value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. During 2019,properties exceeded the estimated fair value. The estimated fair value was determined based on estimated future discounted net cash flows. In addition to our proved property impairment, we also recorded impairmentsrecognized approximately $127.3 million of $27.9 million related to certain midstream facility infrastructureimpairment charges in the first quarter of 2020 for our unproved properties in the Delaware Basin. Upon closingThese impairment charges were recognized based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans. We did not recognize any significant impairment write-downs with respect to our proved and unproved properties during the Midstream Asset Divestitures, it was determined that theremainder of 2020. If crude oil prices decline, or we change other estimates impacting future net book value of these assets was not recoverable.cash flows (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas properties could be subject to additional impairments in future periods.
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General and Administrative Expense
General and administrative expense decreased five percentslightly to $161.1 million in 2020 compared to $161.8 million in 2019 compared2019. Transaction costs relating to $170.5 million in 2018. The decrease was primarily attributable to decreases of $17.9 million in legal-related fees and $8.2 million in government relations costs. The decreases were partially offset by increases ofthe SRC Acquisition increased from $7.8 million in costs related2019 to $19.9 million in 2020, and we also incurred $10.2 million of transition expenses relating to the SRC Acquisition,acquisition in 2020. However, these increases were offset by (i) the non-recurrence of certain 2019 expenses including $6.0 million related to shareholder activism, $5.5 million in consultant fees related to business management and ERP implementation and a $3.4 million for the allowance adjustment for royalty owner payments and $1.0(ii) a $6.6 million in payroll and related benefits.decrease relating to ongoing corporate cost savings initiatives.
Depreciation, Depletion and Amortization
Crude oil and natural gas properties. During 20192020 and 2018,2019, we invested $522.3 million and $787.7 million, and $982.7 million,respectively, exclusive of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties, respectively.properties. DD&ADepreciation, depletion and amortization expense ("DD&A")related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $611.0 million and $638.5 million $551.3 millionin 2020 and $462.5 million in 2019, 2018 and 2017, respectively.
The year-over-year change in DD&A expense for 20192020 compared to 20182019 related to crude oil and natural gas properties was primarily due to the following:
| Year Ended December 31, | ||||||||||||||
| 2020 | ||||||||||||||
| (in millions) | ||||||||||||||
| Increase in production | $ | 220.1 | ||||||||||||
| Decrease in weighted-average depreciation, depletion and amortization rates | (247.6) | |||||||||||||
| Total decrease in DD&A expense related to crude oil and natural gas properties | $ | (27.5) | ||||||||||||
| Year Ended December 31, | ||||
| 2019 | ||||
| (in millions) | ||||
| Increase in production | $ | 128.9 | ||
| Decrease in weighted-average depreciation, depletion and amortization rates | (41.7 | ) | ||
| Total increase in DD&A expense related to crude oil and natural gas properties | $ | 87.2 | ||
The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties:
| Year Ended December 31, | ||||||||||||||||||||
| Operating Region/Area | 2020 | 2019 | 2018 | |||||||||||||||||
| (per Boe) | ||||||||||||||||||||
| Wattenberg Field | $ | 8.80 | $ | 11.77 | $ | 12.58 | ||||||||||||||
| Delaware Basin | 9.68 | 16.76 | 17.70 | |||||||||||||||||
| Total weighted-average | 8.94 | 12.92 | 13.73 | |||||||||||||||||
| Year Ended December 31, | ||||||||||||
| Operating Region/Area | 2019 | 2018 | 2017 | |||||||||
| (per Boe) | ||||||||||||
| Wattenberg Field | $ | 11.82 | $ | 12.58 | $ | 14.67 | ||||||
| Delaware Basin | 16.87 | 17.70 | 14.89 | |||||||||
| Total weighted-average | 13.04 | 13.73 | 14.53 | |||||||||
The decrease in DD&A expense rate in the Wattenberg Field was primarily due to the SRC Acquisition, which added 295 MMBoe in total proved reserves, offset by a $1.6 billion increase in our cost basis.
Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $8.7 million for the year ended December 31, 2020, compared to $5.7 million for the year ended December 31, 2019. The increase in depreciation expense between periods was primarily due to our new ERP system which was implemented at the beginning of 2020.
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Interest Expense, net
Interest expense, net increased by $0.4$17.6 million to $71.2$88.7 million in 20192020 compared to $70.7$71.1 million in 2018.2019. The increase was primarily related to a $4.2$9.2 million increase in interest expense related to our revolving credit facility partiallyas a result of higher borrowings between periods, a $9.2 million increase related to the assumption of the SRC Senior Notes and a $2.5 million increase related to the issuance of an additional $150 million aggregate principal amount of the 2026 Senior Notes in September 2020. Higher credit facility borrowings in 2020 were primarily due to our payment and termination of SRC's revolving credit facility as well as the partial redemption of the SRC Senior Notes in the first quarter of 2020. The increases in interest expense were offset by a $4.1$6.3 million increase in capitalized interest.interest in 2020 as compared to 2019.
Provision for Income Taxes
The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the
periods in which those temporary differences become deductible. At each reporting period, management considers the
scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future
taxable income in making this assessment. As previously noted, we recorded impairments totaling $882.4 million in 2020. These impairments resulted in three years of cumulative historical pre-tax losses and a net deferred tax asset position. The impairment losses were a key consideration that led us to continue to provide a valuation allowance for stateagainst our net deferred tax attributes, stock compensation detriments and nondeductible expensesassets as of December 31, 2020 since we cannot conclude that consist primarily of officers' compensation, acquisition costs and government lobbying expenses.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors resultingimpacting net losses of $724.3 million and $56.7 million in changes in net income (loss) in2020 and 2019, and 2018respectively, are discussed above. These same reasons similarly impacted adjusted
Adjusted net income (loss),loss, a non-U.S. GAAP financial measure, withwas $625.3 million and for the year ended December 31, 2020 and adjusted net income, a non-U.S. GAAP financial measure, was $53.3 million for the year ended December 31, 2019. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted for taxes, of $110.0 million and $198.3 million in 2019 and 2018, respectively. Adjusted net income was $53.3 million in 2019 and adjusted net loss was $196.3 million in 2018.(loss). 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.
Financial Condition, Liquidity and Capital Resources
Our primary sources of liquidity are cash flows from operating activities, borrowings from our revolving credit facility, asset sales and proceeds raised in debt and equity capital market transactions and asset sales.transactions. In 2019,2020, our net cash flows from operating activities were $858.2$870.1 million.
Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile, and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production.
We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions and for general corporate purposes. We maintain a significant capital investment program to execute our
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development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells.
From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 20192020 is an indication of a lack of liquidity. We had working capital deficits of $57.2$471.6 million and $166.6$57.2 million at December 31, 2020 and 2019, respectively. The increase was primarily attributable to our 2021 Convertible Notes maturing in September 2021, which resulted in the notes being classified in current liabilities, an increase in the fair value liability of our commodity derivatives and December 31, 2018, respectively.additional current liabilities resulting from the SRC Acquisition. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time.
Our cash and cash equivalents were $1.0$2.6 million at December 31, 20192020 and availability under our revolving credit facility was $1.3$1.4 billion, providing for total liquidity of $1.3$1.4 billion as of December 31, 2019.2020. In October 2019,2020, as part of our semi-annual redetermination, the borrowing base onof our revolving credit facility was reaffirmed atreduced from $1.7 billion to $1.6 billion, with a corresponding reduction of our elected commitment level to $1.6 billion. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and we elected to retain our commitment amount at $1.3 billion.natural gas interests. Based on our current production forecast for 20202021 and assumed average NYMEX prices of $52.50$45.00 per Bbl of crude oil and $2.00$2.50 per Mcf of natural gas and an assumed average composite price of $11.00$12.00 per Bbl for NGLs, we expect 2020 adjusted2021 cash flows from operations a non-U.S. GAAP financial measure, to exceed our capital investments in crude oil and natural gas properties by approximately $250 million.
As a result of merging with SRC, we assumed the SRC Senior Notes and paid off and terminated SRC's revolving credit facility.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. We funded the repurchase with proceeds from our revolving credit facility. An aggregate principal amount of approximately $102.3 million of the SRC Senior Notes remains outstanding.
In September 2020, we issued an additional $150.0 million principal amount of our 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 April 2019, the Boardour board of directors approved the acquisition of up to $200 million of our outstanding common stock, depending on market conditions. Pursuant to the Stock Repurchase Program, we repurchased 4.7 million shares of outstanding common stock at a cost of $154.4 million during 2019. Subsequent to December 31, 2019, we repurchased approximately 0.6 million shares of our outstanding common stock at a cost of $12.5 million. Additionally, in August 2019, contingent onProgram. Effective with the closing of the SRC Acquisition, our Boardboard of directors approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million with a target completion date of December 31, 2021. As of February 24, 2020, $358.2 million of our outstanding common stock remained available for repurchase under the Stock Repurchase Program.
In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open markets at our discretion and in compliance with safe harbor provisions, or inmarket purchases, privately negotiated transactions. The Stock Repurchase Program does not requiretransactions or otherwise. Such repurchases or exchanges, if any, specific number of shares to be acquired,will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our revolving credit agreement and can be modified or discontinued by the Board at any time.other factors.
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 maturing in September 2021 and to fund our planned activities through the 12-month period following the filing of this report.
Our revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. In August 2019, we entered into a First Amendment to the Restated Credit Agreement. The First Amendment primarily modifies certain sections of the Restated Credit Agreement to permit the consummation of the SRC Acquisition and provides for certain borrowings in connection with the SRC Acquisition.
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The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (i)(a) maintain a minimum current ratio of 1.0:1.0 and (ii)(b) not exceed a maximum leverage ratio of 4.0:1.0. For purposes of the current ratio covenant, the revolving credit facility's definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, among other things, unused commitments under the revolving credit facility.Additionally, the current ratio covenant calculation allows us to exclude the current portion of our long-term debt and other short-term loans from the U.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit under U.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. At December 31, 2019,2020, we were in compliance with all covenants in the revolving credit facility with a current ratio of 4.4:3.5:1.0 and a leverage ratio of 1.4:1.7:1.0. We expect to remain in compliance throughout the 12-month period following the filing of this report.
Cash Flows
Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities decreasedincreased by $31.1$11.9 million to $870.1 million in 2020 as compared to $858.2 million in 2019 as compared to $889.3 million in 2018,2019. The increase between periods was primarily due to an increase in commodity derivative settlements and $82.0 million received in June 2020 from the divestiture of certain midstream assets in 2019. The increases were partially offset by a decrease in crude oil, natural gas and NGLs sales of $82.7 million and a $84.3 million net decrease in changes in assets and liabilities of $48.1 million, primarily attributable to $95.5 million in deferred midstream gathering credits related to our Midstream Asset Divestitures. These changes were partially offset by an increase in commodity derivative settlements of $97.9 million.working capital.
Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $17.0$96.2 million in 20192020 to $921.6 million from $825.4 million from $808.4 million in 2018.2019. The increase was primarily due to the factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. FreeAdjusted free cash flow, a non-U.S GAAP financial measure, increased by $212.0$361.6 million in 20192020 to $399.3 million from $37.7 million from a free cash flow deficit of $174.3 million in 2018.2019. The increase was primarily due to the increase in adjusted cash flows from operations, combined with a decrease in capital investments in crude oil and natural gas properties.
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.
Investing Activities. BecauseAs crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our crude oil and natural reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments.
Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $687.2 million during 2020 was primarily related to our drilling and completion activities of $551.0 million and $139.8 million related to the closing of the SRC Acquisition.
Net cash used in investing activities of $677.8 million during 2019 was primarily related to our drilling and completion activities of $855.9 million. Partially offsetting these investing activities was $202.1 million of net cash received from the Midstream Asset Divestituresdivestitures of certain midstream assets and certain Delaware Basin crude oil and natural gas properties of $199.4 million. Net cash used in investing activities of $1.1 billion during 2018 was primarily related to cash utilized toward property acquisitions of $180.0 million and our drilling and completion activities of $946.4 million. Partially offsetting these investments was the receipt of approximately $43.5 million, primarily related to the sale of our Utica Shale assets in March 2018.properties.
Financing Activities. Net cash used in financing activities in 2020 of $181.3 million was primarily due to the redemption of a portion of the 2025 Senior Notes totaling $452.2 million, the repurchase and retirement of shares of our common stock totaling $23.8 million pursuant to the Stock Repurchase Program and $9.3 million related to purchases of our stock for employee stock-based compensation tax withholding obligations. These financing cash outflows were financed by our net borrowings from our credit facility of $164 million, proceeds from the issuance of 2026 Senior Notes of $148.5 million and cash flows from operating activities.
Net cash used in financing activities in 2019 of $188.9 million was primarily due to the repurchase and retirement of shares of our common stock totaling $154.4 million pursuant to the Stock Repurchase Program, net borrowings from our credit facility of $28.5 million and $4.0 million related to purchases of our stock for employee stock-based compensation tax withholding obligations.
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Subsidiary Guarantor
PDC Permian, Inc., a Delaware corporation (the “Guarantor”), our wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes, 2025 Senior Notes and 2026 Senior Notes (collectively, the "Senior Notes") and our 2021 Convertible Notes. The Guarantor holds our assets located in 2018the Delaware Basin. The Senior Notes and 2021 Convertible Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantees are subject to release in limited circumstances only upon the occurrence of $18.1 million was comprisedcertain customary conditions.
The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of net borrowings from our restricted subsidiaries to: (a) incur additional debt including under our revolving credit facility, of $32.5 million, partially offset by $7.7 million of debt issuance costs and $5.1 million related to purchases(b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our stock.restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company.
| As of/Year Ended December 31, | ||||||||||||||||||||||||||
| 2020 | 2019 | |||||||||||||||||||||||||
| Issuer | Guarantor | Issuer | Guarantor | |||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||
| Current assets | $ | 271.4 | $ | (57.8) | $ | 175.8 | $ | 126.0 | ||||||||||||||||||
| Intercompany accounts receivable, guarantor subsidiary | 107.3 | — | 348.8 | — | ||||||||||||||||||||||
| Intercompany accounts receivable, non-guarantor subsidiary | — | — | 6.3 | — | ||||||||||||||||||||||
| Investment in guarantor subsidiary | 1,767.2 | — | 1,766.8 | — | ||||||||||||||||||||||
| Properties and equipment, net | 3,982.1 | 877.1 | 2,328.3 | 1,766.9 | ||||||||||||||||||||||
| Other non-current assets | 56.6 | 4.3 | 41.8 | 6.8 | ||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||
| Current liabilities | $ | 751.3 | $ | 28.5 | $ | 306.6 | $ | 52.4 | ||||||||||||||||||
| Intercompany accounts payable | — | 94.2 | — | 348.8 | ||||||||||||||||||||||
| Long-term debt | 1,409.5 | — | 1,177.2 | — | ||||||||||||||||||||||
| Other non-current liabilities | 254.9 | 178.1 | 361.1 | 211.6 | ||||||||||||||||||||||
| Statement of Operations | ||||||||||||||||||||||||||
| Crude oil, natural gas and NGLs sales | $ | 968.8 | $ | 183.7 | $ | 999.3 | $ | 308.0 | ||||||||||||||||||
| Commodity price risk management gain (loss), net | 180.3 | — | (162.8) | — | ||||||||||||||||||||||
| Total revenues | 1,151.5 | 182.5 | 838.1 | 308.7 | ||||||||||||||||||||||
| Production costs | 227.0 | 71.6 | 180.1 | 89.2 | ||||||||||||||||||||||
| Gross profit | 741.8 | 112.1 | 819.2 | 218.8 | ||||||||||||||||||||||
| Impairment of properties and equipment | 2.0 | 880.4 | 0.3 | 38.2 | ||||||||||||||||||||||
| Net income (loss) | (49.2) | (670.0) | (24.6) | (30.0) | ||||||||||||||||||||||
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Contractual Obligations and Contingent Commitments
The following table presents our contractual obligations and contingent commitments as of December 31, 2019:
| Payments due by period | ||||||||||||||||||||
| Less than | 1-3 | 3-5 | ||||||||||||||||||
| Contractual Obligations and Contingent Commitments | Total | 1 year | years | years | Thereafter | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Long-term liabilities reflected on the consolidated balance sheet (1) | ||||||||||||||||||||
| Long-term debt (2) | $ | 1,204 | $ | — | $ | 200 | $ | 404 | $ | 600 | ||||||||||
| Commodity derivative contracts (3) | 4 | 3 | 1 | — | — | |||||||||||||||
| Production tax liability | 144 | 76 | 68 | — | — | |||||||||||||||
| Deferred oil gathering credit | 20 | 2 | 5 | 4 | 9 | |||||||||||||||
| Deferred midstream gathering credits | 176 | 7 | 23 | 29 | 117 | |||||||||||||||
| Asset retirement obligations | 127 | 32 | 30 | 30 | 35 | |||||||||||||||
| Operating and finance leases | 22 | 6 | 11 | 3 | 2 | |||||||||||||||
| Other liabilities (4) | 4 | — | 2 | 1 | 1 | |||||||||||||||
| 1,701 | 126 | 340 | 471 | 764 | ||||||||||||||||
| Commitments, contingencies and other arrangements (5) | ||||||||||||||||||||
| Interest on long-term debt (6) | 386 | 67 | 130 | 120 | 69 | |||||||||||||||
| Firm transportation and processing agreements (7) | 581 | 85 | 207 | 147 | 142 | |||||||||||||||
| 967 | 152 | 337 | 267 | 211 | ||||||||||||||||
| Total | $ | 2,668 | $ | 278 | $ | 677 | $ | 738 | $ | 975 | ||||||||||
| Payments due by period | ||||||||||||||||||||||||||||||||
| Less than | 1-3 | 3-5 | ||||||||||||||||||||||||||||||
| Contractual Obligations and Contingent Commitments | Total | 1 year | years | years | Thereafter | |||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||
| Long-term liabilities reflected on the consolidated balance sheet | ||||||||||||||||||||||||||||||||
Long-term debt (1) | $ | 1,620.3 | $ | 200.0 | $ | 168.0 | $ | 502.3 | $ | 750.0 | ||||||||||||||||||||||
Commodity derivative contracts (2) | 134.6 | 98.2 | 36.4 | — | — | |||||||||||||||||||||||||||
| Production tax liability | 190.1 | 124.5 | 65.6 | — | — | |||||||||||||||||||||||||||
| Deferred oil gathering credit | 18.1 | 2.2 | 4.5 | 4.5 | 6.9 | |||||||||||||||||||||||||||
| Deferred midstream gathering credits | 168.7 | 9.4 | 18.9 | 18.8 | 121.6 | |||||||||||||||||||||||||||
| Asset retirement obligations | 166.6 | 33.9 | 37.5 | 37.5 | 57.7 | |||||||||||||||||||||||||||
| Operating and finance leases | 20.1 | 8.6 | 8.7 | 2.1 | 0.7 | |||||||||||||||||||||||||||
Other liabilities (3) | 1.2 | 0.1 | 0.2 | 0.2 | 0.7 | |||||||||||||||||||||||||||
| 2,319.7 | 476.9 | 339.8 | 565.4 | 937.6 | ||||||||||||||||||||||||||||
Commitments, contingencies and other arrangements (4) | ||||||||||||||||||||||||||||||||
Interest on long-term debt (5) | 420.3 | 88.5 | 165.2 | 123.5 | 43.1 | |||||||||||||||||||||||||||
Firm transportation and processing agreements (6) | 516.8 | 135.4 | 209.6 | 124.3 | 47.5 | |||||||||||||||||||||||||||
| 937.1 | 223.9 | 374.8 | 247.8 | 90.6 | ||||||||||||||||||||||||||||
| Total | $ | 3,256.8 | $ | 700.8 | $ | 714.6 | $ | 813.2 | $ | 1,028.2 | ||||||||||||||||||||||
____________
(1)Amount presented does not agree with the consolidated balance sheets as it excludes $6.8 million of unamortized net debt discounts and premium and $10.9 million of unamortized debt issuance costs.
(2)Represents our gross liability related to the fair value of commodity derivative positions.
(3)Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.
(4)Excludes termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
(5)Amounts presented include $258.8 million to the holders of our 2026 Senior Notes, $98.0 million to the holders of our 2024 Senior Notes, $32.0 million to holders of our 2025 Senior Notes and $2.2 million payable to the holders of our 2021 Convertible Notes. Amounts also include $29.3 million commitment fees due which, as of December 31, 2020, includes a commitment equal to 0.375 percent per annum of the unused portion of the borrowing base of the Company's revolving credit facility. At December 31, 2020, we had variable-rate debt outstanding under our credit facility of $168.0 million.
(6)Represents our gross commitment which includes volumes produced by us and purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf.
From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. Information regarding our legal proceedings can be found in the footnote titled Note 12 - Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data included elsewhere in this report.
Off-Balance Sheet Arrangements
At December 31, 2019,2020, we had no off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital investments or capital resources.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. We analyze and base our estimates on historical experience and various other assumptions that we believe to be
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reasonable under the circumstances. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Our significant accounting policies are described in Note 2 - Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the presentation of our financial position and results of operations and we may use significant judgment in their application. As a result, they are subject to an inherent degree of uncertainty. In
Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. CostsUnder this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depleted onIn determining the unit-of-production method based on estimated proved reserves.
Further, under the successful efforts method, exploration costs, including geological and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are expensed as incurred. Exploratory well drilling costs, including the cost of all our propertiesstratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. This accounting method may yield significantly different results than the full cost method of accounting. Judgment is required to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of costs incurred.
The successful efforts method inherently relies on a well-by-well basis asthe estimation of December 31. We adjust ourproved crude oil, and natural gas reservesand NGL reserves. Reserve quantities and the related estimates of future net cash flows are used as inputs in our calculation of depletion, evaluation of proved properties for major acquisitions, new drillingimpairment, assessment of expected realizability of our deferred income tax assets and divestitures duringcalculation of the year as needed.standardized measure of discounted future net cash flows. 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. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs and historical commodity prices. 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. Although every reasonable effort is made to ensure thatWe cannot predict the amounts or timing of such future revisions.
Our reserves estimate has been prepared by our internal and external engineers. For more information regarding reserve estimates reported represent our most accurate assessments possible, the subjective decisionsestimation, including historical reserve revisions, see Items 1 and variances in available data for various properties increase the likelihood2. Business and Properties - Preparation of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net earnings.
Annually, or upon a triggering event, we are unable to make a final determination aboutassess the productive status of a well prior to issuance of the financial statements, the well is classified as a "suspended well" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is applied.
Future commodity prices are estimated future cash flows. Any impairmentby using a combination of assumptions management uses in value is charged to impairment of propertiesits budgeting and equipment. The estimates offorecasting process, historical and future prices may differ from current market prices of crude oiladjusted for geographical location and natural gas. Anyquality differentials, as well as other factors that management believes will impact realizable prices. In the event that there are downward revisions in estimates to our reserveestimated reserves quantities, expectations of falling commodity prices significantly decline or rising operating costs, could result in a triggering event,management would test the recoverability of the carrying value of our oil and therefore, a reduction in undiscounted future net cash flowsgas properties and, if necessary, record an impairment charge. Fair value is calculated by discounting the future cash flows. The discount factor used is the market based weighted average cost of ourcapital which is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas properties. gas.
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Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by their nature, highly uncertain and may vary significantly from actual results.
Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. Unproved properties with individually significant acquisition costs are periodically assessed for impairment based on remaining average lease terms, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense.
Impairment charges would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment charge is recorded.
Asset Retirement Obligations. Crude Oil, Natural GasThe majority of our asset retirement obligations ("ARO") relate to the plugging and NGLs Sales Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred controlabandonment of crude oil naturaland gas or NGLs productionwells. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. The recognition of an asset retirement obligation requires management to make assumptions that include estimated plugging and abandonment costs, timing of settlements, inflation rates and discount rate. Over time, the purchaser. We considerliability is accreted for the
Valuation of Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust ourfor crude oil, natural gas and NGLs salesNGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in subsequent periods based onfuture periods. We have not elected to designate any of our derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the data received fromfair value of our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual salesderivative instruments are recorded one to two months later. Historically, these differences have not been material.
Our financial condition, results of our credit standing on the fair value of commodity derivative liabilitiesoperations and the effect of our counterparties' credit standings on the fair value of commodity derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding commodity derivative position.
Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwardscarryforwards and credit carry-forwardscarryforwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax assetWe must periodically evaluate whether it is more likely than not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value ofthese deferred income tax assets involve judgments and estimatesestablish a valuation allowance for those that do not meet the more likely than not threshold. When assessing the need for a valuation allowance, we primarily consider future reversals of bothexisting taxable temporary differences. To a lesser extent, we may also consider future taxable income exclusive of reversing temporary differences and carryfowards, and tax planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryforwards. The ultimate amount and timing. The judgments used in applying these policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differdeferred tax assets realized could be materially different from those estimates.recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets.
and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. TheTherefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. As the allocation of the purchase price allocations are based on appraisals, discountedis subject to significant estimates, the accuracy of this assessment is inherently uncertain.
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In estimating the fair values of assets acquired and liabilities assumed the most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows quoted marketto a single discounted amount. 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 estimates by management. When appropriate,a market based weighted average cost of capital rate. Additionally, for acquisitions with significant unproved properties, we may also review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties.
If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value.
Acreage Exchanges. From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement. We estimate the fair value of proved crude oil and natural gas properties utilizing the same valuation techniques, significant inputs and assumptions as previously described.
Recent Accounting StandardsPronouncements
See the footnote titled Note 2 - Summary of Significant Accounting Policies - Recently Adopted Accounting Standards to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data included elsewhere in this report.
Reconciliation of Non-U.S. GAAP Financial Measures
We use "adjusted cash flows from operations," "free"adjusted free cash flow (deficit)," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.
Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities
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and to return capital to stockholders.stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure.
We are unable to present a reconciliation of forward-looking freeadjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly
comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of freeadjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations in excess of capital investments in crude oil and natural gas properties.operations.
Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance.
Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, and acquisitions and to service our debt obligations.
Beginning in the third quarter of 2019, we included a reconciling item for gains or losses on the sale of properties and equipment when calculating adjusted EBITDAX, thereby no longer including such gains or losses in our reported adjusted EBITDAX. We believe this methodology for calculating adjusted EBITDAX will enable greater comparability to our peers, as well as consistent treatment of adjustments for impairment and gains or losses on the sale of properties and equipment. For comparability, all prior periods presented have been conformed to the aforementioned methodology.
PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves.
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The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (thousands) | |||||||||||||||||
| Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow (deficit): | |||||||||||||||||
| Net cash from operating activities | $ | 870.1 | $ | 858.2 | $ | 889.3 | |||||||||||
| Changes in assets and liabilities | 51.5 | (32.8) | (80.9) | ||||||||||||||
| Adjusted cash flows from operations | 921.6 | 825.4 | 808.4 | ||||||||||||||
| Capital expenditures for development of crude oil and natural gas properties | (551.0) | (855.9) | (946.4) | ||||||||||||||
| Change in accounts payable related to capital expenditures for oil and gas development activities | 28.7 | 68.2 | (36.3) | ||||||||||||||
| Adjusted free cash flow (deficit) | $ | 399.3 | $ | 37.7 | $ | (174.3) | |||||||||||
| Net income (loss) to adjusted net income (loss): | |||||||||||||||||
| Net income (loss) | $ | (724.3) | $ | (56.7) | $ | 2.0 | |||||||||||
| Loss (gain) on commodity derivative instruments | (180.3) | 162.8 | (145.2) | ||||||||||||||
| Net settlements on commodity derivative instruments | 279.3 | (17.6) | (115.5) | ||||||||||||||
Tax effect of above adjustments (1) | — | (35.2) | 62.4 | ||||||||||||||
| Adjusted net income (loss) | $ | (625.3) | $ | 53.3 | $ | (196.3) | |||||||||||
| Net income (loss) to adjusted EBITDAX: | |||||||||||||||||
| Net income (loss) | $ | (724.3) | $ | (56.7) | $ | 2.0 | |||||||||||
| Loss (gain) on commodity derivative instruments | (180.3) | 162.8 | (145.2) | ||||||||||||||
| Net settlements on commodity derivative instruments | 279.3 | (17.6) | (115.5) | ||||||||||||||
| Non-cash stock-based compensation | 22.2 | 23.8 | 21.8 | ||||||||||||||
| Interest expense, net | 88.7 | 71.1 | 70.3 | ||||||||||||||
| Income tax expense (benefit) | (7.9) | (3.3) | 5.4 | ||||||||||||||
| Impairment of properties and equipment | 882.4 | 38.5 | 458.4 | ||||||||||||||
| Exploration, geologic and geophysical expense | 1.4 | 4.1 | 6.2 | ||||||||||||||
| Depreciation, depletion and amortization | 619.7 | 644.2 | 559.8 | ||||||||||||||
| Accretion of asset retirement obligations | 10.1 | 6.1 | 5.1 | ||||||||||||||
| Loss (gain) on sale of properties and equipment | (0.7) | 9.7 | 0.4 | ||||||||||||||
| Adjusted EBITDAX | $ | 990.6 | $ | 882.7 | $ | 868.7 | |||||||||||
| Cash from operating activities to adjusted EBITDAX: | |||||||||||||||||
| Net cash from operating activities | $ | 870.1 | $ | 858.2 | $ | 889.3 | |||||||||||
| Interest expense, net | 88.7 | 71.1 | 70.3 | ||||||||||||||
| Amortization and write-off of debt discount, premium and issuance costs | (16.8) | (13.6) | (12.8) | ||||||||||||||
| Exploration, geologic and geophysical expense | 1.4 | 4.1 | 6.2 | ||||||||||||||
| Other | (4.3) | (4.3) | (3.4) | ||||||||||||||
| Changes in assets and liabilities | 51.5 | (32.8) | (80.9) | ||||||||||||||
| Adjusted EBITDAX | $ | 990.6 | $ | 882.7 | $ | 868.7 | |||||||||||
| PV-10: | |||||||||||||||||
| Standardized measure of discounted future net cash flows | $ | 3,282.2 | $ | 3,310.3 | $ | 4,447.7 | |||||||||||
| Present value of estimated future income tax discounted at 10% | 172.4 | 526.7 | 873.6 | ||||||||||||||
| PV-10 | $ | 3,454.6 | $ | 3,837.0 | $ | 5,321.3 | |||||||||||
_____________
(1)Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the year ended December 31, 2020.
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| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| (in millions) | |||||||||||
| Cash flows from operations to adjusted cash flows from operations and free cash flow (deficit): | |||||||||||
| Net cash from operating activities | $ | 858.2 | $ | 889.3 | $ | 597.8 | |||||
| Changes in assets and liabilities | (32.8 | ) | (80.9 | ) | (15.7 | ) | |||||
| Adjusted cash flows from operations | 825.4 | 808.4 | 582.1 | ||||||||
| Capital expenditures for development of crude oil and natural gas properties | (855.9 | ) | (946.4 | ) | (737.2 | ) | |||||
| Change in accounts payable related to capital expenditures | 68.2 | (36.3 | ) | (50.8 | ) | ||||||
| Free cash flow (deficit) | $ | 37.7 | $ | (174.3 | ) | $ | (205.9 | ) | |||
| Net income (loss) to adjusted net income (loss): | |||||||||||
| Net income (loss) | $ | (56.7 | ) | 2.0 | $ | (127.5 | ) | ||||
| (Gain) loss on commodity derivative instruments | 162.8 | (145.2 | ) | 3.9 | |||||||
| Net settlements on commodity derivative instruments | (17.6 | ) | (115.5 | ) | 13.3 | ||||||
| Tax effect of above adjustments | (35.2 | ) | 62.4 | (4.1 | ) | ||||||
| Adjusted net income (loss) | $ | 53.3 | $ | (196.3 | ) | $ | (114.4 | ) | |||
| Net income (loss) to adjusted EBITDAX: | |||||||||||
| Net income (loss) | $ | (56.7 | ) | $ | 2.0 | $ | (127.5 | ) | |||
| (Gain) loss on commodity derivative instruments | 162.8 | (145.2 | ) | 3.9 | |||||||
| Net settlements on commodity derivative instruments | (17.6 | ) | (115.5 | ) | 13.3 | ||||||
| Non-cash stock-based compensation | 23.8 | 21.8 | 19.4 | ||||||||
| Interest expense, net | 71.1 | 70.3 | 76.4 | ||||||||
| Income tax expense (benefit) | (3.3 | ) | 5.4 | (211.9 | ) | ||||||
| Impairment of properties and equipment | 38.5 | 458.4 | 285.9 | ||||||||
| Impairment of goodwill | — | — | 75.1 | ||||||||
| Exploration, geologic and geophysical expense | 4.1 | 6.2 | 47.3 | ||||||||
| Depreciation, depletion and amortization | 644.2 | 559.8 | 469.1 | ||||||||
| Accretion of asset retirement obligations | 6.1 | 5.1 | 6.4 | ||||||||
| Loss on extinguishment of debt | — | — | 24.7 | ||||||||
| (Gain) loss on sale of properties and equipment | 9.7 | 0.4 | (0.7 | ) | |||||||
| Adjusted EBITDAX | $ | 882.7 | $ | 868.7 | $ | 681.4 | |||||
| Cash from operating activities to adjusted EBITDAX: | |||||||||||
| Net cash from operating activities | $ | 858.2 | $ | 889.3 | $ | 597.8 | |||||
| Interest expense, net | 71.1 | 70.3 | 76.4 | ||||||||
| Amortization of debt discount and issuance costs | (13.6 | ) | (12.8 | ) | (12.9 | ) | |||||
| Exploration, geologic and geophysical expense | 4.1 | 6.2 | 47.3 | ||||||||
| Exploratory dry hole expense | — | (0.1 | ) | (41.3 | ) | ||||||
| Other | (4.3 | ) | (3.3 | ) | 29.8 | ||||||
| Changes in assets and liabilities | (32.8 | ) | (80.9 | ) | (15.7 | ) | |||||
| Adjusted EBITDAX | $ | 882.7 | $ | 868.7 | $ | 681.4 | |||||
| PV-10: | |||||||||||
| PV-10 | $ | 3,837.0 | $ | 5,321.3 | $ | 3,212.0 | |||||
| Present value of estimated future income tax discounted at 10% | (526.7 | ) | (873.6 | ) | (331.9 | ) | |||||
| Standardized measure of discounted future net cash flows | $ | 3,310.3 | $ | 4,447.7 | $ | 2,880.1 | |||||
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market-Sensitive Instruments and Risk Management
We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.
Interest Rate Risk
Changes in interest rates affect the amount of interest we earn on our interest bearing cash, and cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes, 2025 Senior Notes and 2026 Senior Notes have fixed rates, and therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.
As of December 31, 2019, our interest-bearing deposit accounts included money market accounts and checking accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2019 was $0.4 million, with a weighted-average interest rate of one percent. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2019 and assuming2020, we had $0.4$168.0 million outstanding throughout the period, we estimate that a one percent increase in interest rates would not have a material impact on interest income for the twelve months ended December 31, 2019.
Commodity Price Risk
We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis and NGLs. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas and propane prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives.
| Year Ended December 31, | |||||||
| 2019 | 2018 | ||||||
| Average NYMEX Index Price: | |||||||
| Crude oil (per Bbl) | |||||||
| NYMEX | $ | 57.03 | $ | 64.77 | |||
| Natural gas (per MMBtu) | |||||||
| NYMEX | $ | 2.63 | $ | 3.09 | |||
| Average Sales Price Realized: | |||||||
| Excluding net settlements on commodity derivatives | |||||||
| Crude oil (per Bbl) | $ | 53.26 | $ | 61.19 | |||
| Natural gas (per Mcf) | 1.30 | 1.85 | |||||
| NGLs (per Bbl) | 12.41 | 22.14 | |||||
Based on a sensitivity analysis as of December 31, 2019,2020, we estimate that a 10 percent increase in natural gas, crude oil prices and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in a decrease in the fair value of our net derivative positionsassets of $49.7$83.2 million, whereas a 10 percent decrease in prices would have resulted in an increase in fair value of $50.1our net derivatives assets of $80.9 million. The potential decrease in the fair value of our net derivative assets would be recorded in statements of operations as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties.exposure. When exposed to significant credit risk, we analyze the counterparties’counterparty's financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure financial performance by our counterparties.
We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. See the footnote titled Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments.
Our crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
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Disclosure of Limitations
Because the information above included only those exposures that existed at December 31, 2019,2020, it does not consider those exposures or positions which could arise after that date. OurAs a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information | ||||||||
| Financial Statements: | ||||||||
| Supplemental Information - Unaudited: | ||||||||
| Financial Statement Schedule: | ||||||||
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of PDC Energy, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 20192020 and 2018,2019, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019,2020, including the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019,2020, based on criteria established in Internal Control - Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2020, based on criteria established in Internal Control - Integrated Framework(2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 210 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and
65
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Proved Oil and Natural Gas Reserves on Proved Crude Oil and Natural Gas Properties, Net
As described in Notes 2 and 7 to the consolidated financial statements, the Company’s proved crude oil and natural gas properties balance was $7,524 million as of December 31, 2020, and depreciation, depletion, and amortization (DD&A) expense for the period ended December 31, 2020 was $619.7 million. As disclosed by management, 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. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs and historical commodity prices. 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. The Company accounts for crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. Reserve estimates are prepared by internal and external engineers (collectively “specialists”).
The principal considerations for our determination that performing procedures relating to the impact of proved crude oil and natural gas reserves on proved crude oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved crude oil and natural gas reserves related to reserves volumes and the assumptions applied to the data related to future operating and development costs, and commodity prices.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil and natural gas reserves. The work of specialists was used in performing the procedures to evaluate the reasonableness of the reserve volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ results. These procedures also included, among others, testing the completeness and accuracy of data related to reserves volumes, future operating and development costs, and commodity prices. Additionally, these procedures included evaluating whether the assumptions applied to the aforementioned data were reasonable considering the past performance of the Company.
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Valuation of Proved Crude Oil and Natural Gas Properties
As described in Notes 2, 3, and 87 to the consolidated financial statements, as of December 31, 20192020, the Company’s proved crude oil and natural gas properties were approximately $6,241.8 million. Upon$7,524 million, which includes impairment charges of $753.0 million to write-down proved properties to their estimated fair value and $1,614 million related to a merger completed during the year. Annually, or upon a triggering event, or at least annually, the Company assesses the valuation of its proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based uponand prices at which the Company estimates the commodity will be sold. If net capitalized costscarrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future discounted cash flows analysis. The impairment recorded is the amount by which the carrying values exceed the fair value. In the impairment assessment and as part of acquisition accounting, management estimates the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. 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 estimated future cash flows. Management utilizes the servicesa market based weighted average cost of independent petroleum engineers (management’s specialists) to estimate their proved crude oil and natural gas reserves.capital rate.
The principal considerations for our determination that performing procedures relating to the valuation of proved crude oil and natural gas properties is a critical audit matter are there was(i) the significant judgment by management including the use of management’s specialists, when developing the estimates of proved oilundiscounted future cash flow analysis for the impairment assessment and natural gas reserves; which in turn led to adiscounted future cash flow analysis for the impairment assessment and acquisition accounting, (ii) the high degree of auditor judgment, effort, and subjectivity in performing procedures to evaluateand evaluating management’s estimated future cash flows and significant assumptions includingrelated to estimates of reserves volumes, future operating and development costs, and future commodity prices as well asand the significant inputweighted average cost of interestcapital rate, and net revenue interest inputs used in estimated future cash flows.(iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the impairment assessment and development of future cash flows for impairment and the valuation of acquired proved crude oil and natural gas properties and the development of future cash flows.properties. These procedures also included, among others, (i) testing management’s process for developing the fair value estimate; (ii) evaluating the appropriateness of the undiscounted and discounted cash flow models, (iii) testing the completeness and accuracy of ownership records, including inputs of interestthe underlying data used in the models; and net revenue interests, and(iv) evaluating the significant assumptions used by management related to reserves volumes, future operating and method used indevelopment costs, future commodity prices, and a market based weighted average cost of capital rate. Evaluating the Company’s proved crude oilreasonableness of management’s assumptions related to: (i) future operating and natural gas impairment analysis.development costs involved consideration of the past and anticipated performance of the Company; and (ii) future commodity prices involved consideration of observable market data. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimatesreserve volumes as stated in the Critical Audit Matter titled “Impact of proved crude oilProved Oil and natural gas reserves.Natural Gas Reserves on Proved Crude Oil and Natural Gas Properties, Net”. As a basis for using this work, the specialists’ qualifications and objectivity were understood as well asand the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists. The procedures performed also includedspecialists, tests of the data used by the specialists and an evaluation of the specialist’sspecialists’ findings. WhenProfessionals with specialized skill and knowledge were used to assist in evaluating the assumptions relating to the estimates of reserves volumes, future operating and development costs, and future commodity prices, procedures performed included obtaining evidence related to the reasonableness of these assumptions, including whether the assumptions used were reasonable considering the past performanceappropriateness of the Companymodels and whether the assumptions were consistent with evidence obtained in other areas of the audit.
/s/PricewaterhouseCoopers LLP
Denver, Colorado
February 26, 202024, 2021
We have served as the Company’s auditor since 2007.
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PDC ENERGY, INC.
Consolidated Balance Sheets
(in thousands, except share and per share data)
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 2,623 | $ | 963 | ||||||||||
| Accounts receivable, net | 244,251 | 266,354 | ||||||||||||
| Fair value of derivatives | 48,869 | 28,078 | ||||||||||||
| Prepaid expenses and other current assets | 12,505 | 8,635 | ||||||||||||
| Total current assets | 308,248 | 304,030 | ||||||||||||
| Properties and equipment, net | 4,859,199 | 4,095,202 | ||||||||||||
| Fair value of derivatives | 9,565 | 3,746 | ||||||||||||
| Other assets | 60,961 | 45,702 | ||||||||||||
| Total Assets | $ | 5,237,973 | $ | 4,448,680 | ||||||||||
| Liabilities and Stockholders' Equity | ||||||||||||||
| Liabilities | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable | $ | 90,635 | $ | 98,934 | ||||||||||
| Production tax liability | 124,475 | 76,236 | ||||||||||||
| Fair value of derivatives | 98,152 | 2,921 | ||||||||||||
| Funds held for distribution | 177,132 | 98,393 | ||||||||||||
| Accrued interest payable | 14,734 | 14,284 | ||||||||||||
| Other accrued expenses | 81,715 | 70,462 | ||||||||||||
| Current portion of long-term debt | 193,014 | 0 | ||||||||||||
| Total current liabilities | 779,857 | 361,230 | ||||||||||||
| Long-term debt | 1,409,548 | 1,177,226 | ||||||||||||
| Deferred income taxes | 0 | 195,841 | ||||||||||||
| Asset retirement obligations | 132,637 | 95,051 | ||||||||||||
| Fair value of derivatives | 36,359 | 692 | ||||||||||||
| Other liabilities | 264,034 | 283,133 | ||||||||||||
| Total liabilities | 2,622,435 | 2,113,173 | ||||||||||||
| Commitments and contingent liabilities | 0 | 0 | ||||||||||||
| Stockholders' equity | ||||||||||||||
| Common shares - par value $0.01 per share, 150,000,000 authorized, 99,758,720 and 61,652,412 issued as of December 31, 2020 and 2019, respectively | 998 | 617 | ||||||||||||
| Additional paid-in capital | 3,387,754 | 2,384,309 | ||||||||||||
| Accumulated deficit | (772,265) | (47,945) | ||||||||||||
| Treasury shares - at cost, 37,510 and 34,922 as of December 31, 2020 and 2019, respectively | (949) | (1,474) | ||||||||||||
| Total stockholders' equity | 2,615,538 | 2,335,507 | ||||||||||||
| Total Liabilities and Stockholders' Equity | $ | 5,237,973 | $ | 4,448,680 | ||||||||||
| As of December 31, | 2019 | 2018 | ||||||
| Assets | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 963 | $ | 1,398 | ||||
| Accounts receivable, net | 266,354 | 181,434 | ||||||
| Fair value of derivatives | 28,078 | 84,492 | ||||||
| Prepaid expenses and other current assets | 8,635 | 7,136 | ||||||
| Total current assets | 304,030 | 274,460 | ||||||
| Properties and equipment, net | 4,095,202 | 4,002,862 | ||||||
| Assets held-for-sale, net | — | 140,705 | ||||||
| Fair value of derivatives | 3,746 | 93,722 | ||||||
| Other assets | 45,702 | 32,396 | ||||||
| Total Assets | $ | 4,448,680 | $ | 4,544,145 | ||||
| Liabilities and Stockholders' Equity | ||||||||
| Liabilities | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 98,934 | $ | 181,864 | ||||
| Production tax liability | 76,236 | 60,719 | ||||||
| Fair value of derivatives | 2,921 | 3,364 | ||||||
| Funds held for distribution | 98,393 | 105,784 | ||||||
| Accrued interest payable | 14,284 | 14,150 | ||||||
| Other accrued expenses | 70,462 | 75,133 | ||||||
| Total current liabilities | 361,230 | 441,014 | ||||||
| Long-term debt | 1,177,226 | 1,194,876 | ||||||
| Deferred income taxes | 195,841 | 198,096 | ||||||
| Asset retirement obligations | 95,051 | 85,312 | ||||||
| Liabilities held-for-sale | — | 4,111 | ||||||
| Fair value of derivatives | 692 | 1,364 | ||||||
| Other liabilities | 283,133 | 92,664 | ||||||
| Total liabilities | 2,113,173 | 2,017,437 | ||||||
| Commitments and contingent liabilities | ||||||||
| Stockholders' equity | ||||||||
| Common shares - par value $0.01 per share, 150,000,000 authorized, 61,652,412 and 66,148,609 issued as of December 31, 2019 and 2018, respectively | 617 | 661 | ||||||
| Additional paid-in capital | 2,384,309 | 2,519,423 | ||||||
| Retained earnings (deficit) | (47,945 | ) | 8,727 | |||||
| Treasury shares - at cost, 34,922 and 45,220 as of December 31, 2019 and 2018, respectively | (1,474 | ) | (2,103 | ) | ||||
| Total stockholders' equity | 2,335,507 | 2,526,708 | ||||||
| Total Liabilities and Stockholders' Equity | $ | 4,448,680 | $ | 4,544,145 | ||||
See accompanying Notes to Consolidated Financial Statements
PDC ENERGY, INC.
Consolidated Statements of Operations
(in thousands, except per share data)
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| Revenues | ||||||||||||||||||||
| Crude oil, natural gas and NGLs sales | $ | 1,152,555 | $ | 1,307,275 | $ | 1,389,961 | ||||||||||||||
| Commodity price risk management gain (loss), net | 180,270 | (162,844) | 145,237 | |||||||||||||||||
| Other income | 6,401 | 11,692 | 13,461 | |||||||||||||||||
| Total revenues | 1,339,226 | 1,156,123 | 1,548,659 | |||||||||||||||||
| Costs, expenses and other | ||||||||||||||||||||
| Lease operating expenses | 161,346 | 142,248 | 130,957 | |||||||||||||||||
| Production taxes | 59,368 | 80,754 | 90,357 | |||||||||||||||||
| Transportation, gathering and processing expenses | 77,835 | 46,353 | 37,403 | |||||||||||||||||
| Exploration, geologic and geophysical expense | 1,376 | 4,054 | 6,204 | |||||||||||||||||
| General and administrative expense | 161,087 | 161,753 | 170,504 | |||||||||||||||||
| Depreciation, depletion and amortization | 619,739 | 644,152 | 559,793 | |||||||||||||||||
| Accretion of asset retirement obligations | 10,072 | 6,117 | 5,075 | |||||||||||||||||
| Impairment of properties and equipment | 882,393 | 38,536 | 458,397 | |||||||||||||||||
| Loss (gain) on sale of properties and equipment | (724) | 9,734 | 394 | |||||||||||||||||
| Other expense | 10,272 | 11,317 | 11,829 | |||||||||||||||||
| Total costs, expenses and other | 1,982,764 | 1,145,018 | 1,470,913 | |||||||||||||||||
| Income (loss) from operations | (643,538) | 11,105 | 77,746 | |||||||||||||||||
| Interest expense, net | (88,684) | (71,099) | (70,317) | |||||||||||||||||
| Income (loss) before income taxes | (732,222) | (59,994) | 7,429 | |||||||||||||||||
| Income tax benefit (expense) | 7,902 | 3,322 | (5,406) | |||||||||||||||||
| Net income (loss) | $ | (724,320) | $ | (56,672) | $ | 2,023 | ||||||||||||||
| Earnings (loss) per share: | ||||||||||||||||||||
| Basic | $ | (7.37) | $ | (0.89) | $ | 0.03 | ||||||||||||||
| Diluted | (7.37) | (0.89) | 0.03 | |||||||||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||||||
| Basic | 98,251 | 64,032 | 66,059 | |||||||||||||||||
| Diluted | 98,251 | 64,032 | 66,303 | |||||||||||||||||
| Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
| Revenues | ||||||||||||
| Crude oil, natural gas and NGLs sales | $ | 1,307,275 | $ | 1,389,961 | $ | 913,084 | ||||||
| Commodity price risk management gain (loss), net | (162,844 | ) | 145,237 | (3,936 | ) | |||||||
| Other income | 11,692 | 13,461 | 12,468 | |||||||||
| Total revenues | 1,156,123 | 1,548,659 | 921,616 | |||||||||
| Costs, expenses and other | ||||||||||||
| Lease operating expenses | 142,248 | 130,957 | 89,641 | |||||||||
| Production taxes | 80,754 | 90,357 | 60,717 | |||||||||
| Transportation, gathering and processing expenses | 46,353 | 37,403 | 33,220 | |||||||||
| Exploration, geologic and geophysical expense | 4,054 | 6,204 | 47,334 | |||||||||
| General and administrative expense | 161,753 | 170,504 | 120,370 | |||||||||
| Depreciation, depletion and amortization | 644,152 | 559,793 | 469,084 | |||||||||
| Accretion of asset retirement obligations | 6,117 | 5,075 | 6,306 | |||||||||
| Impairment of properties and equipment | 38,536 | 458,397 | 285,887 | |||||||||
| Impairment of goodwill | — | — | 75,121 | |||||||||
| (Gain) loss on sale of properties and equipment | 9,734 | 394 | (766 | ) | ||||||||
| Provision for uncollectible notes receivable | — | — | (40,203 | ) | ||||||||
| Other expenses | 11,317 | 11,829 | 13,157 | |||||||||
| Total costs, expenses and other | 1,145,018 | 1,470,913 | 1,159,868 | |||||||||
| Income (loss) from operations | 11,105 | 77,746 | (238,252 | ) | ||||||||
| Loss on extinguishment of debt | — | — | (24,747 | ) | ||||||||
| Interest expense | (71,171 | ) | (70,730 | ) | (78,694 | ) | ||||||
| Interest income | 72 | 413 | 2,261 | |||||||||
| Income (loss) before income taxes | (59,994 | ) | 7,429 | (339,432 | ) | |||||||
| Income tax (expense) benefit | 3,322 | (5,406 | ) | 211,928 | ||||||||
| Net income (loss) | $ | (56,672 | ) | $ | 2,023 | $ | (127,504 | ) | ||||
| Earnings per share: | ||||||||||||
| Basic | $ | (0.89 | ) | $ | 0.03 | $ | (1.94 | ) | ||||
| Diluted | $ | (0.89 | ) | $ | 0.03 | $ | (1.94 | ) | ||||
| Weighted-average common shares outstanding: | ||||||||||||
| Basic | 64,032 | 66,059 | 65,837 | |||||||||
| Diluted | 64,032 | 66,303 | 65,837 | |||||||||
See accompanying Notes to Consolidated Financial Statements
PDC ENERGY, INC.
Consolidated Statements of Cash Flows
(in thousands)
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||
| Net income (loss) | $ | (724,320) | $ | (56,672) | $ | 2,023 | ||||||||||||||
| Adjustments to net income (loss) to reconcile to net cash from operating activities: | ||||||||||||||||||||
| Net change in fair value of unsettled commodity derivatives | 99,001 | 145,246 | (260,775) | |||||||||||||||||
| Depreciation, depletion and amortization | 619,739 | 644,152 | 559,793 | |||||||||||||||||
| Impairment of properties and equipment | 882,393 | 38,536 | 458,397 | |||||||||||||||||
| Accretion of asset retirement obligations | 10,072 | 6,117 | 5,075 | |||||||||||||||||
| Non-cash stock-based compensation | 22,200 | 23,837 | 21,782 | |||||||||||||||||
| Loss (gain) on sale of properties and equipment | (724) | 9,734 | 394 | |||||||||||||||||
| Amortization and write-off of debt discount, premium and issuance costs | 16,772 | 13,575 | 12,769 | |||||||||||||||||
| Deferred income taxes | (6,530) | (2,256) | 6,105 | |||||||||||||||||
| Other | 3,004 | 3,155 | 2,876 | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Accounts receivable | 139,664 | (88,304) | 12,025 | |||||||||||||||||
| Other assets | (5,341) | (11,560) | (81) | |||||||||||||||||
| Production tax liability | (50,803) | 22,240 | 35,225 | |||||||||||||||||
| Accounts payable and accrued expenses | (66,183) | (29,578) | 16,261 | |||||||||||||||||
| Funds held for future distribution | (23,621) | (7,298) | 9,973 | |||||||||||||||||
| Asset retirement obligations | (27,491) | (21,511) | (13,341) | |||||||||||||||||
| Other liabilities | (17,753) | 168,813 | 20,801 | |||||||||||||||||
| Net cash from operating activities | 870,079 | 858,226 | 889,302 | |||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||
| Capital expenditures for development of crude oil and natural gas properties | (550,964) | (855,908) | (946,350) | |||||||||||||||||
| Capital expenditures for other properties and equipment | (1,634) | (20,839) | (11,055) | |||||||||||||||||
| Acquisition of crude oil and natural gas properties | (139,812) | (13,207) | (180,026) | |||||||||||||||||
| Proceeds from sale of properties and equipment | 1,641 | 2,105 | 3,562 | |||||||||||||||||
| Proceeds from divestitures | 3,610 | 202,076 | 44,693 | |||||||||||||||||
| Restricted cash | 0 | 8,001 | 1,249 | |||||||||||||||||
| Net cash from investing activities | (687,159) | (677,772) | (1,087,927) | |||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||
| Proceeds from revolving credit facility and other borrowings | 1,799,350 | 1,577,000 | 1,072,500 | |||||||||||||||||
| Repayment of revolving credit facility and other borrowings | (1,635,350) | (1,605,500) | (1,040,000) | |||||||||||||||||
| Proceeds from issuance of senior notes | 148,500 | 0 | 0 | |||||||||||||||||
| Payment of debt issuance costs | (6,538) | (72) | (7,704) | |||||||||||||||||
| Purchase of treasury shares | (23,819) | (154,363) | 0 | |||||||||||||||||
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | (9,345) | (4,003) | (5,147) | |||||||||||||||||
| Redemption of senior notes | (452,153) | 0 | 0 | |||||||||||||||||
| Principal payments under financing lease obligations | (1,905) | (1,952) | (1,495) | |||||||||||||||||
| Other | 0 | 0 | (55) | |||||||||||||||||
| Net cash from financing activities | (181,260) | (188,890) | 18,099 | |||||||||||||||||
| Net change in cash, cash equivalents and restricted cash | 1,660 | (8,436) | (180,526) | |||||||||||||||||
| Cash, cash equivalents and restricted cash, beginning of year | 963 | 9,399 | 189,925 | |||||||||||||||||
| Cash, cash equivalents and restricted cash, end of year | $ | 2,623 | $ | 963 | $ | 9,399 | ||||||||||||||
| Year Ended December 31, | 2019 | 2018 | 2017 | |||||||||
| Cash flows from operating activities: | ||||||||||||
| Net income (loss) | $ | (56,672 | ) | $ | 2,023 | $ | (127,504 | ) | ||||
| Adjustments to net income (loss) to reconcile to net cash from operating activities: | ||||||||||||
| Net change in fair value of unsettled commodity derivatives | 145,246 | (260,775 | ) | 17,260 | ||||||||
| Depreciation, depletion and amortization | 644,152 | 559,793 | 469,084 | |||||||||
| Impairment of properties and equipment | 38,536 | 458,397 | 285,887 | |||||||||
| Accretion of asset retirement obligations | 6,117 | 5,075 | 6,306 | |||||||||
| Non-cash stock-based compensation | 23,837 | 21,782 | 19,353 | |||||||||
| (Gain) loss on sale of properties and equipment | 9,734 | 394 | (766 | ) | ||||||||
| Amortization of debt discount and issuance costs | 13,575 | 12,769 | 12,907 | |||||||||
| Deferred income taxes | (2,256 | ) | 6,105 | (203,685 | ) | |||||||
| Impairment of goodwill | — | — | 75,121 | |||||||||
| Exploratory dry hole costs | — | 113 | 41,297 | |||||||||
| Provision for uncollectible notes receivable | — | — | (40,203 | ) | ||||||||
| Loss on extinguishment of debt | — | — | 24,747 | |||||||||
| Other | 3,155 | 2,763 | 2,265 | |||||||||
| Total adjustments to net income (loss) to reconcile to net cash from operating activities: | 882,096 | 806,416 | 709,573 | |||||||||
| Changes in assets and liabilities: | ||||||||||||
| Accounts receivable | (88,304 | ) | 12,025 | (60,546 | ) | |||||||
| Other assets | (11,560 | ) | (81 | ) | 3,364 | |||||||
| Production tax liability | 22,240 | 35,225 | 31,316 | |||||||||
| Accounts payable and accrued expenses | (29,578 | ) | 16,261 | 31,378 | ||||||||
| Funds held for future distribution | (7,298 | ) | 9,973 | 24,472 | ||||||||
| Asset retirement obligations | (21,511 | ) | (13,341 | ) | (10,176 | ) | ||||||
| Other liabilities | 168,813 | 20,801 | (4,064 | ) | ||||||||
| Total changes in assets and liabilities | 32,802 | 80,863 | 15,744 | |||||||||
| Net cash from operating activities | 858,226 | 889,302 | 597,813 | |||||||||
| Cash flows from investing activities: | ||||||||||||
| Capital expenditures for development of crude oil and natural gas properties | (855,908 | ) | (946,350 | ) | (737,208 | ) | ||||||
| Capital expenditures for other properties and equipment | (20,839 | ) | (11,055 | ) | (5,094 | ) | ||||||
| Acquisition of crude oil and natural gas properties | (13,207 | ) | (180,026 | ) | (15,628 | ) | ||||||
| Proceeds from sale of properties and equipment | 2,105 | 3,562 | 9,991 | |||||||||
| Proceeds from divestitures | 202,076 | 44,693 | — | |||||||||
| Sale of promissory note | — | — | 40,203 | |||||||||
| Restricted cash | 8,001 | 1,249 | (9,250 | ) | ||||||||
| Sale of short-term investments | — | — | 49,890 | |||||||||
| Purchase of short-term investments | — | — | (49,890 | ) | ||||||||
| Net cash from investing activities | (677,772 | ) | (1,087,927 | ) | (716,986 | ) | ||||||
| Cash flows from financing activities: | ||||||||||||
| Proceeds from revolving credit facility | 1,577,000 | 1,072,500 | — | |||||||||
| Repayment of revolving credit facility | (1,605,500 | ) | (1,040,000 | ) | — | |||||||
| Proceeds from issuance of senior notes | — | — | 592,366 | |||||||||
| Redemption of senior notes | — | — | (519,375 | ) | ||||||||
| Payment of debt issuance costs | (72 | ) | (7,704 | ) | (50 | ) | ||||||
| Purchase of treasury shares | (154,363 | ) | — | — | ||||||||
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | (4,003 | ) | (5,147 | ) | (6,672 | ) | ||||||
| Principal payments under financing lease obligations | (1,952 | ) | (1,495 | ) | (1,168 | ) | ||||||
| Other | — | (55 | ) | (103 | ) | |||||||
| Net cash from financing activities | (188,890 | ) | 18,099 | 64,998 | ||||||||
| Net change in cash, cash equivalents and restricted cash | (8,436 | ) | (180,526 | ) | (54,175 | ) | ||||||
| Cash, cash equivalents and restricted cash, beginning of year | 9,399 | 189,925 | 244,100 | |||||||||
| Cash, cash equivalents and restricted cash, end of year | $ | 963 | $ | 9,399 | $ | 189,925 | ||||||
See accompanying Notes to Consolidated Financial Statements