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| PART I – FINANCIAL INFORMATION | | Page |
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| Item 2. | | | |
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| PART II – OTHER INFORMATION |
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| Item 1. | | | |
| Item 1A. | | | |
| Item 2. | | | |
| Item 3. | | | |
| Item 4. | | | |
| Item 5. | | | |
| Item 6. | | | |
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q 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; drilling locations, zones and growth opportunities; impacts of Colorado political matters; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; adequacy of midstream infrastructure; adequacy of third party grid power capacity; the potential return of capital to shareholders through buybacks of shares and/or payments of dividends; expected impact from emission reduction initiatives; risk of our counterparties’ non-performance on derivative instruments; and our ability to fund planned activities.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.
Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
•market and commodity price volatility, widening price differentials, and related impacts to the Company, including decreased revenue, income and cash flow, write-downs and impairments and decreased availability of capital;
•difficulties in integrating our operations as a result of any significant acquisitions or acreage exchanges;
•adverse changes to our future cash flows, liquidity and financial condition;
•changes in, and interpretations and enforcement of, environmental and other laws and other political and regulatory developments;
•declines in the value of our crude oil, natural gas and natural gas liquids (“NGLs”) properties resulting in impairments;
•changes in, and inaccuracy of, reserve estimates and expected production and decline rates;
•timing and extent of our success in discovering, acquiring, developing and producing reserves;
•reductions in the borrowing base under our revolving credit facility;
•availability and cost of capital;
•risks inherent in the drilling and operation of crude oil and natural gas wells;
•ability to add to our gross operated inventory through wellbore spacing and untested zones;
•timing and costs of wells and facilities;
•availability, cost, and timing of sufficient pipeline, gathering, transportation and electrical facilities and related infrastructure;
•limitations in the availability of supplies, materials, contractors and services that may delay the drilling or
completion of our wells;
•potential losses of acreage or other impacts due to lease expirations, other title defects, or otherwise;
•risks inherent in marketing crude oil, natural gas and NGLs;
•effect of crude oil and natural gas derivative activities;
•impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events;
•cost of pending or future litigation;
•impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders;
•uncertainties associated with future dividends to our shareholders or share buybacks;
•timing and amounts of federal and state income taxes;
•our ability to retain or attract senior management and key technical employees;
•an unanticipated assumption of liabilities or other problems with business acquisitions;
•cybersecurity disruptions to our operations from breaches of our information technology systems, or from breaches of third party systems;
•physical, financial and transition risks relating to climate change;
•changes in general economic, business or industry conditions, including changes in interest rates and inflation rates and concerns regarding national or global recessionary conditions;
•our ability to achieve our emission reductions, flaring and other environmental, social and governmental goals;
•the impact of the loss of a single customer or any purchaser of our products; 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 our Annual Report on Form 10-K for the year ended December 31, 2022 (“2022 Form 10-K”) filed with the U.S. Securities and Exchange Commission (“SEC”) for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.
REFERENCES
Unless the context otherwise requires, references in this report to “PDC Energy”, “PDC”, “the Company”, “we”, “us”, “our” or “ours” refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements.
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PDC ENERGY, INC.
Condensed Consolidated Balance Sheets
(in thousands, except share and per share data)
(Unaudited)
| | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| Assets | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 17,443 | | | $ | 6,494 | |
| Accounts receivable, net | | 474,783 | | | 546,311 | |
| Fair value of derivatives | | 68,144 | | | 31,963 | |
| Prepaid expenses and other current assets | | 10,822 | | | 8,987 | |
| Total current assets | | 571,192 | | | 593,755 | |
| Properties and equipment, net | | 7,510,312 | | | 7,293,355 | |
| Fair value of derivatives | | 46,497 | | | 25,562 | |
| Other assets | | 131,464 | | | 70,093 | |
| Total Assets | | $ | 8,259,465 | | | $ | 7,982,765 | |
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| Liabilities and Stockholders’ Equity | | | | |
| Liabilities | | | | |
| Current liabilities: | | | | |
| Accounts payable | | $ | 285,995 | | | $ | 244,406 | |
| Production tax liability | | 253,962 | | | 244,737 | |
| Fair value of derivatives | | 125,529 | | | 274,218 | |
| Funds held for distribution | | 523,889 | | | 539,094 | |
| Accrued interest payable | | 20,877 | | | 11,655 | |
| Other accrued expenses | | 112,294 | | | 106,082 | |
| Total current liabilities | | 1,322,546 | | | 1,420,192 | |
| Long-term debt | | 1,296,491 | | | 1,314,010 | |
| Asset retirement obligations | | 170,060 | | | 171,665 | |
| Fair value of derivatives | | 29,019 | | | 53,600 | |
| Deferred income taxes | | 621,358 | | | 507,683 | |
| Other liabilities | | 605,615 | | | 532,870 | |
| Total liabilities | | 4,045,089 | | | 4,000,020 | |
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| Commitments and contingent liabilities | | | | |
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| Stockholders’ equity | | | | |
Common shares - par value $0.01 per share, 150,000,000 authorized, 87,570,195 and 89,224,353 issued as of March 31, 2023 and December 31, 2022, respectively | | 876 | | | 892 | |
| Additional paid-in capital | | 2,742,706 | | | 2,823,364 | |
| Retained earnings | | 1,476,205 | | | 1,165,816 | |
Treasury shares - at cost, 88,328 and 119,336 as of March 31, 2023 and December 31, 2022, respectively | | (5,411) | | | (7,327) | |
| Total stockholders’ equity | | 4,214,376 | | | 3,982,745 | |
| Total Liabilities and Stockholders’ Equity | | $ | 8,259,465 | | | $ | 7,982,765 | |
See accompanying Notes to Condensed Consolidated Financial Statements
1
PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
(Unaudited)
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| | | | Three Months Ended March 31, |
| | | | | | 2023 | | 2022 |
| Revenues | | | | | | | | |
| Crude oil, natural gas and NGLs sales | | | | | | $ | 813,284 | | | $ | 882,378 | |
| Commodity price risk management gain (loss), net | | | | | | 144,132 | | | (568,055) | |
| Other income | | | | | | 252 | | | 2,125 | |
| Total revenues | | | | | | 957,668 | | | 316,448 | |
| Costs, expenses and other | | | | | | | | |
| Lease operating expense | | | | | | 73,259 | | | 54,156 | |
| Production taxes | | | | | | 55,747 | | | 62,916 | |
| Transportation, gathering and processing expense | | | | | | 32,505 | | | 27,971 | |
| Exploration, geologic and geophysical expense | | | | | | 534 | | | 253 | |
| General and administrative expense | | | | | | 41,487 | | | 34,107 | |
| Depreciation, depletion and amortization | | | | | | 207,187 | | | 151,055 | |
| Accretion of asset retirement obligations | | | | | | 3,714 | | | 2,987 | |
| Impairment of properties and equipment | | | | | | 1,373 | | | 943 | |
| Loss (gain) on sale of properties and equipment | | | | | | 155 | | | (125) | |
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| Total costs, expenses and other | | | | | | 415,961 | | | 334,263 | |
| Income (loss) from operations | | | | | | 541,707 | | | (17,815) | |
| Interest expense, net | | | | | | (14,705) | | | (12,945) | |
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| Income (loss) before income taxes | | | | | | 527,002 | | | (30,760) | |
| Income tax expense | | | | | | (112,870) | | | (1,200) | |
| Net income (loss) | | | | | | $ | 414,132 | | | $ | (31,960) | |
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| Earnings (loss) per share: | | | | | | | | |
| Basic | | | | | | $ | 4.69 | | | $ | (0.33) | |
| Diluted | | | | | | $ | 4.64 | | | $ | (0.33) | |
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| Weighted average common shares outstanding: | | | | | | | | |
| Basic | | | | | | 88,357 | | | 96,279 | |
| Diluted | | | | | | 89,228 | | | 96,279 | |
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See accompanying Notes to Condensed Consolidated Financial Statements
2
PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | 2023 | | 2022 |
| Cash flows from operating activities: | | | | |
| Net income (loss) | | $ | 414,132 | | | $ | (31,960) | |
| Adjustments to net income (loss) to reconcile to net cash from operating activities: | | | | |
| Net change in fair value of unsettled commodity derivatives | | (230,386) | | | 406,461 | |
| Depreciation, depletion and amortization | | 207,187 | | | 151,055 | |
| Impairment of properties and equipment | | 1,373 | | | 943 | |
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| Accretion of asset retirement obligations | | 3,714 | | | 2,987 | |
| Non-cash stock-based compensation | | 6,564 | | | 5,474 | |
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| Amortization of debt discount, premium and issuance costs | | 1,361 | | | 1,357 | |
| Deferred income taxes | | 113,675 | | | 3,600 | |
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| Other | | 258 | | | (1,030) | |
| Changes in assets and liabilities | | 70,445 | | | (49,839) | |
| Net cash from operating activities | | 588,323 | | | 489,048 | |
| Cash flows from investing activities: | | | | |
| Capital expenditures for development of crude oil and natural gas properties | | (362,251) | | | (187,021) | |
| Capital expenditures for midstream assets | | (3,574) | | | — | |
| Capital expenditures for other properties and equipment | | (6,651) | | | (67) | |
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| Proceeds from sale of properties and equipment | | 37 | | | 89 | |
| Proceeds from divestitures | | — | | | 465 | |
| Funds held in escrow for acquisition | | — | | | (50,000) | |
| Net cash from investing activities | | (372,439) | | | (236,534) | |
| Cash flows from financing activities: | | | | |
| Proceeds from revolving credit facility and other borrowings | | 496,000 | | | 100,500 | |
| Repayment of revolving credit facility and other borrowings | | (514,000) | | | (100,500) | |
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| Payment of debt issuance costs | | — | | | (30) | |
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | | (19,243) | | | (9,203) | |
| Purchase of treasury shares under stock repurchase program | | (129,944) | | | (80,853) | |
| Dividends paid | | (37,179) | | | (24,681) | |
| Principal payments under financing lease obligations | | (569) | | | (419) | |
| Net cash from financing activities | | (204,935) | | | (115,186) | |
| Net change in cash and cash equivalents | | 10,949 | | | 137,328 | |
| Cash and cash equivalents, beginning of period | | 6,494 | | | 33,829 | |
| Cash and cash equivalents, end of period | | $ | 17,443 | | | $ | 171,157 | |
See accompanying Notes to Condensed Consolidated Financial Statements
3
PDC ENERGY, INC.
Condensed Consolidated Statements of Stockholders’ Equity
(in thousands, except dividends per share)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2023 |
| Common Stock | | Additional Paid-in Capital | | Treasury Stock | | Retained Earnings (Accumulated Deficit) | | Total Stockholders’ Equity |
| Shares | | Amount | | | Shares | | Amount | | |
| Balance, January 1, 2023 | 89,224 | | | $ | 892 | | | $ | 2,823,364 | | | (119) | | | $ | (7,327) | | | $ | 1,165,816 | | | $ | 3,982,745 | |
| Net income (loss) | — | | | — | | | — | | | — | | | — | | | 414,132 | | | 414,132 | |
| Stock-based compensation | 734 | | | 8 | | | 6,497 | | | — | | | 59 | | | — | | | 6,564 | |
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | — | | | — | | | — | | | (300) | | | (19,243) | | | — | | | (19,243) | |
| Retirement of treasury shares for employee stock-based compensation tax withholding obligations | (300) | | | (3) | | | (10,942) | | | 300 | | | 19,243 | | | (8,298) | | | — | |
| Retirement of treasury shares | (2,088) | | | (21) | | | (76,213) | | | 2,089 | | | 136,047 | | | (59,813) | | | — | |
| Issuance of treasury shares | — | | | — | | | — | | | 1 | | | — | | | — | | | — | |
| Purchase of treasury shares under stock repurchase program | — | | | — | | | — | | | (2,059) | | | (134,190) | | | — | | | (134,190) | |
Dividends declared ($0.40 per share) | — | | | — | | | — | | | — | | | — | | | (35,632) | | | (35,632) | |
| Balance, March 31, 2023 | 87,570 | | | $ | 876 | | | $ | 2,742,706 | | | (88) | | | $ | (5,411) | | | $ | 1,476,205 | | | $ | 4,214,376 | |
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| Three Months Ended March 31, 2022 |
| Common Stock | | Additional Paid-in Capital | | Treasury Stock | | Accumulated Deficit | | Total Stockholders’ Equity |
| Shares | | Amount | | | Shares | | Amount | | |
| Balance, January 1, 2022 | 96,468 | | | $ | 965 | | | $ | 3,161,941 | | | (55) | | | $ | (2,705) | | | $ | (249,954) | | | $ | 2,910,247 | |
| Net income (loss) | — | | | — | | | — | | | — | | | — | | | (31,960) | | | (31,960) | |
| Stock-based compensation | 655 | | | 7 | | | 1,798 | | | — | | | 3,669 | | | — | | | 5,474 | |
| Purchase of treasury shares for employee stock-based compensation tax withholding obligations | — | | | — | | | — | | | (164) | | | (9,203) | | | — | | | (9,203) | |
| Retirement of treasury shares for employee stock-based compensation tax withholding obligations | (53) | | | (2) | | | (3,022) | | | 53 | | | 3,024 | | | — | | | — | |
| Retirement of treasury shares | (1,320) | | | (13) | | | (83,508) | | | 1,320 | | | 83,521 | | | — | | | — | |
| Issuance of treasury shares | — | | | — | | | — | | | 67 | | | — | | | — | | | — | |
| Purchase of treasury shares under stock repurchase program | — | | | — | | | — | | | (1,326) | | | (85,339) | | | — | | | (85,339) | |
Dividends declared ($0.25 per share) | — | | | — | | | (24,468) | | | — | | | — | | | — | | | (24,468) | |
| Balance, March 31, 2022 | 95,750 | | | $ | 957 | | | $ | 3,052,741 | | | (105) | | | $ | (7,033) | | | $ | (281,914) | | | $ | 2,764,751 | |
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See accompanying Notes to Condensed Consolidated Financial Statements
4
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. As of March 31, 2023, we owned an interest in approximately 4,100 gross productive wells.
The accompanying unaudited condensed consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments necessary for a fair statement of the results of interim periods presented in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2022 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2022 Form 10-K. Our results of operations and cash flows for the three months ended March 31, 2023 are not necessarily indicative of the results to be expected for the full year or any other future period.
NOTE 2 - BUSINESS COMBINATION
On May 6, 2022, we completed the acquisition of Great Western Petroleum, LLC (“Great Western”), for approximately $1.4 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western was an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. The consideration paid included $543 million in cash and approximately 4.0 million shares of our common stock, valued at $293 million on the acquisition date. In addition, we paid off the Great Western secured credit facility totaling $236 million and irrevocably deposited $361 million on Great Western’s behalf to pay and discharge on May 20, 2022 Great Western’s 12 percent senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash portion of the purchase price and the termination of Great Western’s debt were funded through a combination of cash on hand and availability under our revolving credit facility.
Purchase Price Allocation
The Great Western Acquisition has been accounted for using the acquisition method under Accounting Standards Codification (“ASC”) 805, Business Combinations, with PDC being treated as the accounting acquirer. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
The purchase price allocation was completed on December 31, 2022. The following table details our final purchase price, valuation and allocation of the purchase price to the assets acquired and liabilities assumed as a result of the Great Western Acquisition:
| | | | | | | | |
| | (in thousands, except share and per share data) |
| Consideration: | | |
| Cash | | $ | 542,500 | |
| Retirement of Great Western’s credit facility | | 235,822 | |
| Extinguishment of Great Western’s secured senior notes | | 361,231 | |
| Total cash consideration | | $ | 1,139,553 | |
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| Common stock issued | | 4,007,018 | |
| Fair value of PDC common stock on May 6, 2022 | | $ | 73.20 | |
| Total fair value of common stock issued | | 293,314 | |
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| Total consideration | | $ | 1,432,867 | |
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| Assets acquired: | | |
| Cash | | $ | 63,183 | |
| Accounts receivable | | 164,026 | |
| Other current assets | | 3,129 | |
| Properties and equipment, net - proved | | 2,091,301 | |
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| Properties and equipment, net - other | | 7,035 | |
| Other noncurrent assets | | 20,345 | |
| Total assets acquired | | $ | 2,349,019 | |
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| Liabilities assumed: | | |
| Accounts payable | | $ | (119,142) | |
| Production tax liability | | (110,940) | |
| Funds held for distribution | | (170,708) | |
| Other current liabilities | | (19,203) | |
| Fair value of derivatives | | (319,600) | |
| Asset retirement obligations | | (25,300) | |
| Deferred tax liabilities | | (28,400) | |
| Other liabilities | | (32,802) | |
| Total liabilities assumed | | $ | (826,095) | |
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| Total identifiable net assets acquired | | $ | 1,522,924 | |
| Gain on bargain purchase | | 90,057 | |
| Purchase price consideration | | $ | 1,432,867 | |
Determining the fair values of the assets and liabilities of Great Western required judgement and certain assumptions to be made, the most significant of these being related to the valuation of crude oil and natural gas properties. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate of 14.25 percent. These inputs require significant judgments and estimates by management at the time of the valuation. The fair value of derivative instruments was based on observable inputs, including forward commodity-price curves which are considered Level 2 inputs, and based on volatility factors which are considered Level 3 inputs.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
ASC 805, Business Combinations, requires that any excess of purchase price over the fair value of assets acquired, including identifiable intangibles and liabilities assumed, be recognized as goodwill and any excess of fair value of acquired net assets, including identifiable intangible assets over the acquisition consideration, results in a gain from bargain purchase. Prior to recording a gain, the acquiring entity must reassess whether all assets acquired and assumed liabilities have been identified and recognized and perform re-measurements to verify that the consideration paid, assets acquired and liabilities assumed have been properly valued. The Great Western Acquisition resulted in a gain on bargain purchase due to the estimated fair value of the identifiable net assets acquired exceeding the purchase consideration transferred by $90 million, net of related income taxes of $28 million. Upon completion of our assessment, we concluded that recording a gain on bargain purchase was appropriate and required under ASC 805. The bargain purchase was primarily attributable to the increase in commodity price forecasts from the date we entered into the definitive purchase agreement with Great Western, February 26, 2022, to the closing date of the acquisition, May 6, 2022, when the fair value of crude oil and natural gas reserves acquired were determined. Additionally, the majority of the acquisition consideration was fixed and therefore did not fluctuate as a result of market increases or decreases between the date of entry into the agreement through the closing date.
The results of operations for the Great Western Acquisition since the closing date have been included on our condensed consolidated financial statements.
Pro Forma Information. The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the three months ended March 31, 2022, assuming the acquisition had been completed as of January 1, 2021. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.
The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that we believe are reasonable, including (i) our common stock issued to the owners of Great Western, (ii) the increase in depletion reflecting the relative fair values and production volumes attributable to Great Western’s properties and the revision to the depletion rate reflecting the reserve volumes acquired, (iii) adjustments to interest expense as a result of payoff of Great Western’s credit facility and secured senior notes, and (iv) the estimated tax impacts of the pro forma adjustments.
| | | | | | | | | | | | | | |
| | | | | | | | Three months ended March 31, 2022 |
| | | | | | | | |
| | | | | | | | (in thousands, except per share data) |
| Total revenue | | | | | | | | $ | 352,347 | |
| Net income (loss) | | | | | | | | (101,097) | |
| | | | | | | | |
| Earnings (loss) per share: | | | | | | | | |
| Basic | | | | | | | | $ | (1.01) | |
| Diluted | | | | | | | | (1.01) | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
NOTE 3 - REVENUE RECOGNITION
Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the periods presented:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
| Revenue by Commodity and Operating Region | | | | | | | | 2023 | | 2022 | | Percent Change |
| | | | | | | | (in thousands) |
| Crude oil | | | | | | | | | | | | |
| Wattenberg Field | | | | | | | | $ | 445,846 | | | $ | 451,911 | | | (1) | % |
| Delaware Basin | | | | | | | | 68,453 | | | 97,838 | | | (30) | % |
| Total | | | | | | | | 514,299 | | | 549,749 | | | (6) | % |
| Natural gas | | | | | | | | | | | | |
| Wattenberg Field | | | | | | | | 153,355 | | | 143,699 | | | 7 | % |
| Delaware Basin | | | | | | | | 7,687 | | | 19,425 | | | (60) | % |
| Total | | | | | | | | 161,042 | | | 163,124 | | | (1) | % |
| NGLs | | | | | | | | | | | | |
| Wattenberg Field | | | | | | | | 119,159 | | | 138,875 | | | (14) | % |
| Delaware Basin | | | | | | | | 18,784 | | | 30,630 | | | (39) | % |
| Total | | | | | | | | 137,943 | | | 169,505 | | | (19) | % |
| Crude oil, natural gas and NGLs | | | | | | | | | | | | |
| Wattenberg Field | | | | | | | | 718,360 | | | 734,485 | | | (2) | % |
| Delaware Basin | | | | | | | | 94,924 | | | 147,893 | | | (36) | % |
| Total | | | | | | | | $ | 813,284 | | | $ | 882,378 | | | (8) | % |
NOTE 4 - FAIR VALUE MEASUREMENTS
Recurring Fair Value Measurements
Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, interest rates, volatility factors and non-performance risk. Non-performance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties’ credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default exchange rates and the duration of each outstanding derivative position. We use our counterparties’ valuations to assess reasonableness of our fair value measurement.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
Our crude oil and natural gas fixed-price exchanges and basis exchanges are included in Level 2. Our collars are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of the dates indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | March 31, 2023 | | December 31, 2022 |
| Condensed Consolidated Balance Sheet Line Item | | Significant Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total | | Significant Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | | (in thousands) |
| Derivative assets | | | | | | | | | | | | | |
| Current | Fair value of derivatives | | $ | 38,181 | | | $ | 29,963 | | | $ | 68,144 | | | $ | 9,178 | | | $ | 22,785 | | | $ | 31,963 | |
| Non-current | Fair value of derivatives | | 36,750 | | | 9,747 | | | 46,497 | | | 20,439 | | | 5,123 | | | 25,562 | |
| Total | | | $ | 74,931 | | | $ | 39,710 | | | $ | 114,641 | | | $ | 29,617 | | | $ | 27,908 | | | $ | 57,525 | |
| | | | | | | | | | | | | |
| Derivative liabilities | | | | | | | | | | | | | |
| Current | Fair value of derivatives | | $ | (97,328) | | | $ | (28,201) | | | $ | (125,529) | | | $ | (214,171) | | | $ | (60,047) | | | $ | (274,218) | |
| Non-current | Fair value of derivatives | | (22,424) | | | (6,595) | | | (29,019) | | | (49,749) | | | (3,851) | | | (53,600) | |
| Total | | | $ | (119,752) | | | $ | (34,796) | | | $ | (154,548) | | | $ | (263,920) | | | $ | (63,898) | | | $ | (327,818) | |
The following table presents a reconciliation of our Level 3 commodity derivative assets and liabilities measured at fair value for the periods presented:
| | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
| | | | | | 2023 | | 2022 |
| | | | | | (in thousands) |
| Fair value of Level 3 instruments, net asset (liability) beginning of period | | | | | | $ | (35,990) | | | $ | (62,540) | |
| Changes in fair value included on condensed consolidated statements of operations line item: | | | | | | | | |
| Commodity price risk management gain (loss), net | | | | | | 40,796 | | | (209,771) | |
| Settlements included on condensed consolidated statement of operations line items: | | | | | | | | |
| Commodity price risk management gain (loss), net | | | | | | 108 | | | 46,100 | |
| Fair value of Level 3 instruments, net asset (liability) end of period | | | | | | $ | 4,914 | | | $ | (226,211) | |
| | | | | | | | |
| Net change in fair value of Level 3 unsettled derivatives included on condensed consolidated statements of operations line item: | | | | | | | | |
| Commodity price risk management gain (loss), net | | | | | | $ | 33,490 | | | $ | (159,118) | |
The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements.
Nonrecurring Fair Value Measurements
Acquisitions and Impairment of Long-lived Assets. We measure fair value using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy, on a nonrecurring basis for any acquired assets or businesses and to review our proved and unproved crude oil and natural gas properties for possible impairment. The most significant fair value determinations for non-financial assets and liabilities are related to crude oil and gas properties acquired. See Note 2 - Business Combination for additional information.
Asset Retirement Obligations. We measure the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
Other Financial Instruments
The carrying value of the financial instruments included in current assets and current liabilities approximates fair value due to the short-term maturities of these instruments.
Long-term Debt. The portion of our long-term debt related to our revolving credit facility approximates fair value, as the applicable interest rates are variable and reflective of market rates. We have elected not to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker or dealer quotes, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes as of the dates indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | March 31, 2023 | | December 31, 2022 |
| | Nominal Interest | | Estimated Fair Value | | Percent of Par | | Estimated Fair Value | | Percent of Par |
| | | | (in millions) | | | | (in millions) | | |
| 2024 Senior Notes | | 6.125 | % | | $ | 199.6 | | | 99.8 | % | | $ | 198.4 | | | 99.2 | % |
| 2026 Senior Notes | | 5.75 | % | | 732.8 | | | 97.7 | % | | 716.0 | | | 95.5 | % |
NOTE 5 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS
Objective and Strategy. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts such as collars, fixed-price exchanges and basis protection exchanges, to protect against price declines in future periods. We do not enter into derivative contracts for speculative or trading purposes.
We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in crude oil and natural gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of March 31, 2023, we had derivative instruments in place for a portion of our anticipated production in 2023 through 2025. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.
Effect of Derivative Instruments on the Condensed Consolidated Statements of Operations. The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations for the periods presented:
| | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
| Condensed Consolidated Statement of Operations Line Item | | | | | | 2023 | | 2022 |
| | | | | | (in thousands) |
| Commodity price risk management gain (loss), net | | | | | | | | |
| Net settlements | | | | | | $ | (86,254) | | | $ | (161,594) | |
| Net change in fair value of unsettled derivatives | | | | | | 230,386 | | | (406,461) | |
| Total commodity price risk management gain (loss), net | | | | | | $ | 144,132 | | | $ | (568,055) | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
Commodity Derivative Contracts. As of March 31, 2023, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is presented:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Collars | | Fixed-Price Swaps | | |
Commodity/ Index/
Maturity Period | | Quantity (Crude oil - MBbls Natural Gas - BBtu) | | Weighted Average
Contract Price | | Quantity (Crude Oil - MBbls Gas and Basis- BBtu) | | Weighted
Average
Contract
Price | | Fair Value March 31, 2023 (in thousands) |
| Floors | | Ceilings | | | |
| Crude Oil | | | | | | | | | | | | |
| NYMEX | | | | | | | | | | | | |
| 2023 | | 4,509 | | | $ | 60.52 | | | $ | 81.92 | | | 7,311 | | | $ | 67.40 | | | $ | (66,451) | |
| 2024 | | 1,545 | | | 63.16 | | | 87.44 | | | 6,126 | | | 70.59 | | | 3,773 | |
| 2025 | | — | | | — | | | — | | | 2,640 | | | 75.10 | | | 19,024 | |
| | | | | | | | | | | | |
| Total Crude Oil | | 6,054 | | | | | | | 16,077 | | | | | (43,654) | |
| | | | | | | | | | | | |
| Natural Gas | | | | | | | | | | | | |
| NYMEX | | | | | | | | | | | | |
| 2023 | | 18,765 | | | 3.44 | | | 5.80 | | | 29,666 | | | 3.04 | | | 25,165 | |
| 2024 | | 14,940 | | | 3.00 | | | 4.68 | | | 26,160 | | | 3.54 | | | (2,608) | |
| 2025 | | 4,980 | | | 3.50 | | | 5.00 | | | 14,940 | | | 4.42 | | | 1,823 | |
| | | | | | | | | | | | |
| | 38,685 | | | | | | | 70,766 | | | | | 24,380 | |
| CIG | | | | | | | | | | | | |
| 2023 | | — | | | — | | | — | | | 6,570 | | | 3.39 | | | 4,968 | |
| 2025 | | — | | | — | | | — | | | 4,800 | | | 3.10 | | | (4,584) | |
| | — | | | | | | | 11,370 | | | | | 384 | |
| | | | | | | | | | | | |
| Total Natural Gas | | 38,685 | | | | | | | 82,136 | | | | | 24,764 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Basis Protection - Natural Gas | | | | | | | | | | | | |
| CIG | | | | | | | | | | | | |
| 2023 | | | | | | | | 47,219 | | | (0.26) | | | (6,227) | |
| 2024 | | | | | | | | 41,100 | | | (0.31) | | | (11,306) | |
| 2025 | | | | | | | | 19,920 | | | (0.25) | | | (3,484) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Total Basis Protection - Natural Gas | | | | | | | | 108,239 | | | | | (21,017) | |
| | | | | | | | | | | | |
| Commodity Derivatives Fair Value | | | | | | | | | | | | $ | (39,907) | |
Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet. The balance sheet line items and fair value amounts of our derivative instruments are disclosed in Note 4 - Fair Value Measurements.
Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets.
The following table reflects the impact of netting agreements on gross derivative assets and liabilities:
| | | | | | | | | | | | | | | | | | | | |
| | Total Gross Amount Presented on the Balance Sheet | | Effect of Master Netting Agreements | | Total Net Amount |
| | (in thousands) |
As of March 31, 2023 | | | | | | |
| Derivative asset instruments, at fair value | | $ | 114,641 | | | $ | (89,682) | | | $ | 24,959 | |
| Derivative liability instruments, at fair value | | $ | 154,548 | | | $ | (89,682) | | | $ | 64,866 | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
Derivative Counterparties. Our commodity derivative instruments expose us to the risk of non-performance by our counterparties. We use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at March 31, 2023; however, this determination may change.
NOTE 6 - PROPERTIES AND EQUIPMENT, NET
The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization (“DD&A”) as of the dates indicated:
| | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| (in thousands) |
| Properties and equipment, net: | | | |
| Crude oil and natural gas properties | | | |
| Proved | $ | 11,696,780 | | | $ | 11,324,756 | |
| Unproved | 156,004 | | | 156,418 | |
| Total crude oil and natural gas properties | 11,852,784 | | | 11,481,174 | |
| Equipment and other | 83,054 | | | 72,151 | |
| Land and buildings | 25,406 | | | 25,406 | |
| Construction in progress | 750,460 | | | 716,302 | |
| Properties and equipment, at cost | 12,711,704 | | | 12,295,033 | |
| Accumulated DD&A | (5,201,392) | | | (5,001,678) | |
| Properties and equipment, net | $ | 7,510,312 | | | $ | 7,293,355 | |
Suspended Well Costs. The following table presents the changes in capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment for the periods presented:
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Year Ended December 31, 2022 |
| | (in thousands, except for number of wells) |
| Beginning balance | | $ | — | | | $ | — | |
| Additions to capitalized exploratory well costs pending the determination of proved reserves | | 2,538 | | | — | |
| Reclassifications to proved properties | | — | | | — | |
| Ending balance | | $ | 2,538 | | | $ | — | |
| | | | |
| Number of wells pending determination at period-end | | 3 | | — |
As of March 31, 2023, there were no exploratory well costs that were capitalized more than one year.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
NOTE 7 - ACCOUNTS RECEIVABLE, OTHER ACCRUED EXPENSES AND OTHER LIABILITIES
Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts, as of the dates indicated:
| | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| (in thousands) |
| Crude oil, natural gas and NGLs sales | $ | 398,324 | | | $ | 491,327 | |
| Joint interest billings | 56,088 | | | 46,633 | |
| Other | 25,715 | | | 13,796 | |
| Allowance for doubtful accounts | (5,344) | | | (5,445) | |
| Accounts receivable, net | $ | 474,783 | | | $ | 546,311 | |
Other Accrued Expenses. The following table presents the components of other accrued expenses as of the dates indicated:
| | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | (in thousands) |
| Employee benefits | | $ | 18,396 | | | $ | 29,288 | |
| Asset retirement obligations | | 25,864 | | | 25,986 | |
| Environmental expenses | | 23,529 | | | 25,666 | |
| Operating and finance leases | | 28,127 | | | 5,987 | |
| Other | | 16,378 | | | 19,155 | |
| Other accrued expenses | | $ | 112,294 | | | $ | 106,082 | |
Other Liabilities. The following table presents the components of other liabilities as of the dates indicated:
| | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | (in thousands) |
| Deferred midstream gathering credits | | $ | 141,976 | | | $ | 145,937 | |
| Production taxes | | 371,863 | | | 315,758 | |
| Operating and finance leases | | 63,496 | | | 41,815 | |
| Other | | 28,280 | | | 29,360 | |
| Other liabilities | | $ | 605,615 | | | $ | 532,870 | |
NOTE 8 - LONG-TERM DEBT
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $6 million and $6 million as of March 31, 2023 and December 31, 2022, respectively, consists of the following:
| | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| (in thousands) |
| Revolving credit facility due November 2026 | $ | 352,000 | | | $ | 370,000 | |
| 6.125% Senior Notes due September 2024 | 199,286 | | | 199,163 | |
| 5.75% Senior Notes due May 2026 | 745,205 | | | 744,847 | |
| Total debt, net of unamortized discount, premium and debt issuance costs | $ | 1,296,491 | | | $ | 1,314,010 | |
Revolving Credit Facility
In November 2021, we entered into a Fifth Amended and Restated Credit Agreement (the “Restated Credit Agreement”), which provides for a maximum credit amount of $2.5 billion, subject to certain limitations, an initial borrowing base of $2.4 billion and an elected commitment of $1.5 billion. The Restated Credit Agreement matures on the earlier to occur of (i) the end of the five-year term on November 2, 2026 or (ii) the date that is 91 days prior to the scheduled maturity of the 2026 Senior Notes if the aggregate outstanding principal amount of those notes exceeds $500 million and our commitment
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
utilization exceeds 50%. In the semi-annual redetermination that occurred in October 2022, the borrowing base increased from $3.0 billion to $3.5 billion as a result of the reserves acquired in the Great Western Acquisition; however, we maintained our elected commitment of $1.5 billion.
The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general business purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. The Restated Credit Agreement includes an investment grade period election pursuant to which we have an option to remove our borrowing base limitations and terminate the liens securing the Restated Credit Agreement when certain debt ratings are achieved.
As of March 31, 2023, we had a borrowing base of $3.5 billion, an elected commitment of $1.5 billion and availability under our revolving credit facility of $1.1 billion, net of $20 million of letters of credit outstanding.
The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the Secured Overnight Financing Rate (“SOFR”) for one month, plus a premium) or, at our election, a rate equal to SOFR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of March 31, 2023, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the SOFR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the maturity date of the revolving credit facility, unless the borrowing base falls below the outstanding balance. The Restated Credit Agreement also includes the ability to add certain sustainability-linked key performance indicators to be agreed upon between us, the administrative agent and a majority of the lenders and that may impact the applicable margin and commitment fee rate.
The revolving credit facility contains various restrictive covenants and compliance requirements, which include, among other things: (i) maintenance of certain financial ratios, as defined per the revolving credit facility, including a minimum current ratio of 1.0:1.0 and a maximum leverage ratio of 3.5:1.0; (ii) restrictions on the payment of cash dividends; (iii) limits on the incurrence of additional indebtedness; (iv) prohibition on the entry into commodity hedges exceeding a specified percentage of our expected production; and (v) restrictions on mergers and dispositions of assets. As of March 31, 2023, we were in compliance with all covenants related to our revolving credit facility.
Debt issuance costs related to our revolving credit facility were $13 million as of March 31, 2023 and December 31, 2022, and are included in other assets on our condensed consolidated balance sheets.
Senior Notes
The following table summarizes the face values, interest rates, maturity dates, semi-annual interest payment dates, and optional redemption periods related to our outstanding senior note obligations as of March 31, 2023:
| | | | | | | | | | | | | | |
| | 2024 Senior Notes | | 2026 Senior Notes |
| Outstanding principal amounts (in thousands) | | $ | 200,000 | | | $ | 750,000 | |
| Interest rate | | 6.125 | % | | 5.75 | % |
| Maturity date | | September 15, 2024 | | May 15, 2026 |
| Interest payment dates | | March 15, September 15 | | May 15, November 15 |
Redemption periods (1) | | September 15, 2022 | | May 15, 2024 |
_____________(1) At any time prior to the indicated dates, we have the option to redeem all or a portion of our senior notes of the applicable series at the redemption amounts specified in the respective senior note indenture plus accrued and unpaid interest to the date of redemption. On or after the indicated dates, we may redeem all or a portion of the senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus accrued and unpaid interest to the date of redemption.
The 2024 Senior Notes and the 2026 Senior Notes (collectively, the “Senior Notes”) are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.
Upon the occurrence of a “change of control”, as defined in the indentures for the Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase.
The indentures governing the Senior Notes contain covenants and restricted payment provisions that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of March 31, 2023, we were in compliance with all covenants and all restricted payment provisions related to our Senior Notes.
Our wholly-owned subsidiaries, PDC Permian, Inc. and Pioneer Water Pipeline LLC are each a guarantor of our obligations under our Senior Notes and our credit facility.
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties for the three months ended March 31, 2023:
| | | | | |
| (in thousands) |
| Beginning balance | $ | 197,651 | |
| Obligations incurred with development activities and other | 2,888 | |
| Obligations incurred with acquisition | — | |
| Accretion expense | 3,714 | |
| Revisions in estimated cash flows | — | |
| |
| Obligations discharged with asset retirements and divestitures | (8,329) | |
| Asset retirement obligations at end of period | 195,924 | |
| |
Current portion (1) | (25,864) | |
| Long-term portion | $ | 170,060 | |
_____________(1) The current portion of the asset retirement obligation is included in other accrued expenses on our condensed consolidated balance sheets.
Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at the time that the obligation is incurred. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
Contractual Obligations. We routinely enter into, extend or amend operating agreements in the ordinary course of business. We have long-term transportation, sales, processing and facility expansion agreements for pipeline capacity and water delivery and disposal commitments. There were no significant commitments entered into during the three months ended March 31, 2023. For details of our existing commitments, refer to Note 12 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data included in our 2022 Form 10-K.
Lease Commitments. In March 2023, we commenced two long-term drilling rig leases. We recognized right-of-use of assets and operating lease liabilities in an aggregate amount of $45 million. Additionally, we had short-term lease costs of $168 million and $75 million for the three months ended March 31, 2023 and March 31, 2022, respectively. Our short-term lease
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
costs include amounts that are capitalized as part of the cost of assets and are recorded as properties and equipment, or recognized as expense.
Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying condensed consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.
NOTE 11 - COMMON STOCK
Stock-Based Compensation Plans
2018 Equity Incentive Plan. In 2020, our stockholders approved an amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) to 7,050,000 shares. As of March 31, 2023, there were 3,515,571 shares available for grant under the 2018 Plan.
2010 Long-Term Equity Compensation Plan. Our Amended and Restated 2010 Long-Term Equity Compensation Plan, approved in 2013 (the “2010 Plan”), remains outstanding and we may continue to use the 2010 Plan to grant awards. No awards may be granted under the 2010 Plan on or after June 5, 2023. As of March 31, 2023, there were 241,841 shares available for grant under the 2010 Plan.
The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented:
| | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
| | | | | | 2023 | | 2022 |
| | | | | | (in thousands) |
| General and administrative expense | | | | | | $ | 6,218 | | | $ | 5,182 | |
| Lease operating expense | | | | | | 346 | | | 292 | |
| Total stock-based compensation expense | | | | | | $ | 6,564 | | | $ | 5,474 | |
Restricted Stock Units
The following table presents the changes in non-vested time-based RSUs to eligible employees, including executive officers, for the three months ended March 31, 2023:
| | | | | | | | | | | |
| Shares | | Weighted Average Grant-Date Fair Value per Share |
| Non-vested at beginning of period | 896,511 | | | $ | 42.05 | |
| Granted | 87,354 | | | 66.49 | |
| Vested | (156,353) | | | 32.01 | |
| Forfeited | (720) | | | 60.38 | |
| Non-vested at end of period | 826,792 | | | 46.51 | |
The weighted average grant-date fair value of restricted stock units was $66.49 and $57.57 for the three months ended March 31, 2023 and 2022, respectively. The total grant-date fair value of restricted stock units that vested for the three months ended March 31, 2023 and 2022 was $5 million and $6 million, respectively. Total compensation cost related to non-vested time-based awards and not yet recognized on our condensed consolidated statements of operations as of March 31, 2023 was $26 million. This cost is expected to be recognized over a weighted average period of 1.6 years.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
Performance Stock Units
The Compensation Committee awarded a total of 96,605 market-based PSUs to our executive officers during the three months ended March 31, 2023. In addition to continuous employment, the vesting of these PSUs is contingent on a combination of absolute stock performance and our total stockholder return (“TSR”), which is essentially our stock price performance, including any dividends, over a three-year period ending on December 31, 2025, as compared to the TSR of a group of peer companies and the S&P Mid Cap 400 Index over the same period. The PSUs will result in a payout between zero and 250 percent of the target PSUs awarded.
The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our common stock historical volatility, as well as that of a group of peer companies and the S&P Mid Cap 400 Index.
The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the periods presented:
| | | | | | | | | | | |
| Three Months Ended March 31, |
| 2023 | | 2022 |
| Expected term of award (in years) | 2.9 | | 2.9 |
| Risk-free interest rate | 4.4% | | 1.7% |
| Expected volatility | 66.7% | | 86.3% |
| Weighted average grant-date fair value per share | $110.18 | | $107.85 |
The following table presents the change in non-vested market-based awards during the three months ended March 31, 2023:
| | | | | | | | | | | | | | |
| | Shares | | Weighted Average Grant-Date Fair Value per Share |
| Non-vested at beginning of period | | 309,753 | | | $ | 71.76 | |
| Granted | | 96,605 | | | 110.18 | |
| Non-vested at end of period | | 406,358 | | | 80.89 | |
Total compensation cost related to non-vested market-based awards not yet recognized on our condensed consolidated statements of operations as of March 31, 2023 was $20 million. This cost is expected to be recognized over a weighted average period of 1.5 years.
Preferred Stock
We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our board of directors from time to time. Through March 31, 2023, no shares of preferred stock have been issued.
Stock Repurchase Program
In 2019, our board of directors approved a program pursuant to which we may acquire shares of our common stock from time to time. In February 2023, our board of directors approved a $750 million increase in the size of our stock repurchase program, resulting in an aggregate authorization of $2 billion. The stock repurchase program does not require any specific number of shares to be acquired and can be modified or discontinued by our board of directors at any time. Repurchases under the program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. Pursuant to the program, we repurchased 2.1 million and 1.3 million shares of outstanding common stock at a cost of $134 million and $85 million during the three months ended March 31, 2023 and 2022, respectively. As of March 31, 2023, $1.1 billion remained available under the program for repurchases of our outstanding common stock.
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
Dividends
For the three months ended March 31, 2023 and 2022, our dividends totaled $36 million or $0.40 per share of outstanding common stock and $24 million or $0.25 per share of outstanding stock, respectively. All RSUs and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities on our condensed consolidated balance sheets, until the recipients receive the equivalents upon vesting. Dividends declared were recorded as a reduction of retained earnings; however, if there were no retained earnings as of the date of declaration, dividends declared were recorded as a reduction of additional paid-in capital. Future dividend payments must be approved by our board of directors and will depend on our liquidity, financial requirements, and other factors considered relevant by our board.
NOTE 12 - INCOME TAXES
Our effective income tax rate for the three months ended March 31, 2023 and 2022 was 21.4 percent and 3.9 percent, respectively. For the three months ended March 31, 2023, our effective income tax rate was different from the U.S. statutory tax rate of 21 percent primarily due to the effects of state income taxes, partially offset by the benefit of excess stock-based compensation deductions and a change in the state effective tax rate. For the three months ended March 31, 2022, our effective income tax rate was different from the U.S. statutory tax rate of 21 percent primarily due to our valuation allowance against our deferred tax assets.
In August 2022, the Inflation Reduction Act (“IRA”) was enacted into law. The provisions of the IRA include (i) a new 15 percent corporate alternative minimum tax on corporations with average annual adjusted financial statement income over a three-year period in excess of $1.0 billion, (ii) a nondeductible 1 percent excise tax on the value of certain stock that a company repurchases, and (iii) various tax incentives for energy and climate initiatives. Each of these provisions is effective for tax years beginning after December 31, 2022. We continue to monitor updates to the IRA and the impact to our financial position, results of operations and liquidity, however, we do not believe it will have a material impact on our cash taxes for the 2023 tax year and we are still assessing the impact for subsequent years.
NOTE 13 - EARNINGS PER SHARE
Basic earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested stock-based employee awards and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.
The following table presents our weighted average basic and diluted shares outstanding for the periods presented:
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2023 | | 2022 |
| | | | | (in thousands) |
| Weighted average common shares outstanding - basic | | | | | 88,357 | | | 96,279 | |
| Dilutive effect of: | | | | | | | |
| RSUs and PSUs | | | | | 852 | | | — | |
| | | | | | | |
| Other equity-based awards | | | | | 19 | | | — | |
| Weighted average common shares and equivalents outstanding - diluted | | | | | 89,228 | | | 96,279 | |
| | | | | | | |
PDC ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2023
(Unaudited)
We reported a net loss for the three months ended March 31, 2022, as a result, our basic and diluted weighted average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive.
The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect for the periods presented:
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2023 | | 2022 |
| | | | (in thousands) |
| Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: | | | | | | | |
| RSUs and PSUs | | | | | 82 | | | 2,281 | |
| | | | | | | |
| Other equity-based awards | | | | | 32 | | | 143 | |
| Total anti-dilutive common share equivalents | | | | | 114 | | | 2,424 | |
NOTE 14 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | 2023 | | 2022 |
| | (in thousands) |
| Supplemental cash flow information: | | | | |
| Cash payments (receipts) for: | | | | |
| Interest, net of capitalized interest | | $ | 4,261 | | | $ | 3,825 | |
| Income taxes | | — | | | (233) | |
| | | | |
| Non-cash investing and financing activities: | | | | |
| Change in accounts payable related to capital expenditures | | $ | 52,304 | | | $ | 33,135 | |
| Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals | | 2,156 | | | 767 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our condensed consolidated financial statements and related notes included in Item 1. Financial Statements of this report. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements.
EXECUTIVE SUMMARY
March 31, 2023 Financial Overview of Operations and Liquidity
Market Conditions
The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment. In 2022 and the first quarter of 2023, crude oil and natural gas prices continued to be volatile. NYMEX WTI spot prices for crude oil reached a high of $130.50 per barrel in March 2022 and a low of $64.12 per barrel in March 2023. In addition, NYMEX Henry Hub spot prices for natural gas reached a high of $9.85 per MMBtu in August 2022 and a low of $1.93 per MMBtu in March 2023.
Crude Oil Markets
During the first quarter of 2023, crude oil pricing has decreased due to the net impact of higher supply and accumulation of global oil inventories, recession concerns, instability in the banking industry, uncertainties relating to the Russian invasion of Ukraine and changes in production by non-OPEC countries. In April 2023, OPEC+ announced a production cut which resulted to an increase in crude oil prices. Inflation rates in the first quarter of 2023 have started to soften, however, the U.S. Federal Reserve may continue to increase the benchmark federal funds interest rate in an effort to combat inflation. The magnitude and overall effectiveness of these actions remains uncertain. Overall, monetary policy changes can increase the risk of economic slowdown and/or lead to a recession. A slowdown or recession can cause a decrease in short-term or long-term demand for commodities, resulting in industry oversupply and a potential for lower commodity prices, which could impact our drilling program and further increase the volatility of our common stock price.
Natural Gas and NGL Markets
In addition to the crude oil market drivers noted above, natural gas and NGL prices are also affected by structural changes in supply and demand, growth in levels of liquified natural gas and liquified petroleum gas exports and deviations from seasonally normal weather. Europe’s shift away from Russia’s natural gas has led to Europe becoming increasingly dependent on U.S. LNG exports, creating new sources of demand for U.S. natural gas.
During the first quarter of 2023, natural gas and NGLs prices declined compared to prices during 2022 due to high inventories as a result of a warm winter and lower heating demand and continued growth in natural gas production across the U.S.
Financial Matters
Three months ended March 31, 2023 compared to three months ended December 31, 2022
•Production volumes decreased to 22.0 MMboe in the first quarter of 2023, a decrease of 3 percent compared to 22.7 MMboe in the fourth quarter of 2022, primarily driven by two fewer days in the first quarter of 2023 and the timing of our turn-in-line activities in both basins.
•Crude oil, natural gas and NGLs sales decreased to $813 million compared to $976 million in the fourth quarter of 2022 primarily due to a 14 percent decrease in weighted average realized commodity prices and a 3 percent decrease in production volumes between periods.
•Negative net cash settlements from our commodity derivative contracts decreased to $86 million in the first quarter of 2023 compared to $167 million in the fourth quarter of 2022 due to a decrease in commodity prices compared to our commodity derivative contract prices between periods.
•Combined revenues from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments decreased 10 percent to $727 million from $809 million in the fourth quarter of 2022.
•Net income increased to $414 million, or $4.64 per diluted share, for the first quarter of 2023 compared to $350 million, or $3.79 per diluted share, in the fourth quarter of 2022 primarily due to a $144 million commodity risk management gain in the first quarter of 2023 compared to a $100 million commodity risk management loss in the fourth quarter of 2022, partially offset by a decrease in crude oil, natural gas and NGLs sales of $163 million and increase in income tax expense of $17 million.
•Cash flows from operations decreased to $588 million compared to $688 million in the fourth quarter of 2022 primarily due to lower sales partially offset by lower net derivative cash settlement losses. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, decreased to $518 million compared to $604 million in the fourth quarter of 2022. Adjusted free cash flows, a non-U.S. GAAP financial measure, decreased to $101 million from $258 million in the fourth quarter of 2022 due to a decrease in adjusted cash flows from operations and an increase in capital expenditures between periods.
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.
Drilling and Completion Overview
During the first quarter of 2023, we operated three full-time drilling rigs and two full-time completion crews in the Wattenberg Field and one full-time drilling rig and completion crew in the Delaware Basin. Our total capital investments in crude oil and natural gas properties and midstream assets for the first quarter of 2023 were $417 million.
The following table summarize our drilling and completion activities for the three months ended March 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Operated Wells |
| | Wattenberg Field | | Delaware Basin | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| In-process as of December 31, 2022 | | 200 | | | 185 | | | 12 | | | 12 | | | 212 | | | 197 | |
| Wells spud | | 64 | | | 60 | | | 9 | | | 9 | | | 73 | | | 69 | |
| Wells turned-in-line | | (55) | | | (49) | | | (6) | | | (6) | | | (61) | | | (55) | |
| | | | | | | | | | | | |
| In-process as of March 31, 2023 | | 209 | | | 196 | | | 15 | | | 15 | | | 224 | | | 211 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling.
Capital Returns
Stock Repurchase Program. In February 2023, our board of directors approved a $750 million increase in the size of our stock repurchase program resulting in an aggregate authorization of $2 billion, which we currently anticipate fully utilizing by December 31, 2025. We repurchased 2.1 million shares of outstanding common stock at a cost of $134 million during the three months ended March 31, 2023. Effective January 1, 2023, the cost of stock repurchases includes related excise taxes pursuant to the terms of the IRA. As of March 31, 2023, $1.1 billion remained available for repurchases under the program.
Dividends. In February 2023, our board of directors approved an increase in the quarterly base dividend from $0.35 to $0.40 per share of outstanding common stock. For the three months ended March 31, 2023, our dividends totaled $36 million or $0.40 per share of outstanding common stock.
2023 Operational and Financial Outlook
We anticipate that our full-year 2023 production will range between 255,000 Boe and 265,000 Boe per day, of which approximately 82,000 Bbls to 86,000 Bbls is expected to be crude oil. Our planned 2023 capital investments in crude oil and natural gas properties, which we expect to be between $1,350 million to $1,450 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. Our capital budget and operating costs for 2023 may continue to be impacted by the volatility of commodity prices. Additionally, inflation has declined since December 2022, creating a modest decrease in certain capital costs during the first quarter of 2023; we anticipate this trend could continue through the second half of 2023.
We continue to move towards electrification in our operations to allow us to forego using internal combustion-power engines, which further helps us reduce our emissions. However, with this continued shift to electrification, we become more reliant on local third party grid power, which can be susceptible to capacity constraints, blackouts and infrastructure delays. These hazards could have an impact on our well development program as well as our daily production on existing wells.
We have 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 to best meet our short- and long-term corporate strategy. We may revise our 2023 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, 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 and acquisition and divestiture opportunities.
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in a mixture of urban, urban interfacing and rural areas of the core Wattenberg Field. Our 2023 capital investment program for the Wattenberg Field represents approximately 80 percent of our expected total capital investments in crude oil and natural gas properties. Our plan includes spudding and turning-in-line 200 to 225 operated wells. To meet our development plan, we intend on running three full-time horizontal drilling rigs and one full-time completion crew plus an intermittent completion crew during the year.
Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2023 are expected to be approximately 20 percent of our total capital investments. In 2023, we anticipate spudding 15 to 25 operated wells.
We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2023, we expect 2023 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Our first priority is to pay our quarterly base dividend of $0.40 per share. Then we expect to use approximately 60% or more of our remaining adjusted free cash flow, a non-U.S. GAAP financial measure, for share repurchases and special dividends, as needed. Any remaining adjusted free cash flows will be used for reducing debt, and other general corporate purposes.
Regulatory and Political Updates
In March 2023, the Colorado Governor directed the Colorado Oil and Gas Conservation Commission (“COGCC”) and the Colorado Department of Public Health and Environment (“CDPHE”) to develop a rule or rules by the end of 2024 requiring the upstream oil and gas sector operating in the ozone nonattainment area to achieve minimum emissions reductions of nitrogen oxides (“NOx”), one of ground level ozone’s primary precursors along with volatile organic compounds (“VOCs”), of 30% by 2025 and 50% by 2030; directing COGCC to solidify environmental best management practices addressing ozone; and directing COGCC to establish an environmental best practices program to incentivize operators to engage in greenhouse gas related environmental efforts. Substantially all of our producing properties in the Wattenberg Field are located in the nonattainment area.
We cannot predict whether future ballot initiatives or other legislation or regulation will be proposed that would limit the areas of the state in which drilling is permitted to occur or impose other requirements or restrictions.
Environmental, Social and Governance
We are committed to meaningful and measurable sustainability progress, focused on being a cleaner, safer and more socially responsible company. Our strategy is integrated into every level of our business and is overseen by our Environmental, Social, Governance and Nominating Committee at the board of directors and our internal Steering Committee, comprised of our senior leaders.
A core component of our sustainability initiatives is a dedicated drive to reduce our emissions. We have set aggressive targets to (i) reduce Scope 1 greenhouse gas emissions intensity, as defined by the Sustainability Accounting Standards Board, by 60% from 2020 levels by 2025 and 74% by 2030, (ii) reduce methane emissions intensity by 50% from 2020 levels by 2025 and 70% by 2030, and (iii) eliminate routine flaring, as defined by World Bank, by 2025. In March 2023, we completed our EPA annual filing for 2022 emissions and reported a 32% reduction in Scope 1 GHG emissions intensity and a 58% reduction in methane emissions intensity since 2021. Additionally, we eliminated routine flaring. As a result of our strong performance, we have exceeded our 2025 goal for methane emissions intensity and reached our 2025 goal of eliminating routine flaring. Accordingly, we are now reassessing our longer-term goals.
Additional information on our ESG practices, including sustainability goals, key metrics and progress achieved, can be found on the Sustainability page of our website at www.pdce.com. The information on our website, including the Sustainability reports, is not incorporated by reference in this report.
The SEC and other regulatory bodies are proposing a number of climate-change focused and broader ESG reporting requirements focused on emission reduction. When adopted, we will modify our disclosures accordingly.
Results of Operations
Summary of Operating Results
The following table presents selected information regarding our operating results:
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2023 | | December 31, 2022 | | | | Percent Change | | |
| (dollars in millions, except per unit data) | | | | |
| Production: | | | | | | | | | |
| Crude oil (MBbls) | 6,938 | | | 7,380 | | | | | (6) | % | | |
| Natural gas (MMcf) | 52,487 | | | 53,479 | | | | | (2) | % | | |
| NGLs (MBbls) | 6,286 | | | 6,430 | | | | | (2) | % | | |
| Crude oil equivalent (MBoe) | 21,971 | | | 22,723 | | | | | (3) | % | | |
| Average Boe per day (Boe) | 244,122 | | | 246,989 | | | | | (1) | % | | |
| | | | | | | | | |
| Crude Oil, Natural Gas and NGLs Sales: | | | | | | | | | |
| Crude oil | $ | 514 | | | $ | 607 | | | | | (15) | % | | |
| Natural gas | 161 | | | 224 | | | | | (28) | % | | |
| NGLs | 138 | | | 145 | | | | | (5) | % | | |
| Total crude oil, natural gas and NGLs sales | $ | 813 | | | $ | 976 | | | | | (17) | % | | |
| | | | | | | | | |
| Net Settlements on Commodity Derivatives | | | | | | | | | |
| Crude oil | $ | (35) | | | $ | (105) | | | | | (66) | % | | |
| Natural gas | (51) | | | (62) | | | | | (18) | % | | |
| Total net settlements on derivatives | $ | (86) | | | $ | (167) | | | | | (48) | % | | |
| | | | | | | | | |
| Average Sales Price (excluding net settlements on derivatives): | | | | | | | | | |
| Crude oil (per Bbl) | $ | 74.13 | | | $ | 82.24 | | | | | (10) | % | | |
| Natural gas (per Mcf) | 3.07 | | | 4.20 | | | | | (27) | % | | |
| NGLs (per Bbl) | 21.95 | | | 22.49 | | | | | (2) | % | | |
| Crude oil equivalent (per Boe) | 37.02 | | | 42.95 | | | | | (14) | % | | |
| | | | | | | | | |
| Average Costs and Expense (per Boe): | | | | | | | | | |
| Lease operating expense | $ | 3.33 | | | $ | 3.04 | | | | | 10 | % | | |
| Production taxes | 2.54 | | | 2.71 | | | | | (6) | % | | |
| Transportation, gathering and processing expense | 1.48 | | | 1.53 | | | | | (3) | % | | |
| General and administrative expense | 1.89 | | | 1.60 | | | | | 18 | % | | |
| Depreciation, depletion and amortization | 9.43 | | | 8.89 | | | | | 6 | % | | |
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| Lease Operating Expense by Operating Region (per Boe) | | | | | | | | | |
| Wattenberg Field | $ | 2.83 | | | $ | 2.52 | | | | | 12 | % | | |
| Delaware Basin | 7.14 | | | 7.03 | | | | | 2 | % | | |
Crude Oil, Natural Gas and NGLs Sales
Crude oil, natural gas and NGLs sales for the three months ended March 31, 2023 decreased compared to the three months ended December 31, 2022 due to the following factors:
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| |
| December 31, 2022 - March 31, 2023 | | |
| (in millions) |
| Change in: | | | |
| Production | $ | (44) | | | |
| | | |
| Average crude oil price | (56) | | | |
| Average natural gas price | (59) | | | |
| Average NGLs price | (4) | | | |
| Total change in crude oil, natural gas and NGLs sales revenue | $ | (163) | | | |
Crude Oil, Natural Gas and NGLs Production
The following table presents crude oil, natural gas and NGLs production for the periods presented:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | |
| Production by Operating Region | | March 31, 2023 | | December 31, 2022 | | | | Percent Change | | |
| Crude oil (MBbls) | | | | | | | | | | |
| Wattenberg Field | | 6,005 | | | 6,406 | | | | | (6) | % | | |
| Delaware Basin | | 933 | | | 974 | | | | | (4) | % | | |
| Total | | 6,938 | | | 7,380 | | | | | (6) | % | | |
| Natural gas (MMcf) | | | | | | | | | | |
| Wattenberg Field | | 46,720 | | | 47,502 | | | | | (2) | % | | |
| Delaware Basin | | 5,767 | | | 5,977 | | | | | (4) | % | | |
| Total | | 52,487 | | | 53,479 | | | | | (2) | % | | |
| NGLs (MBbls) | | | | | | | | | | |
| Wattenberg Field | | 5,628 | | | 5,799 | | | | | (3) | % | | |
| Delaware Basin | | 658 | | | 631 | | | | | 4 | % | | |
| Total | | 6,286 | | | 6,430 | | | | | (2) | % | | |
| Crude oil equivalent (MBoe) | | | | | | | | | | |
| Wattenberg Field | | 19,420 | | | 20,122 | | | | | (3) | % | | |
| Delaware Basin | | 2,551 | | | 2,601 | | | | | (2) | % | | |
| Total | | 21,971 | | | 22,723 | | | | | (3) | % | | |
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| Average crude oil equivalent per day (Boe) | | | | | | | | | | |
| Wattenberg Field | | 215,778 | | | 218,717 | | | | | (1) | % | | |
| Delaware Basin | | 28,344 | | | 28,272 | | | | | — | % | | |
| Total | | 244,122 | | | 246,989 | | | | | (1) | % | | |
Net production volumes for oil, natural gas and NGLs decreased 3 percent during the three months ended March 31, 2023 compared to the three months ended December 31, 2022, primarily driven by two fewer days in the first quarter of 2023 compared to the fourth quarter of 2022 and timing of our turn-in-line activities in both basins. Average crude oil equivalent per day was relatively flat between the three months ended March 31, 2023 and December 31, 2022.
The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented:
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| | Three Months Ended |
| Production Ratio by Operating Region | | March 31, 2023 | | December 31, 2022 | | |
| Wattenberg Field | | | | | | |
| Crude oil | | 31 | % | | 32 | % | | |
| Natural gas | | 40 | % | | 39 | % | | |
| NGLs | | 29 | % | | 29 | % | | |
| Total | | 100 | % | | 100 | % | | |
| Delaware Basin | | | | | | |
| Crude oil | | 36 | % | | 37 | % | | |
| Natural gas | | 38 | % | | 39 | % | | |
| NGLs | | 26 | % | | 24 | % | | |
| Total | | 100 | % | | 100 | % | | |
Midstream Capacity
Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, compression, 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 on a timely basis and at acceptable costs, our production and results of operations could be adversely affected.
The ultimate timing and availability of adequate infrastructure remains out of our control. Weather, regulatory developments, preventative routine maintenance and other factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time, we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to 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 from the Wattenberg Field and the Delaware Basin was not materially affected by midstream or downstream capacity constraints during the three months ended March 31, 2023. We continuously monitor infrastructure capacities versus producer activity and production volume forecasts. Increases in crude oil and natural gas prices in 2022 have incentivized producers in the Permian Basin to increase the level of drilling and completion activities. Despite the recent volatility in commodity prices, the number of drilling rigs has not materially declined, and the pace of production growth may lead to natural gas transportation constraints out of the Permian Basin in 2023. This may result in lower realized Waha natural gas prices, however, approximately half of our gas production in the Delaware Basin is dedicated to the Permian Highway Pipeline and is exposed to Houston-based gas pricing. This price diversification reduces the risk of a decrease in realized natural gas prices related to transportation constraints.
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.
The following table presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented:
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| | Three Months Ended | | |
| Weighted Average Realized Sales Price by Operating Region | | March 31, 2023 | | December 31, 2022 | | | | Percent Change | | |
| (excluding net settlements on derivatives) | | | | | |
| Crude oil (per Bbl) | | | | | | | | | | |
| Wattenberg Field | | $ | 74.25 | | | $ | 82.10 | | | | | (10) | % | | |
| Delaware Basin | | 73.35 | | | 83.15 | | | | | (12) | % | | |
| Weighted average price | | 74.13 | | | 82.24 | | | | | (10) | % | | |
| Natural gas (per Mcf) | | | | | | | | | | |
| Wattenberg Field | | $ | 3.28 | | | $ | 4.46 | | | | | (26) | % | | |
| Delaware Basin | | 1.33 | | | 2.07 | | | | | (36) | % | | |
| Weighted average price | | 3.07 | | | 4.20 | | | | | (27) | % | | |
| NGLs (per Bbl) | | | | | | | | | | |
| Wattenberg Field | | $ | 21.17 | | | $ | 21.24 | | | | | — | % | | |
| Delaware Basin | | 28.58 | | | 34.04 | | | | | (16) | % | | |
| Weighted average price | | 21.95 | | | 22.49 | | | | | (2) | % | | |
| Crude oil equivalent (per Boe) | | | | | | | | | | |
| Wattenberg Field | | $ | 36.99 | | | $ | 42.79 | | | | | (14) | % | | |
| Delaware Basin | | 37.20 | | | 44.17 | | | | | (16) | % | | |
| Weighted average price | | 37.02 | | | 42.95 | | | | | (14) | % | | |
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.
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 (“TGP”) expense.
Information related to the components and classifications of TGP expense on the condensed 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 TGP expense shown in the table below represents our approximate composite per barrel price for NGLs for the periods presented.
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Three Months Ended March 31, 2023 | | Average NYMEX Price | | Average Realized Price Before TGP Expense | | Average Realization Percentage Before TGP Expense | | Average TGP Expense (1) | | Average Realized Price After TGP Expense | | Average Realization Percentage After TGP Expense |
| Crude oil (per Bbl) | | $ | 76.13 | | | $ | 74.13 | | | 97 | % | | $ | 2.66 | | | $ | 71.47 | | | 94 | % |
| Natural gas (per MMBtu) | | 3.42 | | | 3.07 | | | 90 | % | | 0.18 | | | 2.89 | | | 85 | % |
| NGLs (per Bbl) | | 76.13 | | | 21.95 | | | 29 | % | | — | | | 21.95 | | | 29 | % |
| Crude oil equivalent (per Boe) | | 54.00 | | | 37.02 | | | 69 | % | | 1.28 | | | 35.74 | | | 66 | % |
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Three Months Ended December 31, 2022 | | Average NYMEX Price | | Average Realized Price Before TGP Expense | | Average Realization Percentage Before TGP Expense | | Average TGP Expense (1) | | Average Realized Price After TGP Expense | | Average Realization Percentage After TGP Expense |
| Crude oil (per Bbl) | | $ | 82.64 | | | $ | 82.24 | | | 100 | % | | $ | 2.55 | | | $ | 79.69 | | | 96 | % |
| Natural gas (per MMBtu) | | 6.26 | | | 3.94 | | | 63 | % | | 0.21 | | | 3.73 | | | 60 | % |
| NGLs (per Bbl) | | 82.64 | | | 22.49 | | | 27 | % | | — | | | 22.49 | | | 27 | % |
| Crude oil equivalent (per Boe) | | 64.95 | | | 42.34 | | | 65 | % | | 1.32 | | | 41.02 | | | 63 | % |
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____________(1)Average TGP expense excludes unutilized firm transportation fees of $0.20 per Boe and $0.21 per Boe for the three months ended March 31, 2023 and December 31, 2022, respectively.
Our average realization percentage for natural gas increased for the three months ended March 31, 2023 as compared to the three months ended December 31, 2022 primarily due to higher first of the month Colorado Interchange Gas (“CIG”) basis in January and February of 2023.
Commodity Price Risk Management
We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price exchanges, and basis protection exchanges on a portion of our estimated crude oil and natural gas production. For our commodity exchanges, we ultimately realize the fixed price value related to the swaps. See Note 5 - Commodity Derivative Financial Instruments in Item 1. Financial Statements included elsewhere in this report for a summary of our derivative positions as of March 31, 2023.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, and 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: | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | | | |
| (in millions) |
| Commodity price risk management gain (loss), net: | | | | | | | |
| Net settlements of commodity derivative instruments: | | | | | | | |
| Crude oil collars and fixed price exchanges | $ | (35) | | | $ | (105) | | | | | |
| Natural gas collars and fixed price exchanges | (5) | | | (69) | | | | | |
| Natural gas basis protection exchanges | (46) | | | 7 | | | | | |
| Total net settlements of commodity derivative instruments | (86) | | | (167) | | | | | |
| Change in fair value of unsettled commodity derivative instruments: | | | | | | | |
| Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments | 110 | | | 156 | | | | | |
| Crude oil collars and fixed price exchanges | 69 | | | (153) | | | | | |
| Natural gas collars and fixed price exchanges | 80 | | | 93 | | | | | |
| Natural gas basis protection exchanges | (29) | | | (29) | | | | | |
| Net change in fair value of unsettled commodity derivative instruments | 230 | | | 67 | | | | | |
| Total commodity price risk management gain (loss), net | $ | 144 | | | $ | (100) | | | | | |
The decrease in commodity prices during the three months ended March 31, 2023 compared to the three months ended December 31, 2022 resulted in an unrealized commodity risk management gain in the first quarter of 2023.
Lease Operating Expense
Lease operating expense (“LOE”) increased by 6 percent to $73 million for the three months ended March 31, 2023 compared to $69 million for the three months ended December 31, 2022. The period-over-period increase in LOE was primarily attributable to a $2 million increase in chemicals, power and fuel and a $1 million increase in regulatory and abandonment costs. LOE per Boe increased 10 percent to $3.33 for the three months ended March 31, 2023 from $3.04 for the three months ended December 31, 2022. The increase in LOE per Boe was primarily due to the factors outlined above and a 3 percent decrease in production volumes between periods.
Production Taxes
Production taxes 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 based upon activity levels and relative commodity prices from year-to-year.
Production taxes decreased 9 percent to $56 million for the three months ended March 31, 2023 compared to $61 million for the three months ended December 31, 2022. Production taxes per Boe decreased 6 percent to $2.54 for the three months ended March 31, 2023 compared to $2.71 for the three months ended December 31, 2022. The decrease in production taxes was primarily due to a 14 percent decrease in weighted average realized sales prices between periods and a 3 percent decrease in production volumes between periods. The decrease in production taxes per Boe was primarily due to a decrease in weighted average realized sales prices between periods.
Transportation, Gathering and Processing Expense
TGP expense decreased 6 percent to $33 million for the three months ended March 31, 2023 compared to $35 million for the three months ended December 31, 2022. The decrease in TGP expense between periods was primarily due to a 3 percent decrease in production volumes and a $1 million decrease in shortfall fees relating to our delivery commitments. TGP expense per Boe decreased 3 percent to $1.48 for the three months ended March 31, 2023 compared to $1.53 for the three months ended December 31, 2022.
General and Administrative Expense
General and administrative expense increased 14 percent to $41 million for the three months ended March 31, 2023 compared to $36 million for the three months ended December 31, 2022. The increase between periods was primarily due to a $2 million release of our accrual related to our consent decree which terminated in the fourth quarter of 2022 and a $2 million increase in salaries, wages and benefits related to the timing of our employee incentive programs.
Depreciation, Depletion and Amortization Expense
DD&A expense 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 $205 million for the three months ended March 31, 2023 compared to $200 million for the three months ended December 31, 2022. The increase in DD&A expense was primarily due to a 6 percent increase in the weighted average depletion expense rate partially offset by a 3 percent decrease in production volumes between periods.
The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following:
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| | December 31, 2022 - March 31, 2023 | | |
| | (in millions) |
| Increase (decrease) in production | | $ | (7) | | | |
| Increase (decrease) in weighted average depletion rates | | 12 | | | |
| Total increase (decrease) in DD&A expense related to crude oil and natural gas properties | | $ | 5 | | | |
The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties for the periods presented:
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| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | | | |
| (per Boe) |
| Operating Region/Area | | | | | | | |
| Wattenberg Field | $ | 9.04 | | | $ | 8.56 | | | | | |
| Delaware Basin | 11.50 | | | 10.66 | | | | | |
| Total weighted average DD&A expense rate | 9.32 | | | 8.80 | | | | | |
Interest Expense, net
Interest expense, net decreased 6 percent to $15 million for the three months ended March 31, 2023 compared to $16 million for the three months ended December 31, 2022. The decrease between periods was primarily due to an increase in capitalized interest as a result of an increase in interest rates and drilling activity in both basins.
Provision for Income Taxes
We recorded income tax expense of $113 million and $96 million for the three months ended March 31, 2023 and December 31, 2022, respectively, resulting in an effective income tax rate of 21.4 percent and 20.3 percent on the respective pre-tax income. For the three months ended March 31, 2023, our effective income tax rate was different from the statutory U.S. statutory tax rate of 21 percent primarily due to the effects of state income taxes, partially offset by the benefit of excess stock-based compensation deductions and a change in the state effective tax rate. For the three months ended December 31, 2022, our effective income tax rate was different from the U.S. statutory tax rate of 21 percent primarily due to changes in our valuation allowance against our deferred tax assets and due to the effects of state income taxes.
In August 2022, the IRA was enacted into law. The provisions of the IRA include (i) a new 15 percent corporate alternative minimum tax on corporations with average annual adjusted financial statement income over a three-year period in excess of $1.0 billion, (ii) a nondeductible 1 percent excise tax on the value of certain stock that a company repurchases, and (iii) various tax incentives for energy and climate initiatives. Each of these provisions are effective for tax years beginning after December 31, 2022. We continue to monitor updates to the IRA and the impact to our financial position, results of operations
and liquidity, however, we do not believe it will have a material impact on our cash taxes for the 2023 tax year, and we are still assessing the impact for subsequent years.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors impacting a net income of $414 million and $350 million for the three months ended March 31, 2023 and December 31, 2022, respectively, are discussed above.
Adjusted net income, a non-U.S. GAAP financial measure, was $233 million and $297 million for the three months ended March 31, 2023 and December 31, 2022, respectively. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income. 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
Overview
Our primary sources of liquidity are cash and cash equivalents, cash flows from operating activities, unused borrowing capacity from our revolving credit facility, proceeds raised in debt and equity capital market transactions, and other sources, such as asset sales.
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, capital returns and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. These activities typically result in a working capital deficit; however, we do not believe that our working capital deficit as of March 31, 2023 is an indication of a lack of liquidity. We had working capital deficits of $751 million as of March 31, 2023 and $826 million as of December 31, 2022. The decrease in working capital deficit since December 31, 2022 was primarily due to a decrease in fair value of our current net derivative liabilities between periods. 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.
From time to time, we may seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise.
Liquidity
Our cash and cash equivalents were $17 million at March 31, 2023 and availability under our revolving credit facility was $1.1 billion, providing for a total liquidity position of $1.1 billion as of March 31, 2023. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests.
Our material short-term and long-term cash requirements consist primarily of capital expenditures, payments of contractual obligations, dividends, share repurchases, income taxes and working capital obligations. If commodity prices increase, our working capital requirements may increase due to higher operating costs and negative settlements on our outstanding commodity derivative contracts. Funding for these requirements may be provided by any combination of our capital resources previously outlined.
Based on our current production forecast for 2023, we expect 2023 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. In addition, 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 fund our planned activities through the 12-month period following the filing of this report. We also believe that we will have sufficient expected cash flows from operations to allow us to execute our capital return plan. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board.
Our material long-term cash requirements relate to debt obligations and interest payments, commodity derivative contract liabilities, production taxes, operating and finance leases, asset retirement obligations, and firm transportation and processing agreements. There are no significant changes to our material cash requirements arising from contractual obligations since December 31, 2022.
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 (a) to maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 3.5:1.0. 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 and excludes the fair value of commodity derivative assets. Additionally, the current ratio covenant calculation allows us to exclude the fair value of commodity derivative liabilities and 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 March 31, 2023, we were in compliance with all covenants in the revolving credit facility with a current ratio of 1.4:1.0 and a leverage ratio of 0.5:1.0.
We expect to remain in compliance with the covenants under our credit facility and our Senior Notes throughout the 12-month period following the filing of this report.
Cash Flows
Our cash flows from operating, investing and financing activities are as follows:
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| | Three Months Ended March 31, |
| | 2023 | | 2022 |
| | (in thousands) |
| Cash flows from operating activities | | $ | 588,323 | | | $ | 489,048 | |
| Cash flows from investing activities | | (372,439) | | | (236,534) | |
| Cash flows from financing activities | | (204,935) | | | (115,186) | |
| Net increase (decrease) in cash and cash equivalents | | $ | 10,949 | | | $ | 137,328 | |
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 expense. Cash flows from operating activities increased by $99 million to $588 million during the three months ended March 31, 2023 compared to $489 million during the three months ended March 31, 2022. The increase between periods was primarily due to a $75 million decrease in net cash derivative settlement losses and the timing of receivable collections, partially offset by a $69 million decrease in revenue from crude oil, natural gas and NGLs sales and the timing vendor payments.
Adjusted cash flows from operations, a non-U.S. GAAP financial measure, decreased by $21 million to $518 million during the three months ended March 31, 2023 from $539 million during the three months ended March 31, 2022. The decrease 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. Adjusted free cash flow, a non-U.S. GAAP financial measure, decreased by $218 million during the three months ended March 31, 2023 to $101 million compared to $319 million during the three months ended March 31, 2022 primarily due to an increase in capital investments in crude oil and natural gas properties as a result of our 2023 development plan.
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. As 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 $372 million during the three months ended March 31, 2023 was primarily due to our drilling and completion activities of $362 million. Net cash used in investing activities of $237 million during the three months ended March 31, 2022 was primarily related to our drilling and completion activities of $187 million and a $50 million deposit in escrow relating to the Great Western Acquisition.
Financing Activities. Net cash used in financing activities of $205 million during the three months ended March 31, 2023 was primarily due to (i) the repurchase of 2.1 million shares of our common stock for $130 million pursuant to our stock repurchase program, (ii) dividend payments totaling $37 million, (iii) purchase of treasury shares for employee stock-based compensation tax withholding obligations amounting to $19 million and (iv) $18 million in net payments on our credit facility outstanding balance. In February 2023, our board of directors approved a $750 million increase in the size of our stock repurchase program resulting in an aggregate authorization of $2 billion. Repurchases of our common stock may extend through the end of 2025 based on current market conditions, although the board of directors could elect to suspend or terminate the program at any time, including if certain share price parameters are not achieved.
Net cash used in financing activities of $115 million during the three months ended March 31, 2022 was primarily due to the repurchase of 1.3 million shares of our common stock for $81 million pursuant to our stock repurchase program and dividend payments totaling $25 million.
Subsidiary Guarantors
PDC Permian, Inc., a Delaware corporation (“Permian”), and Pioneer Water Pipeline LLC, a Delaware limited liability company (“Pioneer” and together with “Permian”, the “Guarantors”), each a wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”). Permian holds our assets located in the Delaware Basin. Pioneer holds certain water midstream assets located in the Wattenberg Field. The Senior Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantors. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions.
The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (iii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.
The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method.
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| | As of/Three Months Ended | | As of/Year Ended |
| | March 31, 2023 | | December 31, 2022 |
| | Issuer | | Guarantors | | Issuer | | Guarantors |
| | (in millions) |
| Assets | | | | | | | | |
| Current assets | | 518 | | | 54 | | | 539 | | | 55 | |
| Intercompany accounts receivable, guarantor subsidiary | | — | | | 323 | | | — | | | 334 | |
| Investment in guarantor subsidiary | | 1,767 | | | — | | | 1,767 | | | — | |
| Properties and equipment, net | | 6,444 | | | 1,067 | | | 6,286 | | | 1,007 | |
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| | As of/Three Months Ended | | As of/Year Ended |
| | March 31, 2023 | | December 31, 2022 |
| | Issuer | | Guarantors | | Issuer | | Guarantors |
| | (in millions) |
| Other non-current assets | | 124 | | | 54 | | | 88 | | | 8 | |
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| Liabilities | | | | | | | | |
| Current liabilities | | 1,217 | | | 105 | | | 1,362 | | | 59 | |
| Intercompany accounts payable | | 323 | | | — | | | 334 | | | — | |
| Long-term debt | | 1,297 | | | — | | | 1,314 | | | — | |
| Other non-current liabilities | | 1,244 | | | 182 | | | 1,102 | | | 164 | |
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| Statement of Operations | | | | | | | | |
| Crude oil, natural gas and NGLs sales | | 718 | | | 95 | | | 3,639 | | | 657 | |
| Commodity price risk management gain (loss), net | | 144 | | | — | | | (464) | | | — | |
| Total revenues | | 863 | | | 95 | | | 3,180 | | | 666 | |
Production costs (1) | | 301 | | | 67 | | | 1,167 | | | 282 | |
Gross profit (2) | | 416 | | | 28 | | | 2,472 | | | 376 | |
| Impairment of properties and equipment | | 1 | | | — | | | 1 | | | 6 | |
| Net income (loss) | | 388 | | | 26 | | | 1,420 | | | 359 | |
____________(1)Production costs include LOE, TGP, production taxes and DD&A.
(2)Gross profit is calculated as crude oil, natural gas and NGLs sales less production costs.
Recent Accounting Pronouncements
There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of March 31, 2023.
Critical Accounting Policies and Estimates
The preparation of the accompanying condensed consolidated financial statements in conformity with U.S. GAAP required management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.
There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the consolidated financial statements and accompanying notes contained in our 2022 Form 10-K filed with the SEC on February 22, 2023.
Reconciliation of Non-U.S. GAAP Financial Measures
We use “adjusted cash flows from operations”, “adjusted free cash flow (deficit)” and “adjusted net income (loss)”, 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.
In the first quarter of 2023, we determined that adjusted earnings before interest expense, taxes, DD&A and exploration expense (“Adjusted EBITDAX”) is no longer used as a non-U.S. GAAP metric by our management to monitor our financial performance. As a result, we removed the Adjusted EBITDAX disclosure for the period ending March 31, 2023, as well as related comparative information of prior periods.
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 and to return capital to 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 adjusted 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 adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our 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.
The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure for the periods presented:
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| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | | | March 31, 2022 |
| (in millions) |
| Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow: | | | | | | | |
| Net cash from operating activities | $ | 588 | | | $ | 688 | | | | | $ | 489 | |
| Changes in assets and liabilities | (70) | | | (84) | | | | | 50 | |
| Adjusted cash flows from operations | 518 | | | 604 | | | | | 539 | |
| Capital expenditures for development of crude oil and natural gas properties | (362) | | | (296) | | | | | (187) | |
| Capital expenditures for midstream assets | (4) | | | (1) | | | | | — | |
| Change in accounts payable related to capital expenditures for oil and gas development activities and midstream assets | (51) | | | (49) | | | | | (33) | |
| Adjusted free cash flow | $ | 101 | | | $ | 258 | | | | | $ | 319 | |
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| Net income (loss) to adjusted net income (loss): | | | | | | | |
| Net income (loss) | $ | 414 | | | $ | 350 | | | | | $ | (32) | |
| Loss (gain) on commodity derivative instruments | (144) | | | 100 | | | | | 568 | |
| Net settlements on commodity derivative instruments | (86) | | | (167) | | | | | (161) | |
Tax effect of above adjustments | 49 | | | 14 | | | | | (16) | |
| Adjusted net income (loss) | $ | 233 | | | $ | 297 | | | | | $ | 359 | |
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market-Sensitive Instruments and Risk Management
We are exposed to market risks associated with commodity price risk, interest rate risk and credit risk. Recent inflationary trends and the possibility of a recession could impact each of these market risks. We have established risk management processes to monitor and manage these market risks.
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 and the terms of our credit facility, 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 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.
As of March 31, 2023, we had a net liability derivative position of $39.9 million related to our commodity price risk derivatives. Our outstanding derivative contracts, related maturities and fair values are disclosed in Note 5 - Commodity Derivative Financial Instruments included elsewhere in this report. Based on a sensitivity analysis as of March 31, 2023, we estimate that a hypothetical 10 percent increase in natural gas prices, 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 an increase in the fair value of our net derivative liabilities of $115 million, whereas a ten percent decrease in prices would have resulted in a decrease in fair value of our net derivative liabilities of $114 million. The potential increase in the fair value of our net derivative liabilities 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.
Interest Rate Risk
Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2024 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, such changes could affect our results of operations and cash flows if we elected to repurchase or otherwise retire fixed-rate debt at prices different than carrying values.
As of March 31, 2023, we had $352 million in outstanding borrowings under our revolving credit facility with a weighted average interest of 6.5% for the three months ending March 31, 2023. Details of the interest rate terms of our credit facility are disclosed in Note 8 - Long-term Debt included elsewhere in this report. If market interest rates would have increased or decreased one percent, our interest expense for the three months ended March 31, 2023 would have changed by approximately $1 million.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure. When exposed to significant credit risk, we analyze the 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 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, instability in the banking industry 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.
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.
Disclosure of Limitations
Because the information above included only those exposures that existed at March 31, 2023, it does not consider those exposures or positions which could arise after that date. As 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.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of March 31, 2023, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2023.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended March 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.