PDC Energy Inc PDCE

DENVER, Feb. 24, 2021 (GLOBE NEWSWIRE) -- PDC Energy, Inc. (“PDC” or the “Company”) (Nasdaq:PDCE) today announced its 2020 fourth quarter and full-year operating and financial results. The Company also provided detailed 2021 guidance and a preliminary multi-year outlook.

2020 Fourth Quarter and Full-Year Highlights:

• Net cash from operating activities of approximately $220 million and $870 million in the fourth quarter and full-year 2020, respectively. Adjusted cash flows from operations, a non-U.S. GAAP metric defined below, of approximately $270 million and $920 million for the comparable periods.
  
  
• Oil and gas capital investments of approximately $110 million and $520 million for the fourth quarter and full-year 2020, respectively.
  
  
• Approximately $160 million and $400 million of adjusted free cash flow (“FCF”), a non-U.S. GAAP metric defined as net cash flows from operating activities, excluding changes in working capital, less oil and gas capital investments.
  
  
• Reduced total debt by approximately $300 million since closing the SRC Energy, Inc. ("SRC") acquisition, resulting in a year-end leverage ratio, as defined by the Company’s revolving credit facility, of approximately 1.7 times.
  
  
• Implemented initiatives aimed at decreasing both total emissions and flaring intensity as the Company is aligned with the World Bank in achieving zero routine flaring by 2030, with aspirations to reach this goal sooner. In 2020, the Company flared approximately 0.2 percent of its total gross natural gas production, including approximately 1.6 percent of gross Delaware Basin natural gas production, an improvement of more than 50 percent compared to 2019.
  

2021 Guidance Highlights:

• Oil and gas capital investments expected between $500 and $600 million.
  
  
• Anticipate generating more than $400 million of FCF assuming $45 WTI crude oil, $2.50 NYMEX natural gas and NGL realizations of approximately $12 per barrel.
  
  
• The Company plans to reinvest less than 60 percent of its adjusted cash flows from operations into oil and gas capital development with the remaining portion being allocated to reduce absolute debt by more than $200 million and to return more than $120 million to shareholders through its reinstated stock repurchase program and planned dividend program, which is anticipated to commence mid-year.
  
  
• Total production and oil production expected between 190,000 and 200,000 barrels of oil equivalent (“Boe”) per day and 64,000 and 68,000 barrels (“Bbls”) of crude oil per day.
  

CEO Commentary

President and Chief Executive Officer Bart Brookman commented, “As is the case for many, Covid-19 has had a lasting impact on the way in which we live as individuals and operate as an organization and I'm incredibly proud of our team's ability to adapt, persevere and succeed in what was an incredibly unique and challenging year. Through it all, we continued to make meaningful strides in both our operating efficiencies and financial results, as evidenced by the significant improvements in our cost structure and the nearly $400 million of free cash flow in 2020.”

"Importantly, the successes of 2020 have positioned PDC to deliver an unmatched three-year outlook highlighted by the ability to generate well over $1 billion of free cash flow at prices below the current strip. Additionally, PDC's commitment to significantly reduce absolute debt levels, coupled with the stock repurchase program and planned quarterly dividend, offer an unrivaled shareholder-friendly, three-pronged approach to sustainable value-creation."

2020 Operations Update

In 2020, the Company invested approximately $520 million in the development of its crude oil and natural gas properties and produced 68.4 MMBoe, or approximately 187,000 Boe per day including oil production of 23.7 MMBbls or 65,000 Bbls per day. Both total production and oil production were significant increases compared to 2019 due to the merger with SRC in January 2020. In the fourth quarter, the Company’s oil and gas capital investments of approximately $110 million contributed to total production of 16.6 MMBoe and oil production of 5.6 MMBbls.

In Wattenberg, the Company invested approximately $425 million to spud 105 wells and turn-in-line (“TIL”) 124 wells, including 19 spuds and 23 TILs in the fourth quarter. Production for the year averaged 157,000 Boe per day with oil accounting for approximately 53,500 Bbls per day, while production in the fourth quarter averaged approximately 152,000 Boe per day and 50,000 Bbls per day, respectively. PDC exited 2020 with approximately 200 drilled but uncompleted wells (“DUC”) and 300 approved drilling permits. The combined total of DUCs and permits represents over three years of future TILs at the current and expected future pace.

In the Delaware Basin, PDC invested approximately $95 million to spud eight wells and TIL 13 wells. Production for the year averaged approximately 30,000 Boe per day and 11,500 Bbls per day, while fourth quarter production averaged approximately 28,000 Boe per day and 11,000 Bbls per day, respectively.

PDC’s estimated proved reserves as of year-end 2020 were 731 MMBoe, with proved developed reserves accounting for approximately 44 percent of the total.  Year-end 2020 proved reserves reflect a decrease of approximately 19 percent compared to PDC and SRC pro forma year-end 2019 proved reserves of approximately 905 MMBoe.  The year-over-year decrease is predominately due to the Company’s shift in emphasis to a FCF generation business model, which resulted in a slower development pace with reduced total proved reserves in accordance with the Securities and Exchange Commission’s five-year rule. The majority of the impacted reserves were re-classified as probable reserves; however, the Company anticipates they will be promoted to proved reserves in future years.

2021 Capital Investment and Financial Guidance

PDC anticipates 2021 capital investments of $500 to $600 million to generate between 190,000 and 200,000 Boe per day and 64,000 to 68,000 Bbls per day, reflecting approximately five percent total production growth and flat oil production on a year-over-year basis. The Company’s revised production ranges reflect an increase in expected total production and no change in expected oil production compared to prior guided ranges due to sooner than previously planned completions of large, gassier Plains wells in Wattenberg and the delayed completions of oilier Delaware basin wells from January to March.

PDC expects its capital program to generate more than $400 million of FCF, assuming $45 per Bbl WTI, $2.50 per Mcf NYMEX natural gas and NGL realizations of $12 per Bbl. In late February 2021, PDC reduced its debt balance to below its near-term target of $1.5 billion and subsequently reinstated its stock repurchase program. Also, in February, the Company’s Board of Directors approved the implementation of a quarterly dividend program expected to commence in mid-2021 with an initial target of a one to two percent yield. As part of PDC’s long-term strategy, it is targeting 2021 debt reduction of more than $200 million and shareholder returns, consisting of stock repurchases and dividend payments, of at least $120 million. The remaining projected FCF is expected to flex between further debt reduction, additional shareholder returns, working capital needs and business development initiatives as dictated by macro-level conditions such as commodity prices and PDC share price.

Keeping percentage realizations constant, the Company projects commodity price fluctuations to change its estimated adjusted cash flows from operations as follows:

In Wattenberg, the Company expects to utilize one full-time completion crew, one full-time drilling rig and one intermittent spudder rig. Well costs are expected to average approximately $360 per lateral foot, a decrease of ten percent compared to approximately $400 per lateral foot in 2020. Updated projected well costs reflect multiple operating efficiencies realized in 2020, including average spud-to-spud extended-reach lateral (“XRL”) drill times of five days and more than 20 completions stages per day on average. Further, PDC plans to submit permit applications for more than 500 future drilling locations through two oil and gas development plans and one comprehensive area plan.  If approved, these locations, combined with the Company’s current DUC and approved permit backlog, represent all projected TILs through 2026.

In the Delaware basin, XRL drilling, completion and facility costs are expected to average less than $800 per foot, an improvement of more than five percent compared to 2020 costs of approximately $850 per foot. Additional basin-level details, including year-end inventory, projected capital spend and estimated spud and TIL ranges can be found in the Company’s investor presentation at www.pdce.com.

Environmental, Social and Governance (“ESG”) Highlights

In 2021, PDC plans to undertake several initiatives aimed at further improving its ESG best-practices. From an environmental standpoint, the Company expects plugging and reclamation of more than 350 legacy Wattenberg vertical wells, while in the Delaware basin, the Company plans to install hydrogen sulfide treatment earlier in the producing life of the well. These initiatives are aimed at decreasing both total emissions and flaring intensity as the Company is aligned with the World Bank in achieving zero routine flaring by 2030, with aspirations to reach this goal sooner.  

As highlighted in a separate press release issued on February 22, PDC continued its board refreshment initiatives through the appointment of Diana L. Sands, effective February 18, and the nomination of Carlos A. Sabater at the Company’s 2021 Annual Meeting of Shareholders in May 2021. Also, in February, the Company’s Board of Directors approved executive compensation metrics tied to health and safety, increased alignment with Sustainability Accounting Standards Board (“SASB”) standards, establishment of reduced greenhouse gas and methane emission targets and Board diversity and refreshment initiatives.

The table below provides additional 2021 financial guidance:

Quarterly Commentary

PDC plans to invest approximately 60 percent of its full-year capital budget in the first half of the year, with anticipated first quarter investments of less than $150 million. The remaining 40 percent of full-year investments are expected to be split relatively evenly between the third and fourth quarters.

Total daily production in the first quarter is expected to decline zero to five percent compared to the fourth quarter of 2020, while daily oil production is expected to decline five to ten percent. Each anticipated decline includes the projected impact related to weather and associated downtime in mid-February. The disproportionate decrease in oil production compared to total production is primarily due to a lack of Delaware completions in the second half of 2020, delaying 2021 Delaware completions to March from January and a focus in the gassier Wattenberg Plains area at the end of 2020 and beginning of 2021. Daily volumes, for both total production and oil production, are expected to increase in the second and third quarters before flattening in the fourth quarter at levels ten to 15 percent greater than the fourth quarter of 2020.

Finally, PDC expects to generate meaningful FCF in each quarter, with more than $75 million expected in the first quarter and approximately 65 percent of the total 2021 FCF expected in the second half of the year.

Multi-Year Outlook and Return of Capital Initiatives

The Company’s outlook through 2023 is predicated on generating substantial levels of FCF through consistent capital investments expected between $500 and $600 million per year while delivering a mid-single digit compound annual growth rate in both total production and oil production. Assuming $45 per Bbl WTI, $2.50 per Mcf NYMEX natural gas and $12 NGL realizations, PDC projects to generate more than $400 million of FCF in each of the next three years and between $1.3 billion and $1.5 billion of cumulative FCF. The projected cumulative FCF represents approximately 50 percent of the Company’s market cap and nearly 33 percent of its enterprise value as of February 19, 2021. The Company has an immaterial Federal acreage position and projects the combination of its current DUCs and approved drilling permits to be sufficient in executing its anticipated Wattenberg development plan over the next three years.

Under the same price assumptions, PDC projects to reinvest less than 60 percent of its adjusted cash flows from operations in the development of crude oil and natural gas. More than 15 percent of its adjusted cash flows from operations is expected to be allocated to debt reduction as the Company targets a long-term sustainable leverage ratio below 1.0x. At least ten percent of its adjusted cash flows from operations is expected to be allocated to shareholder-friendly initiatives, including its stock repurchase program and recently approved dividend program expected to commence mid-2021. Similar to 2021 expectations, remaining cash flows are expected to flex between further debt reduction, additional shareholder returns, working capital needs and business development initiatives as dictated by macro-level conditions such as commodity prices and PDC share price.

2020 Oil and Gas Production, Sales and Operating Cost Data

Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, decreased to $1.2 billion in 2020 compared to sales of $1.3 billion in 2019. The decrease in sales between periods was due to a 36 percent reduction in sales price to $16.86 per Boe from $26.46 per Boe being partially offset by a 38 percent increase in production. The increase in production between periods was due to the merger with SRC in January 2020, while the decrease in sales price per Boe was driven by decreases of 35 percent, 17 percent and 26 percent decreases in weighted-average realized oil, natural gas and NGL prices, respectively. The combined revenue from crude oil, natural gas and NGLs sales and net settlements received on our commodity derivative instruments was $1.4 billion in 2020 and $1.3 billion in 2019.

In the fourth quarter, crude oil, natural gas and NGL sales increased one percent to $344 million from $340 million in the comparable 2019 period. The increase in sales between periods was primarily due to the 27 percent increase in production outweighing the 20 percent decrease in sales price per Boe. The combined revenue from crude oil, natural gas and NGLs sales and net settlements received on commodity derivative instruments increased 15 percent to $395 million in the fourth quarter of 2020 from $342 million in the comparable 2019 period.

The following table provides weighted-average sales price, by area, for the periods presented, excluding net settlements on derivatives and TGP:

Production costs for 2020, which include LOE, production taxes and TGP, were $299 million, or $4.37 per Boe, compared to $269 million, or $5.45 per Boe, in 2019. In the fourth quarter of 2020, production costs totaled $80 million, or $4.83 per Boe, compared to $71 million, or $5.42 per Boe in the comparable 2019 period. LOE per Boe improved 18 and 16 percent for the comparable full-year and fourth quarter periods, respectively, as the Company realized efficiency-gains through compressor management, reduced overtime and vendor price concessions. TGP per Boe increased 21 percent and 55 percent for the comparable full-year and fourth quarter periods, primarily due to the accounting treatment of new transportation agreements and amendments to existing crude oil sales contracts resulting in increases to both TGP and realized prices.

The following table provides the components of production costs for the periods presented:

2020 Financial Results

Net loss for 2020 was approximately $724 million, or $7.37 per diluted share, compared to net loss of $57 million, or $0.89 per diluted share in 2019. The year-over-year change was primarily due to $882 million impairment charges recognized in 2020 compared to $39 million recognized in 2019, partially offset by increased commodity price risk management gains between periods. Adjusted net loss, a non-U.S. GAAP financial measure defined below, was $625 million in 2020 compared to adjusted net income of $53 million in 2019. The year-over-year change was primarily due to aforementioned impairment.

Net cash from operating activities for 2020 was approximately $870 million compared to $858 million in 2019. Adjusted cash flows from operations was approximately $920 million in 2020 compared to approximately $825 million in the comparable 2019 period. The year-over-year difference in each metric was primarily due to an increase in production volumes and an increase in realized settlements of our commodity derivatives partially offset by a decrease in realized sales price between periods.  

G&A, which includes cash and non-cash expense, was $161 million, or $2.36 per Boe, in 2020 compared to $162 million, or $3.27 per Boe, in 2019. Approximately $30 million of transaction and transition expenses related to the SRC merger are included in 2020. Inclusive of these expenses, G&A per Boe improved 28 percent year-over-year, while excluding the deal-related costs would result in a 2020 G&A per Boe of $1.92, a 41 percent improvement from 2019.

Reconciliation of Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "adjusted free cash flow (deficit)," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.

Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities 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.

Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, and acquisitions and to service our debt obligations.

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      (1)   Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the year ended December 31, 2020.

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2020 Year-End and Fourth Quarter Teleconference and Webcast

The Company invites you to join Bart Brookman, President and Chief Executive Officer; Scott Meyers, Chief Financial Officer; Lance Lauck, Executive Vice President Corporate Development and Strategy; and David Lillo, Senior Vice President Operations for a conference call on Thursday, February 25, 2021, to discuss its 2020 results and 2021 guidance. The related slide presentation will be available on PDC's website at www.pdce.com.

Conference Call and Webcast:
Date/Time: Thursday, February 25, 2021 at 11:00 a.m. ET
Domestic (toll free): 877-312-5520
International: 1-253-237-1142
Conference ID: 7896168
Webcast: available at www.pdce.com

Replay Information:
Domestic (toll free): 855-859-2056
International: 1-404-537-3406
Conference ID: 7896168
Webcast Replay: available for six months at www.pdce.com

About PDC Energy, Inc.
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 Delaware Basin in west Texas. Its 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.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This press release 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 press release are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; impacts of Colorado political matters, including recent rulemaking initiatives given our geographic concentration; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; our stock repurchase program; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; ability to meet our volume commitments to midstream providers and timing and adequacy of midstream infrastructure; the potential return of capital to shareholders through buyback of shares and/or issuance of a dividend; ongoing compliance with our consent decree; risk of our counterparties non-performance on derivative instruments; and our ability to repay our 1.125% convertible due to 2021 (the "2021 Convertible Notes") and fund planned activities.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this press release 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 press release or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

• the COVID-19 pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters;
• changes in global production volumes and demand, including economic conditions that might impact demand and prices for the products we produce;
• impact of regulatory developments in Colorado, particularly with respect to additional permit scrutiny;
• geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries;
• volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices, including risks relating to decreased revenue, income and cash flow, write-downs and impairments and availability of capital;
• volatility and widening of differentials;
• reductions in the borrowing base under our revolving credit facility;
• impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement of those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;
• timing and receipt of necessary regulatory permits;
• declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments;
• changes in estimates of proved reserves;
• inaccuracy of reserve estimates and expected production rates;
• potential for production decline rates from our wells being greater than expected;
• timing and extent of our success in discovering, acquiring, developing and producing reserves;
• availability and cost of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
• risks incidental to the drilling and operation of crude oil and natural gas wells;
• difficulties in integrating our operations as a result of any significant acquisitions or acreage exchanges;
• increases in costs and expenses;
• limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells;
• potential losses of acreage due to lease expirations or otherwise;
• future cash flows, liquidity and financial condition;
• competition within the oil and gas industry;
• availability and cost of capital;
• success in marketing our crude oil, natural gas and NGLs;
• effect of crude oil and natural gas derivative activities;
• impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders;
• impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events;
• cost of pending or future litigation;
• effect that acquisitions we may pursue have on our capital requirements;
• our ability to replace our oil and natural gas reserves;
• title defects in our oil and natural gas properties;
• civil unrest, terrorist attacks and cyber threats;
• our ability to retain or attract senior management and key technical employees; and
• success of strategic plans, expectations and objectives for our future operations.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors", in our Annual Report on Form 10-K for the year ended December 31, 2020 and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this press release. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this press release 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.