PDC Energy Announces 2020 Third Quarter Operating and Financial Results and Recently Approved Colorado Drilling Permit Applications

DENVER, Nov. 04, 2020 (GLOBE NEWSWIRE) -- PDC Energy, Inc. (“PDC” or the “Company”) (Nasdaq:PDCE) today announced its 2020 third quarter operating and financial results. 

2020 Third Quarter Highlights:

• Net cash from operating activities of approximately $280 million and adjusted cash flows from operations, a non-U.S. GAAP metric defined below, of approximately $260 million.
• Oil and gas capital investments of approximately $35 million.
• Approximately $225 million of adjusted free cash flow, a non-U.S. GAAP metric reconciled below and defined as net cash flows from operating activities, before changes in working capital, less oil and gas capital investments.
• Paid down approximately $215 million of debt from the Company’s revolving credit facility. The Company paid down an incremental $70 million of debt in October, resulting in total debt of less than $1.7 billion as of October 31, 2020.
• Lease operating expense (“LOE”) of $37 million or $2.11 per barrel of oil equivalent (“Boe”).
• Total production of 17.7 million Boe or approximately 192,000 Boe per day and oil production of 6.0 million barrels (“Bbls”) or approximately 65,000 Bbls per day.
• In September and October 2020, the Company received approval from the Colorado Oil and Gas Conservation Commission (“COGCC”) for an additional 32 future drilling locations. The Company now estimates it will have approximately 475 combined approved permits and drilled but uncompleted wells (“DUC”) at year-end 2020.

CEO Commentary

President and Chief Executive Officer Bart Brookman commented “I’m extremely proud of our team’s ability to remain focused and execute through all the uncertainty we experienced in the third quarter.  I believe the company’s considerable free cash flow generation and subsequent debt pay down truly differentiates PDC.   Furthermore, our ongoing track record of safe and responsible operations remains our highest priority.  This reputation, when combined with our community and county relationships, give us the utmost confidence in our long-term development plan on PDC’s 100% Weld County acreage position.”

Colorado Regulatory Update

In September and October, PDC received COGCC approval related to 32 future wells.  This inventory is located on four surface locations (Form 2A’s) averaging approximately ten building units within 2,000 feet and 750 feet to the nearest building unit.  The Company expects to exit 2020 with approximately 23 approved surface permits comprising approximately 275 future locations as well as an additional 200 DUCs.  The approximately 475 combined locations equate to nearly four years of future completion activity at the Company’s current pace.

Operations Update, 2020 Capital Investments and Financial Guidance

Year-to-date, PDC has generated approximately $240 million of adjusted free cash flow, including $225 million in the third quarter.  Additionally, the Company paid down approximately $215 million of debt in the third quarter and an incremental $70 million in October, resulting in total debt of less than $1.7 billion, as of October 31. Assuming fourth quarter pricing of $35 per Bbl WTI, $2.50 per Mcf NYMEX natural gas and NGL realizations of approximately $10 per barrel, the Company projects full-year and fourth quarter 2020 adjusted free cash flow in excess of $350 million and $100 million, respectively.

In the third quarter, the Company invested approximately $35 million while delivering total production of 17.7 million Boe, or approximately 192,000 Boe per day, and oil production of 6.0 million Bbls, or approximately 65,000 Bbls per day.  In the fourth quarter, the Company expects to invest approximately $110 million operating both a Wattenberg drilling rig and completion crew throughout the quarter with minimal planned investments in the Delaware Basin. Both total production and oil production are expected to decrease less than ten percent in the fourth quarter compared to the third quarter and average approximately 175,000 Boe per day and 60,000 Bbls per day, respectively.

In Wattenberg, the Company operated one drilling rig throughout the third quarter and a completion crew for the month of September, resulting in 17 spuds and two turn-in-lines (“TIL”) for the quarter.  Due to a lack of new TILs and the timing of returning to production previously shut-in, high GOR wells, average daily production was relatively flat while average daily oil production decreased approximately six percent on a sequential basis.  Additionally, the Company has realized several Wattenberg drilling and completion efficiencies throughout 2020, including improved extended reach lateral spud-to-spud drill times to an average of six days, and an increase in the number of completion stages per day.  These efficiencies may result in a slightly accelerated cadence of spuds and TILs in the fourth quarter of 2020 and all of 2021.

The Company is currently inactive from both a drilling and completion standpoint in the Delaware Basin; however, due to late second quarter TILs, oil production and total production in the third quarter increased eight and ten percent, respectively, compared to the second quarter.

The table below provides additional 2020 financial guidance:

2021 Preliminary Outlook

The Company’s preliminary 2021 Outlook remains unchanged from an operational standpoint as it contemplates total capital investment between $500 million and $600 million.  PDC projects drilling, completion and facility costs in each basin to decrease five to ten percent compared to its previously stated cost estimates of approximately $400 per foot in Wattenberg and approximately $850 per foot in the Delaware Basin. These potential savings are subject to market conditions and will likely be partially offset by the aforementioned Wattenberg operating efficiencies resulting in additional spuds and TILs late in 2021.  Assuming $40 per Bbl WTI oil, $2.75 per Mcf NYMEX natural gas and NGL realizations of approximately $10 per barrel, the Company projects to generate approximately $300 million of adjusted free cash flow in 2021. 

PDC continues to prioritize meaningful adjusted free cash flow generation while delivering zero to low single digit annual growth for both total production and oil production. The previously disclosed 2021 expectations of 175,000 to 185,000 Boe per day and 64,000 to 68,000 barrels per day for both total production and oil production, respectively, remain unchanged and are consistent with the current 2020 guidance ranges.  The Company will continue to monitor the aforementioned operating efficiencies as it balances production and capital spend with minimizing potential operating downtime in an effort to generate consistent, sustainable adjusted free cash flow.

Hedging Overview

In the fourth quarter of 2020, the Company has approximately 4.1 million Bbls of oil hedges at a weighted-average floor price of approximately $58 per Bbl.  The Company’s remaining swaps and costless collars represent approximately 70 percent of its projected oil volumes through year-end.  Approximately 40 percent of the Company’s estimated gas production in the fourth quarter of 2020 is protected at approximately $2 per Mcf. PDC’s 2021 hedge positions protect nearly 45 percent of its estimated oil volumes and 55 percent of its projected natural gas volumes at weighted-average floor prices of approximately $45 per barrel and $2.45 per Mcf, respectively.

The Company’s hedging strategy is predicated on systematically layering in oil and natural gas swaps and costless collars, as well as evaluating basis swaps and physical hedges when appropriate.

Oil and Gas Production, Sales and Operating Cost Data

Crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, increased to $315 million in the third quarter 2020 compared to $307 million in the comparable 2019 period.  The increase in sales between periods was due to a 39 percent increase in production being partially offset by a 26 percent reduction in sales price to $17.79 per Boe from $24.18 per Boe.  The decrease in sales price per Boe was driven by a 29 percent decrease in weighted-average oil price outweighing a ten percent and 18 percent increase in weighted-average realized natural gas and NGL prices, respectively. The increase in production between periods was due to the merger with SRC Energy, Inc. (“SRC”) in January 2020.  The combined revenue from crude oil, natural gas and NGLs sales and net settlements received on commodity derivative instruments increased 24 percent between periods to $382 million from $309 million.

The following table provides weighted-average sales price, by area, for the three and nine months ended September 30, 2020 and 2019, excluding net settlements on derivatives and TGP:

Production costs for the third quarter of 2020, which include LOE, production taxes and TGP, were $76 million, or $4.32 per Boe, compared to $61 million, or $4.77 per Boe, in the third quarter of 2019.  LOE improved 26 percent between periods to $2.11 per Boe from $2.87 per Boe.  The improvement in LOE per Boe is primarily due to efficiency-gains realized through compressor management and reduced overtime as well as vendor price concessions.  TGP increased 59 percent between periods to $1.38 per Boe in the third quarter of 2020 from $0.87 per Boe in the comparable 2019 period.  The increase between periods was 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 three and nine months ended September 30, 2020 and 2019:

Financial Results

Net loss for the third quarter of 2020 was approximately $31 million, or $0.31 per diluted share, compared to net income of $16 million, or $0.25 per diluted share in the comparable 2019 period.  The year-over-year change was due to the increase in commodity price risk management loss, partially offset by the decrease in depreciation expense between periods. Adjusted net income, a non-U.S. GAAP financial measure defined below, was $104 million in the third quarter of 2020 compared to adjusted net loss of $25 million in the comparable 2019 period.  The year-over-year change is primarily due to the increase in realized settlements of derivatives in the quarter.

Net cash from operating activities for the third quarter of 2020 was approximately $280 million compared to $234 million in the comparable 2019 period.  Adjusted cash flows from operations, a non-U.S. GAAP metric defined below, was approximately $260 million in the third quarter of 2020 compared to approximately $202 million in the comparable 2019 period. The year-over-year increase in each metric was primarily due to the increase in realized settlements of our derivatives between periods. 

G&A, which includes cash and non-cash expense, was $32 million, or $1.84 per Boe, in the third quarter of 2020 compared to $41 million, or $3.23 per Boe, in 2019.  Third quarter 2019 G&A includes approximately $5 million, or $0.42 per Boe, of legal-related expenses primarily associated with the SRC acquisition. Excluding these expenses would have resulted in third quarter 2020 G&A per Boe reflecting a 35 percent improvement between periods.

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.

Beginning in the third quarter of 2019, we included a reconciling item for gains or losses on the sale of properties and equipment when calculating adjusted EBITDAX, thereby no longer including such gains or losses in our reported adjusted EBITDAX. We believe this methodology for calculating adjusted EBITDAX will enable greater comparability to our peers, as well as consistent treatment of adjustments for impairment and gains or losses on the sale of properties and equipment. For comparability, all prior periods presented have been conformed to the aforementioned methodology.

(1)   Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the three or nine months ended September 30, 2020.

PDC ENERGY, INC.

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Condensed Consolidated Balance Sheets

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Condensed Consolidated Statements of Cash Flows

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2020 Third 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, November 5, 2020, to discuss its 2020 third quarter results. The related slide presentation will be available on PDC's website at .

Conference Call and Webcast:

Date/Time: Thursday, November 5, 2020 at 11:00 a.m. ET

Domestic (toll free): 877-312-5520

International: 1-253-237-1142

Conference ID: 7464278

Webcast: available at 

Replay Information:

Domestic (toll free): 855-859-2056

International: 1-404-537-3406

Conference ID: 7464278

Webcast Replay: available for six months at 

Upcoming Investor Presentations

PDC is scheduled to participate at the BofA 2020 Global Energy Conference on November 12, 2020; the Stephens Annual Investment Conference on November 19, 2020, and the Capital One Securities 15^th Annual Energy Conference on December 7, 2020.  An updated presentation will be posted to the Company’s website, , prior to the start of the conference.

About PDC Energy, Inc.

PDC Energy, Inc. is a domestic independent exploration and production company that acquires, produces, develops, and explores for crude oil, natural gas, and NGLs, with operations in the Wattenberg Field in Colorado and in the Delaware Basin in West Texas. Its operations are focused on the liquid-rich horizontal Niobrara and Codell plays in the Wattenberg Field and the liquid-rich Wolfcamp zones in the Delaware Basin.

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"), 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 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; 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 currently suspended 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; timing and adequacy of infrastructure projects of our midstream providers and the related impact on our midstream capacity and related curtailments; impacts of Colorado political matters; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; and our ability to repay our 2021 Convertible Notes.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this 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 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;
• 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;
• impacts of Colorado political matters;
• 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, writedowns 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;
• impact of regulatory developments in Colorado, particularly with respect to additional permit scrutiny;
• 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, including the merger with SRC, 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 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," made in our Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the U.S. Securities and Exchange Commission ("SEC") on February 26, 2020 (the "2019 Form 10-K"), our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 8, 2020 (the "First Quarter 2020 Form 10-Q"), our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the SEC on August 6, 2020 (the "Second Quarter 2020 Form 10-Q") and our other filings with the 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 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 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.