Acquisition Adds Significant Scale to Core Wattenberg Position, is Accretive to Key Financial and Operating Metrics, Maintains Strong Balance Sheet

Increases Quarterly Base Dividend More Than 100% to $0.25 per Share with Expectations to Further Increase to $0.35 per Share Upon Acquisition Closing

Commits to Returning a Minimum of 60% of Annual Post-Dividend FCF to Shareholders via Systematic Share Repurchases and Special Dividend, if needed

Increases Board-Authorized Share Repurchase Program to $1.25 Billion

PDC to Host Investor Call Today at 11:00 a.m. ET / 9:00 a.m. MT

DENVER, Feb. 28, 2022 (GLOBE NEWSWIRE) — PDC Energy, Inc. (“PDC” or the “Company”) (Nasdaq:PDCE) today announced it has entered into a definitive purchase agreement with Great Western Petroleum, LLC (“Great Western”) and certain sellers under which PDC will acquire Great Western in a transaction valued at approximately $1.3 billion, including net debt of approximately $500 million (the “Acquisition”). Great Western is a Denver-based DJ Basin operator owned by affiliates of EIG, TPG Energy Solutions, L.P. and The Broe Group. Under the terms of the agreement, the Acquisition will be financed through the issuance of approximately 4.0 million shares of common stock to existing Great Western shareholders and approximately $543 million of cash, subject to customary post-closing adjustments. The transaction is expected to close in the second quarter of 2022 and is expected to be financed with cash on hand and borrowings under the Company’s credit facility. PDC does not expect its pro forma leverage ratio to exceed 1.0x upon closing.

The Company also provided its enhanced return of capital framework, 2021 fourth quarter and year-end operating and financial results, detailed 2022 PDC standalone guidance and a preliminary 2022 pro forma outlook.

Key Acquisition Highlights:

  • Materially increases PDC scale through the acquisition of approximately 55,000 barrels of oil equivalent (“Boe”) per day, composed of approximately 42 percent crude oil and 67 percent liquids and year-end 2021 SEC proved reserves of 185 MMBoe. PDC estimates its pro forma year-end 2021 SEC proved reserves were approximately 1 billion Boe.
  • Addition of 315 identified locations – approximately 125 of which are either drilled but uncompleted wells (“DUCs”) or approved permits. The Company’s pro forma combined DUC and approved permit count was approximately 500 locations at year-end 2021.
  • Accretive to key financial and operating metrics including adjusted free cash flow (“FCF”), a non-U.S. GAAP metric defined below, FCF per share, shareholder returns, oil mix, general & administrative expense (“G&A”) per Boe and lease operating expense (“LOE”) per Boe. The Company anticipates its pro forma leverage ratio to be less than 0.7x at year-end 2022.
  • Accretive to PDC’s current GHG and methane emission intensities while supporting the Company’s 2025 and 2030 emission intensity reduction goals and further enhancing its best-in-class community stewardship programs.

President and Chief Executive Officer Bart Brookman commented, “Coupled with our existing high-quality inventory, this Core Wattenberg acquisition adds meaningful scale to PDC while also demonstrating our commitment to – and confidence in – the future of safe and responsible energy development in the state of Colorado. This opportunity meets all the Company’s acquisition-related criteria we’ve previously communicated by strengthening our free cash flow, increasing our shareholder returns, honoring the balance sheet and adding competitive, high-quality inventory.”

Return of Capital Framework:

  • PDC’s board of directors has approved an increase to its 2022 first quarter base dividend to $0.25 per share from $0.12 per share in the fourth quarter of 2021. The Company anticipates further increasing the quarterly base dividend to $0.35 per share upon closing of the Acquisition in the second quarter.
  • In 2022 and beyond, PDC is committed to returning a minimum of 60 percent of post-dividend annual FCF to shareholders through the Company’s board-authorized $1.25 billion share repurchase program and year-end special dividend, if needed. The Company intends to utilize its entire $1.25 billion authorization by year-end 2023.
  • Cumulative 2022 and 2023 estimated pro forma FCF of approximately $2.7 billion and projected shareholder returns of more than $1.7 billion, equating to approximately 50 percent and 30 percent, respectively, of the Company’s current market cap.

“I’m extremely excited to execute our new return of capital framework.” commented Chief Financial Officer Scott Meyers. “Not only do we feel this will lead to industry-leading shareholder returns, but we maintain the ability to further strengthen the balance sheet and build a cash balance for future flexibility. While our primary goal is to honor and consistently grow the base dividend, we plan to aggressively buy back a significant portion of our stock while we trade at an unwarranted discount to our intrinsic value, our peers and the broad market in general. At our current share price, we not only plan to fully exhaust our new plan in under two years – but we also project to retire more shares by the end of the third quarter than we’re issuing in association with the Great Western acquisition.”

PDC Standalone and Pro Forma 2022 Highlights (1):

  • Assuming $75 per barrel WTI crude oil, $4.00 NYMEX natural gas and NGL realizations of approximately $27.50 per barrel, PDC anticipates generating approximately $1.1 billion of standalone FCF with anticipated pro forma FCF of approximately $1.3 billion.
  • PDC standalone oil and gas capital investments expected between $675 and $725 million with pro forma capital investments expected between $900 million and $1.0 billion.
  • Total standalone production and oil production expected between 195,000 and 205,000 Boe per day and 62,000 and 65,000 barrels (“Bbls”) of crude oil per day. Pro forma daily production and daily oil production in the second half of 2022 are expected between 250,000 and 260,000 and 82,000 and 87,000, respectively.

    (1)   Pro forma outlook assumes successful closing of Acquisition in the second quarter, are based on current estimates and subject to a higher degree of uncertainty.

Colorado Permits

PDC exited the year with approximately 145 DUCs and approximately 230 approved permits in-hand, which includes the eight-well Spinney OGDP that was approved by the COGCC in early October. Further, the Company’s 70-well Kenosha OGDP recently passed the completeness determination stage of the approval process and is tentatively scheduled to be heard by the COGCC Commissioners in May 2022. Finally, the Company submitted its 450-well Guanella Comprehensive Area Plan (“CAP”) in December 2021. PDC continues to work collaboratively with local communities, Weld County, the State of Colorado and other key stakeholders as this meaningful project progresses through the permit approval process.

The Acquisition consists of approximately 315 total locations, with approximately 115 combined DUCs and approved permits in Adams County and approximately 10 approved permits and 90 low-risk, unpermitted locations in Weld County. An additional 96 locations have approved Form 2A permits in Adams County, providing line of sight to attaining Form 2 sub-surface permits. PDC projects its current level of DUCs and approved permits to be sufficient for all completion activity through 2023.

Year-End Proved Reserves and Inventory

PDC’s estimated SEC proved reserves as of year-end 2021 were 814 million Boe, with proved developed reserves accounting for approximately 49 percent of the total. Year-end 2021 reserves reflect an increase of 11 percent compared to year-end 2020 and equate to a 217% reserve replacement ratio. Under SEC pricing of approximately $67 per Bbl WTI, $3.60 per MMBtu natural gas and NGL realizations of approximately $25 per Bbl, the Company’s standardized measure value of its proved reserves was $7.9 billion and the discounted pre-tax PV-10 of those reserves was $9.7 billion.

Pro forma for the Acquisition, PDC’s estimated year-end 2021 SEC proved reserves were approximately 1,000 MMBoe, with proved developed reserves accounting for approximately 50 percent of the total. The Company’s discounted pre-tax PV-10 value of the pro forma year-end 2021 proved reserves was nearly $12.0 billion.

In Wattenberg, the Company’s estimated year-end undeveloped inventory, including DUCs, was approximately 1,800 locations with an average lateral length of approximately 9,700 feet, an increase of nearly 10 percent compared to the average lateral length of undeveloped locations as of year-end 2020. Total inventory represents an inventory life of more than ten years at the current development pace.

Pro forma Wattenberg undeveloped inventory was approximately 2,100 locations.

The table below provides a summary of the estimated year-end 2021 pro forma inventory by status and location:

Area  DUCs Permits Unpermitted Total
Kersey 70 60 124 254
Summit 12 89 317 418
Plains 47 32 386 465
Prairie 14 60 688 762
Range 12 105 96 213
Total  155 346 1,611 2,112

In the Delaware basin, PDC’s estimated year-end 2021 inventory was approximately 65 locations, including DUCs. The inventory had an average lateral length of approximately 10,200 feet, an increase of approximately 15 percent compared to year-end 2020. The Company’s estimated inventory equates to between three and four years of future TILs at its current development pace and reflects a more relaxed spacing design than prior development with a focus primarily on the Wolfcamp A and B zones. PDC is planning several initiatives in 2022 aimed at organically increasing inventory including testing the Bone Spring formation.

2022 Free Cash Flow Allocation, Capital Investment and Financial Guidance

PDC Standalone

PDC’s 2022 and multi-year operating plans are based on generating significant and sustainable levels of FCF with an industry-leading level of shareholder returns through its recently established free cash flow allocation framework. This framework contemplates that PDC will focus on consistent and meaningful growth to its quarterly base dividend on an annual basis with a commitment to returning a minimum of 60 percent of its post-dividend annual FCF to shareholders through a systematic share repurchase program while utilizing a special dividend, if needed, to fulfill its annual targets.

On February 25, PDC’s board of directors approved more than doubling its quarterly base dividend, raising it to $0.25 per share from $0.12 per share. The first quarter dividend is payable on March 25 to stockholders of record at the close of business on March 11. To fulfill the increased shareholder return objectives, the board also authorized a $1.25 billion share repurchase program with the goal of fully executing the increased plan by year-end 2023. PDC aims to systematically repurchase shares on a daily basis and uses a variety of factors to manage the pace of buybacks, including intrinsic discounted after-tax net asset value analysis, trading multiples and current and projected commodity prices.

In 2022, PDC projects to generate approximately $1.1 billion of post-tax FCF assuming $75 per Bbl WTI, $4.00 per Mcf NYMEX natural gas and NGL realizations of approximately $27.50 per Bbl. Under its new framework, PDC projects 2022 post-base dividend shareholder returns to exceed $600 million. Given the recent improvements in oil and gas prices, PDC expects to begin to incur cash federal and state income taxes in 2022 and beyond.

In 2022, on a standalone basis, PDC anticipates capital investments between $675 and $725 million with total daily production expected between 195,000 and 205,000 and daily oil production between 62,000 and 65,000. The Company’s 2022 capital investment range reflects an increase of approximately 10 percent at the mid-point compared to prior messaging primarily due to service cost inflation associated with higher commodity prices and other macro conditions.

Due to a majority of the Delaware basin completion program occurring in the first quarter, PDC expects its first quarter capital investments of between $195 and $215 million to be the highest, on a quarterly basis, of 2022. First quarter average daily production is expected between 190,000 and 200,000 while average oil production is expected between 61,000 and 66,000 per day. Compared to the fourth quarter of 2021, anticipated first quarter daily production and daily oil production are expected to decrease approximately 15 percent in the Delaware basin due to a lack of recent operated TIL activity and approximately seven percent in Wattenberg due to the anticipated timing of first quarter TILs, lower non-operated volumes and weather-related freeze offs.

In Wattenberg, on a standalone basis, the Company expects to utilize one full-time completion crew while increasing its rig count from one to two in the second quarter for total capital investments of approximately $550 million. Assuming more than 20 completion stages per day and average spud times of less than five days for an extended-reach lateral, the Company projects to TIL between 115 and 130 wells and spud between 130 and 145 wells. Well costs for the year, which include an estimated 100 percent increase to steel costs per well, are estimated at $450 per lateral foot. Wattenberg maintains a best-in-class cost structure including projected LOE of less than $2.50 per Boe.

In the Delaware basin, the Company anticipates running one full-time drilling rig and a part-time completion crew, resulting in an estimated 15 to 20 spuds and TILs, respectively. Capital investments are projected at approximately $150 million with estimated well costs, including facilities, of $850 per lateral foot.

Corporate LOE and G&A are expected to be between $2.70 and $2.90 per Boe and $1.80 and $2.00, respectively, for 2022. The modest increase to anticipated LOE per Boe is primarily associated with service and labor cost inflation and the Delaware basin artificial lift program.

Assuming the same commodity prices in 2023, PDC anticipates similar ranges for capital investments and after-tax FCF while delivering zero to five percent total production and oil production growth. Cumulative 2022-2023 FCF of approximately $2.2 billion equates to approximately 40 percent of the Company’s current market cap. Under the Company’s enhanced return of capital framework, and assuming a $0.25 per share quarterly dividend throughout 2022 and 2023, cumulative shareholder returns are expected to exceed $1.4 billion.

Preliminary Pro Forma 2022 Outlook

The Company anticipates closing the Acquisition in the second quarter with all estimates below based on the assumption that closing is successful. See the “Risk Factors” section of our December 31, 2021 Annual Report on Form 10-K for a discussion of certain risks associated with the acquisition.

In 2022, PDC projects to generate approximately $1.3 billion of after-tax FCF with more than $800 million of total shareholder returns. Anticipated 2022 capital investments between $900 million and $1.0 billion are expected to generate total production between 225,000 and 240,000 Boe per day and between 74,000 and 81,000 Bbls of oil per day. Post-close, the Company plans to operate three Wattenberg rigs, one Delaware rig and one and a half Wattenberg completion crews, resulting in anticipated second half daily total production and daily oil production of approximately 250,000 to 260,000 Boe and 82,000 to 87,000 Bbls, respectively.

The Company currently estimates pro forma cumulative 2022-2023 FCF of approximately $2.7 billion – equating to approximately 50 percent of the Company’s current market cap. Under the Company’s enhanced return of capital framework, and assuming a $0.25 per share quarterly dividend in the first quarter of 2022 and $0.35 per share thereafter, cumulative shareholder returns in 2022 and 2023 are expected to exceed $1.7 billion.

Environmental, Social and Governance (“ESG”)

In 2022, PDC plans to invest approximately $80 million and undertake several initiatives aimed at further improving its ESG best-practices and meeting certain regulatory requirements. From an environmental standpoint, PDC anticipates the plugging and reclamation of more than 300 legacy vertical wells, the installation of air pneumatics as part of its facility retrofit program and the transition to an electric drilling program that we anticipate will contribute to year-over-year emission intensity reductions of approximately 10 percent and more than 15 percent for GHG and methane, respectively. In 2022, PDC modified its executive compensation program to include GHG and methane emission intensity performance targets. Including its existing safety-related performance bonus metrics, ESG is projected to account for approximately 30 percent of the short-term incentive program.

As highlighted in a separate press release issued on February 2, PDC continued its board refreshment initiatives with the appointment of Pamela Butcher. Including Ms. Butcher, seven of PDC’s eight board members are independent and five have joined the board since 2020. Further, three directors are either female and/or self-identify as underrepresented minorities.

Due to the average age of Great Western’s existing wellbores and facilities compared to those of PDC, the Company projects its pro forma GHG and methane emission intensities to improve compared to its existing metrics. PDC expects the Acquisition to further support or accelerate its existing GHG and methane emission intensity reduction targets of more than 50 percent and 60 percent, respectively, by 2025 compared to 2020.

2021 Fourth Quarter and Year-End Results

GLJ

In the fourth quarter of 2021, PDC generated approximately $340 million of FCF and reduced total debt by approximately $300 million, exiting the year with a trailing twelve-month net leverage ratio of 0.6x. Additionally, PDC returned approximately $110 million of capital to shareholders through the $0.12 per share payment of its quarterly base dividend, the repurchase of approximately 1.0 million shares of common stock and a $0.50 per share special dividend. For the year, the Company generated approximately $950 million of FCF, reduced total net debt by approximately $700 million and returned approximately $245 million to shareholders.

Capital investments in the fourth quarter were approximately $134 million with total production of 19.4 million Boe, or 211,000 Boe per day, and oil production of 6.3 million Bbls, or 68,750 Bbls per day. Daily total production and daily oil production represent approximately three and four percent sequential increases from the third quarter of 2021. In 2021, PDC invested approximately $584 million to produce 71.3 million Boe, or 195,000 Boe per day, and 22.7 million Bbls of oil, or 62,000 Bbls per day.

In Wattenberg, the Company invested approximately $106 million in the fourth quarter to operate one drilling rig and one completion crew, resulting in 15 spuds and 36 turn-in-lines (“TILs”). Total production was 16.7 million Boe, or approximately 182,000 Boe per day, while oil production was 5.3 million Bbls, or approximately 57,500 Bbls per day. Full-year Wattenberg activity consisted of capital investments of approximately $432 million, 78 spuds and 149 TILs. Total production and oil production averaged approximately 170,000 Boe per day and 52,000 Bbls of oil per day, respectively.

In the Delaware Basin, PDC invested approximately $28 million to operate one drilling rig, resulting in four spuds and zero TILs in the quarter as the Company finished its 2021 completion activity in the second quarter. Total production was 2.7 million Boe, or approximately 29,000 Boe per day, while oil production was approximately 1.0 million Bbls, or approximately 11,000 Bbls per day. Fourth quarter total production and oil production benefited from the installation and utilization of five electrical submersible pumps and several workover projects completed in the third quarter, as well as strong non-operated well performance. For the full-year, PDC invested approximately $152 million to drill and TIL 18 wells. Total production and oil production averaged approximately 26,000 Boe per day and 10,000 Bbls per day, respectively.

Oil and Gas Production, Sales and Operating Cost Data

Fourth quarter crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, were $848 million, a 147 percent increase over 2020 levels of $343 million. The increase in sales between periods was due to a 111 percent increase in weighted average realized sales price per Boe to $43.71 from $20.72. The increase in sales price was driven by 89 percent, 159 percent and 157 percent increases in weighted average realized crude oil, natural gas and NGL prices, respectively. The combined revenue from crude oil, natural gas and NGLs sales and net settlements on commodity derivative instruments was approximately $653 million in 2021 compared to approximately $395 million in 2020.

Full-year crude oil, natural gas and NGLs sales, excluding net settlements on derivatives, were $2,553 million, a 122 percent increase over 2020 levels of $1,153 million. The increase in sales between periods was due to a 112 percent increase in weighted average realized sales price per Boe to $35.78 from $16.86. The increase in sales price was driven by 96 percent, 174 percent and 182 percent increases in weighted average realized crude oil, natural gas and NGL prices, respectively. The combined revenue from crude oil, natural gas and NGLs sales and net settlements on commodity derivative instruments was approximately $2,142 million in 2021 compared to approximately $1,432 million in 2020.

The following table provides weighted-average sales price, by area, for the three and twelve months ended December 31, 2021 and 2020, excluding net settlements on derivatives and TGP:

Three Months Ended December 31, Year Ended December 31,
2021 2020 Percent
Change
2021 2020 Percent
Change
Crude oil (MBbls)
Wattenberg Field 5,306 4,568 16  % 18,901 19,552 (3 )%
Delaware Basin 1,019 1,019  % 3,781 4,168 (9 )%
Total 6,325 5,587 13  % 22,682 23,720 (4 )%
Weighted-Average Sales Price $ 76.50 $ 40.43 89  % $ 67.49 $ 34.44 96  %
Natural gas (MMcf)
Wattenberg Field 40,870 35,559 15  % 154,150 140,845 9  %
Delaware Basin 6,163 6,276 (2 )% 21,597 24,792 (13 )%
Total 47,033 41,835 12  % 175,747 165,637 6  %
Weighted-Average Sales Price $ 4.10 $ 1.58 159  % $ 2.96 $ 1.08 174  %
NGLs (MBbls)
Wattenberg Field 4,615 3,458 33  % 17,300 14,495 19  %
Delaware Basin 626 556 13  % 2,060 2,547 (19 )%
Total 5,241 4,014 31  % 19,360 17,042 14  %
Weighted-Average Sales Price $ 32.74 $ 12.76 157  % $ 25.94 $ 9.21 182  %
Crude oil equivalent (MBoe)
Wattenberg Field 16,732 13,952 20  % 61,892 57,521 8  %
Delaware Basin 2,673 2,622 2  % 9,441 10,847 (13 )%
Total 19,405 16,574 17  % 71,333 68,368 4  %
Weighted-Average Sales Price $ 43.71 $ 20.72 111  % $ 35.78 $ 16.86 112  %

Production costs for the fourth quarter of 2021, which include LOE, production taxes and TGP, were $141 million, or $7.26 per Boe, compared to $80 million, or $4.83 per Boe, in 2020. Production costs for the full year were $446 million, or $6.26 per Boe, compared to $299 million, or $4.37 per Boe, in 2020. The increase in production costs per Boe between comparable periods was predominantly due to increases in production taxes per Boe of 197 percent and 167 percent, respectively.

The following table provides the components of production costs for the three and twelve months ended December 31, 2021 and 2020:

Three Months Ended
December 31,
Year Ended
December 31,
2021 2020 2021 2020
Lease operating expenses $ 50.8 $ 38.7 $ 180.7 $ 161.3
Production taxes 64.1 18.4 165.2 59.4
Transportation, gathering and processing expenses 26.0 23.0 100.4 77.8
Total $ 140.9 $ 80.1 $ 446.3 $ 298.5
Three Months Ended
December 31,
Year Ended
December 31
2021 2020 2021 2020
Lease operating expenses per Boe $ 2.62 $ 2.33 $ 2.53 $ 2.36
Production taxes per Boe 3.30 1.11 2.32 0.87
Transportation, gathering and processing expenses per Boe 1.34 1.39 1.41 1.14
Total per Boe $ 7.26 $ 4.83 $ 6.26 $ 4.37

Financial Results

Net income for the fourth quarter and full-year 2021 were $473 million, or $4.78 per diluted share, and $522 million, or $5.22 per diluted share, respectively, compared to net losses of $7 million, or $0.07 per diluted share, and $724 million, or $7.37 per diluted share in the comparable 2020 periods. Adjusted net income, a non-U.S. GAAP financial measure defined below, was $283 million in the fourth quarter of 2021 and $800 million for the full year compared to $111 million and a net loss of $625 million in the comparable 2020 periods. The year-over-year change between fourth quarter metrics was primarily due to an increase in sales partially offset by an increase in net derivative settlement losses and an increase in production taxes whereas the year-over-year difference between annual metrics was primarily due to an $882 million impairment expense in 2020.

Net cash from operating activities for the fourth quarter of 2021 was approximately $520 million compared to $221 million in 2020. Adjusted cash flows from operations, a non-U.S. GAAP metric defined below, was approximately $473 million in the fourth quarter of 2021 compared to approximately $269 million in 2020. Full year 2021 net cash from operating activities was $1,548 million compared to $870 million in 2020 while adjusted cash flows from operations were $950 million and $400 million, respectively. The year-over-year increase in each metric was primarily due to the increase in sales partially offset by the increase in costs and change in derivative settlements.

G&A, which includes cash and non-cash expense, was $31 million, or $1.62 per Boe, in the fourth quarter of 2021 compared to $31 million, or $1.88 per Boe, in 2020. G&A for the full year 2021 was $128 million, or $1.79 per Boe, compared to $161 million, or $2.36 per Boe in 2020. The 14 percent decrease in G&A per Boe between fourth quarter periods was primarily due to increased production volumes whereas the 24 percent decrease between annual periods is primarily attributable to transaction and transition costs associated with the acquisition of SRC Energy in 2020.

Timing and Approvals

The Acquisition, which is expected to close in the second quarter of 2022, is subject to customary closing conditions and the satisfaction of certain regulatory approvals.

Advisors

PJT Partners is serving as exclusive financial advisor to PDC, and Davis, Graham and Stubbs LLP is serving as PDC’s legal counsel. Citi is serving as exclusive financial advisor to Great Western, and Latham & Watkins LLP is serving as Great Western’s legal counsel.

Reconciliation of Non-U.S. GAAP Financial Measures

We use “adjusted cash flows from operations,” “adjusted free cash flow (deficit), (or “FCF”)” “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.

Cash Flows from Operations to Adjusted Cash Flows From Operations and Adjusted Free Cash Flow
Three Months Ended
December 31,
Year Ended
December 31,
2021 2020 2021 2020
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:
Net cash from operating activities $ 520.0 $ 220.8 $ 1,547.8 $ 870.1
Changes in assets and liabilities (46.9 ) 48.0 (15.2 ) 51.5
Adjusted cash flows from operations 473.1 268.8 1,532.6 921.6
Capital expenditures for development of crude oil and natural gas properties (154.3 ) (105.5 ) (583.1 ) (551.0 )
Change in accounts payable related to capital expenditures for oil and gas development activities 20.7 (2.7 ) (0.5 ) 28.7
Adjusted free cash flow $ 339.5 $ 160.6 $ 949.0 $ 399.3
Net Income (Loss) to Adjusted Net Income (Loss) and Adjusted Earnings Per Share, Diluted
Three Months Ended
December 31,
Year Ended
December 31,
2021 2020 2021 2020
Net income (loss) to adjusted net income (loss):
Net income (loss) $ 473.1 $ (6.7 ) $ 522.3 $ (724.3 )
(Gain) loss on commodity derivative instruments (5.7 ) 65.6 701.5 (180.3 )
Net settlements on commodity derivative instruments (194.8 ) 51.8 (410.2 ) 279.3
Tax effect of above adjustments (1) 10.5 (14.0 )
Adjusted net income (loss) $ 283.1 $ 110.7 $ 799.6 $ (625.3 )
Earnings (Loss) per share, diluted $ 4.78 $ (0.07 ) $ 5.22 $ (7.37 )
Loss (gain) on commodity derivative instruments (0.06 ) 0.65 7.00 (1.83 )
Net settlements on commodity derivative instruments (1.97 ) 0.52 (4.09 ) 2.84
Tax effect of above adjustments (1) 0.11 (0.14 )
Adjusted earnings per share, diluted $ 2.86 $ 1.10 $ 7.99 $ (6.36 )
Weighted-average diluted shares outstanding 99.0 100.4 100.2 98.3

_____________

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

Adjusted EBITDAX
Three Months Ended
December 31,
Year Ended
December 31,
2021 2020 2021 2020
Net income (loss) to adjusted EBITDAX:
Net income (loss) $ 473.1 $ (6.7 ) $ 522.3 $ (724.3 )
Loss (gain) on commodity derivative instruments (5.7 ) 65.6 701.5 (180.3 )
Net settlements on commodity derivative instruments (194.8 ) 51.8 (410.2 ) 279.3
Non-cash stock-based compensation 5.7 4.8 23.0 22.2
Interest expense, net 23.5 21.7 82.7 88.7
Income tax expense (benefit) 26.5 (4.4 ) 26.6 (7.9 )
Impairment of properties and equipment 0.1 0.1 0.4 882.4
Exploration, geologic and geophysical expense 0.2 0.4 1.1 1.4
Depreciation, depletion and amortization 156.6 149.6 635.2 619.7
Accretion of asset retirement obligations 2.9 2.7 12.1 10.1
Loss (gain) on sale of properties and equipment (0.4 ) (0.1 ) (0.9 ) (0.7 )
Adjusted EBITDAX $ 487.7 $ 285.5 $ 1,593.8 $ 990.6
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities $ 520.0 $ 220.8 $ 1,547.8 $ 870.1
Interest expense, net(1) 16.6 21.7 75.8 88.7
Amortization and write-off of debt discount, premium and issuance costs (2.3 ) (4.3 ) (13.5 ) (16.8 )
Exploration, geologic and geophysical expense 0.2 0.4 1.1 1.4
Other 0.1 (1.1 ) (2.2 ) (4.3 )
Changes in assets and liabilities (46.9 ) 48.0 (15.2 ) 51.5
Adjusted EBITDAX $ 487.7 $ 285.5 $ 1,593.8 $ 990.6

(1) Excludes loss on extinguishment from early retirement of our senior notes amounting to $6.9 million for the three months and year ended December 31, 2021

PDC ENERGY, INC.
Condensed Consolidated Statements of Operations
(unaudited, in thousands, except per share data)

Three Months Ended
December 31,
Year Ended
December 31,
2021 2020 2021 2020
Revenues
Crude oil, natural gas and NGLs sales $ 848,162 $ 343,399 $ 2,552,558 $ 1,152,555
Commodity price risk management gain (loss), net 5,731 (65,581 ) (701,456 ) 180,270
Other income 750 745 4,808 6,401
Total revenues 854,643 278,563 1,855,910 1,339,226
Costs, expenses and other
Lease operating expense 50,811 38,666 180,659 161,346
Production taxes 64,095 18,431 165,209 59,368
Transportation, gathering and processing expense 25,950 22,991 100,403 77,835
Exploration, geologic and geophysical expense 202 350 1,064 1,376
General and administrative expense 31,366 31,080 127,733 161,087
Depreciation, depletion and amortization 156,567 149,587 635,184 619,739
Accretion of asset retirement obligations 2,901 2,674 12,086 10,072
Impairment of properties and equipment 73 66 402 882,393
Gain on sale of properties and equipment (351 ) (82 ) (912 ) (724 )
Other expenses (6 ) 4,189 2,490 10,272
Total costs, expenses and other 331,608 267,952 1,224,318 1,982,764
Income (loss) from operations 523,035 10,611 631,592 (643,538 )
Interest expense, net (23,499 ) (21,706 ) (82,698 ) (88,684 )
Income (loss) before income taxes 499,536 (11,095 ) 548,894 (732,222 )
Income tax (expense) benefit (26,473 ) 4,405 (26,583 ) 7,902
Net income (loss) $ 473,063 $ (6,690 ) $ 522,311 $ (724,320 )
Earnings (Loss) per share:
Basic 4.87 $ (0.07 ) 5.30 $ (7.37 )
Diluted 4.78 $ (0.07 ) 5.22 $ (7.37 )
Weighted average common shares outstanding:
Basic 97,140 99,708 98,546 98,251
Diluted 99,021 99,708 100,154 98,251

PDC ENERGY, INC.
Consolidated Balance Sheets
(unaudited, in thousands, except share and per share data)

December 31, 2021 December 31, 2020
Assets
Current assets:
Cash and cash equivalents $ 33,829 $ 2,623
Accounts receivable, net 398,605 244,251
Fair value of derivatives 17,909 48,869
Prepaid expenses and other current assets 8,230 12,505
Total current assets 458,573 308,248
Properties and equipment, net 4,814,865 4,859,199
Fair value of derivatives 15,177 9,565
Other assets 48,051 60,961
Total Assets $ 5,336,666 $ 5,237,973
Liabilities and Stockholders’ Equity
Liabilities
Current liabilities:
Accounts payable $ 127,891 $ 90,635
Production tax liability 99,583 124,475
Fair value of derivatives 304,870 98,152
Funds held for distribution 285,861 177,132
Accrued interest payable 10,482 14,734
Other accrued expenses 91,409 81,715
Current portion of long-term debt 193,014
Total current liabilities 920,096 779,857
Long-term debt 942,084 1,409,548
Asset retirement obligations 127,526 132,637
Fair value of derivatives 95,561 36,359
Deferred income taxes 26,383
Other liabilities 314,769 264,034
Total liabilities 2,426,419 2,622,435
Commitments and contingent liabilities
Stockholders’ equity
Common shares – par value $0.01 per share, 150,000,000 authorized, 96,468,071 and 99,758,720 issued as of December 31, 2021 and 2020, respectively 965 998
Additional paid-in capital 3,161,941 3,387,754
Accumulated deficit (249,954 ) (772,265 )
Treasury shares – at cost, 54,960 and 37,510 as of December 31, 2021 and 2020, respectively (2,705 ) (949 )
Total stockholders’ equity 2,910,247 2,615,538
Total Liabilities and Stockholders’ Equity $ 5,336,666 $ 5,237,973

PDC ENERGY, INC.
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)

Three Months Ended
December 31,
Year Ended
December 31,
2021 2020 2021 2020
Cash flows from operating activities:
Net income (loss) 473,063 $ (6,690 ) $ 522,311 $ (724,320 )
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives (200,562 ) 117,339 291,268 99,001
Depreciation, depletion and amortization 156,567 149,587 635,184 619,739
Impairment of properties and equipment 73 66 402 882,393
Accretion of asset retirement obligations 2,901 2,674 12,086 10,072
Non-cash stock-based compensation 5,729 4,759 23,023 22,200
Loss (gain) on sale of properties and equipment (351 ) (82 ) (912 ) (724 )
Amortization and write-off of debt discount, premium and issuance costs 2,273 4,226 13,468 16,772
Loss from extinguishment of debt 6,927 6,927
Deferred income taxes 26,383 (4,099 ) 26,383 (6,530 )
Other 98 1,054 2,451 3,004
Changes in assets and liabilities 46,875 (48,067 ) 15,205 (51,528 )
Net cash from operating activities 519,976 220,767 1,547,796 870,079
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties (154,277 ) (105,459 ) (583,108 ) (550,964 )
Capital expenditures for other properties and equipment (531 ) 306 (894 ) (1,634 )
Acquisition of crude oil and natural gas properties (139,812 )
Proceeds from sale of properties and equipment 353 102 5,073 1,641
Proceeds from divestitures 125 1,814 125 3,610
Net cash from investing activities (154,330 ) (103,237 ) (578,804 ) (687,159 )
Cash flows from financing activities:
Proceeds from revolving credit facility and other borrowings 300,000 313,750 802,800 1,799,350
Repayment of revolving credit facility and other borrowings (300,000 ) (430,750 ) (970,800 ) (1,635,350 )
Proceeds from issuance of senior notes 148,500
Redemption of senior notes (308,584 ) (308,584 ) (452,153 )
Redemption of convertible notes (200,000 )
Payment of debt issuance costs (13,066 ) (341 ) (13,066 ) (6,538 )
Purchase of treasury shares (49,477 ) (156,795 ) (23,819 )
Purchase of treasury shares for employee stock-based compensation tax withholding obligations (202 ) (933 ) (6,038 ) (9,345 )
Dividends paid (60,015 ) (83,615 )
Principal payments under financing lease obligations (395 ) (451 ) (1,688 ) (1,905 )
Net cash from financing activities (431,739 ) (118,725 ) (937,786 ) (181,260 )
Net change in cash, cash equivalents and restricted cash (66,093 ) (1,195 ) 31,206 1,660
Cash, cash equivalents and restricted cash, beginning of year 99,922 12,254 2,623 963
Cash, cash equivalents and restricted cash, end of year $ 33,829 $ 11,059 $ 33,829 $ 2,623

2021 Fourth Quarter and Year-End 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 Monday, February 28, 2022 at 11:00 a.m. ET, to discuss its 2021 fourth quarter and year-end results. The related slide presentation will be available on PDC’s website at www.pdce.com.

Conference Call and Webcast:
Date/Time: Monday, February 28, 2022 at 11:00 a.m. ET
Domestic (toll free): 877-312-5520
International: 1-253-237-1142
Conference ID: 2197232
Webcast: available at www.pdce.com

Replay Information:
Domestic (toll free): 855-859-2056
International: 1-404-537-3406
Conference ID: 2197232
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, the pending acquisition of Great Western and the effects thereof; the expected timing of the Acquisition and the possibility that the Acquisition will not close; statements regarding future: production, costs and cash flows; impacts of Colorado political matters, including initiatives influencing our ability to continue to obtain permits; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; adequacy of midstream infrastructure; the potential return of capital to shareholders through buyback of shares and/or payments of dividends; expected impact from emission reduction initiatives; 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 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:

  • 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;
  • 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, including in particular additional permit scrutiny in Colorado;
  • the coronavirus 2019 (“COVID-19”) pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters;
  • 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;
  • timing and cost of wells and facilities;
  • availability, cost, and timing of sufficient pipeline, gathering and transportation 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 our 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;
  • timing and amounts for cash income taxes;
  • uncertainties associated with future dividends to our shareholders or share buybacks;
  • our ability to retain or attract senior management and key technical employees;
  • difficulties in integrating our operations as a result of any significant acquisitions, including the Acquisition, or acreage exchanges;
  • a failure to complete the Acquisition or an unanticipated assumption of liabilities or other problems with the Acquisition;
  • civil unrest, terrorist attacks and cyber threats; 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, 2021 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.

Contacts: Kyle Sourk
Director Corporate Finance & Investor Relations
303-318-6150
[email protected]