PDC ENERGY, INC. The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data and also with Item 1A. Risk Factors of this report. A discussion of changes in our results of operations and liquidity from 2019 to 2020 has been omitted from this report but can be found in Item 7. Management's Discussion and Analysis, of our Annual Report on Form 10-K for the year endedDecember 31, 2020 , filed with theSEC onFebruary 25, 2021 . Further, we encourage you to review the Special Note Regarding Forward-Looking Statements in Part I of this report.
EXECUTIVE SUMMARY
2021 Financial Overview of Operations and Liquidity
Market Conditions
The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment.
Crude Oil Markets
In 2020, the COVID-19 pandemic led to a significant decline in commodity prices due to the decrease in demand for crude oil, negatively impacting crude oil and natural gas producers, such as PDC. Due to the decrease in oil demand, theOrganization of Petroleum Exporting Countries ("OPEC") and other oil producing countries significantly decreased production, resulting in a low level of global supply. During 2021, the global economy slowly recovered from the impacts of COVID-19 and related variants through vaccination distributions. The recovery of the global economy was supported by gradual increases to production volumes fromOPEC and other oil producing countries; however, demand growth exceeded the production increases, resulting in higher commodity prices compared to pre-COVID-19 prices. The commodity price environment may remain volatile for an extended period due to, among other things, outbreaks caused by coronavirus variants, the recovery of the economy, unexpected supply disruptions in key producing countries, geopolitical disputes, weather conditions, and ongoing investor and regulatory pressure to replace fossil fuel consumption with lower carbon emission alternatives. Natural Gas and NGL Markets In addition to the crude oil market drivers noted above, natural gas and NGL prices are also affected by structural changes in supply and demand, growth in levels of liquified natural gas exports and deviations from seasonally normal weather. Lower inventory levels and lack of reinvestment in supply growth have driven natural gas and NGL prices higher than recent levels.
Financial Matters
Twelve months ended
•Production volumes increased 4 percent to 71.3 MMboe in 2021 compared to 2020 as a result of our full-year drilling and completion program during 2021.
•Crude oil, natural gas and NGLs sales increased to
•Incurred negative net settlements from our commodity derivative contracts of$410.2 million compared to positive net settlements of$279.3 million in 2020 due to improvement in commodity prices during 2021. 41 -------------------------------------------------------------------------------- •Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 50 percent to$2.1 billion from$1.4 billion in 2020. •Generated net income of$522.3 million , or$5.22 per diluted share, compared to a net loss of$724.3 million , or$7.37 per diluted share, in 2020. The net income during the period compared to the net loss in the prior period was significantly impacted by an increase in crude oil, natural gas and NGLs sales of$1,400.0 million and an$882.4 million impairment charge recognized in 2020. These positive factors were partially offset by an increased loss of$881.7 million in commodity price risk management and$105.8 million in additional production taxes between periods. •Adjusted EBITDAX, a non-U.S. GAAP financial measure, was$1,593.8 million compared to$990.6 million in 2020, primarily due to an increase in sales of$710.5 million , net of negative net derivative settlements. •Cash flows from operations increased to$1,547.8 million compared to$870.1 million in 2020. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to$1,532.6 million compared to$921.6 million in 2020. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to$949.0 million from$399.3 million in 2020. See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparableU.S. GAAP measures.
Pending Acquisition
OnFebruary 26, 2022 , we entered into the Acquisition Agreement to acquire Great Western for approximately$1.3 billion , inclusive of Great Western's net debt. Great Western is an in dependent oil and gas company focused on the exploration, production and development of crude oil and natural gas inColorado . We anticipate acquiring approximately 54,000 net acres in the Core Wattenberg and production of approximately 55,000 Boe per day. Under the terms of the Acquisition Agreement, the purchase price of the Great Western Acquisition will consist of approximately 4.0 million shares of our common stock and approximately$543 million in cash. The cash portion of the purchase price is expected to be funded through a combination of cash on hand and availability under our revolving credit facility. We expect the Great Western Acquisition to be completed in the second quarter of 2022, subject to certain customary closing conditions. Upon a successful close, we anticipate adding between$225 million and$275 million to our planned 2022 Wattenberg capital investment. See Item 1A. Risk Factors for risk factors related to the Great Western Acquisition of this report.
Drilling, Completion and Vertical Well Abandonment Overview
During 2021, we operated one full-time drilling rig, one spudder rig and one full-time completion crew in the Wattenberg Field. In addition, we operated one full-time drilling rig and one part-time completion crew, which started in March and ended in June, in theDelaware Basin . Our total capital investments in crude oil and natural gas properties for the year endedDecember 31, 2021 were$583.7 million . We operated a full-time workover rig in the Wattenberg Field in 2021 for use in our plugging and abandonment program. This program focused on our legacy vertical wells to assist in our horizontal drilling program and to reduce our overall produced well emissions. We spent$30.5 million on this program in 2021. 42 --------------------------------------------------------------------------------
The following table summarize our drilling, completion and vertical well
abandonment activities for the year ended
Operated Wells
Wattenberg Field Delaware Basin Total
Gross Net Gross Net Gross Net
In-process as of December 31,
2020 214 201.8 20 19.0 234 220.8
Wells spud 78 74.2 19 19.0 97 93.2
Wells turned-in-line (149) (143.0) (18) (17.4) (167) (160.4)
In-process as of December 31,
2021 143 133.0 21 20.6 164 153.6
Plugged and abandoned -
Vertical Wells 404 392.0 - - 404 392.0
Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling.
Debt Reductions and Capital Returns
Debt Reduction. During the year endedDecember 31, 2021 , we significantly reduced our indebtedness by$670.3 million . This reduction included net repayments of$168.0 million on our revolving credit facility, resulting in no outstanding balance at the period end. OnSeptember 15, 2021 , we redeemed and retired our 2021 Convertible Notes with a cash payment for the principal amount of$200 million , plus accrued and unpaid interest. Additionally, onNovember 3, 2021 , we redeemed the aggregate$200 million principal amount of our outstanding 2024 Senior Notes at a redemption price of 101.531 percent of the principal plus accrued and unpaid interest, leaving an aggregate principal amount outstanding of$200 million . Finally, onDecember 1, 2021 , we redeemed the remaining$102.3 million principal amount of our outstanding 6.25% Senior Notes due in 2025 (the "2025 Senior Notes") at a redemption price of 103.125 percent of the principal plus accrued and unpaid interest. The redemptions of our 2021 Convertible Notes and 2025 Senior Notes as well as the partial redemption of our 2024 Senior Notes were financed by our cash flows from operations. Stock Repurchase Program. InFebruary 2021 , we reinstated our Stock Repurchase Program. During the year endedDecember 31, 2021 , we repurchased 3.8 million shares of outstanding common stock at a cost of$159.5 million . As ofDecember 31, 2021 ,$187.3 million remained available under the program. InFebruary 2022 , our board of directors increased the size of the program to$1.25 billion , which we anticipate fully utilizing byDecember 31, 2023 . Dividends. In the second quarter of 2021, our board of directors commenced the declaration and payment of quarterly cash dividends of$0.12 per share of our common stock. InDecember 2021 , our board of directors declared and paid a special dividend of$0.50 per share of our common stock in addition to the regular fourth quarter dividend declared. For the year endedDecember 31, 2021 , our dividends paid totaled$0.86 per share of common stock or$83.6 million in the aggregate.
2022 Operational and Financial Outlook
We anticipate that our production for 2022 will range between 195,000 Boe to 205,000 Boe per day, approximately 62,000 Bbls to 65,000 Bbls of which are expected to be crude oil. Our planned 2022 capital investments in crude oil and natural gas properties, which we expect to be between$675 million and$725 million , are focused on continued execution of our development plans in the Wattenberg Field and theDelaware Basin . Our 2022 capital investments budget incorporates an increase in both basins relating to service cost inflation resulting in an estimated cost increase of approximately 10 to 15 percent per well, based on costs we have experienced since the third quarter of 2021. We have operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining 43 -------------------------------------------------------------------------------- inventory to best meet our short- and long-term corporate strategy. We may revise our 2022 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds and acquisition and divestiture opportunities. Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between theKersey , Prairie, Plains, and Summit development areas. Our 2022 capital investment program for the Wattenberg Field represents approximately 75 percent of our expected total capital investments in crude oil and natural gas properties. In 2022, the majority of the wells we plan to drill are 1.5 mile and 2.0 mile lateral wells in the Wattenberg Field. In 2022, we anticipate spudding approximately 130 to 145 operated wells and turning-in-line approximately 115 to 130 operated wells. As ofDecember 31, 2021 , we have approximately 145 gross operated DUCs and 235 approved permitted locations. In 2022, we expect to add a rig in March, bringing us to two full-time horizontal rigs and one completion crew along with a part-time spudder rig.Delaware Basin . Total capital investments in crude oil and natural gas properties in theDelaware Basin for 2022 are expected to be approximately 25 percent of our total capital investments. In 2022, we anticipate spudding and turning-in-line approximately 15 to 20 operated wells. The majority of the wells we plan to drill in 2022 in theDelaware Basin are 2.0 mile lateral wells. We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2022, we expect 2022 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Our first priority is to pay our quarterly base dividend of$0.25 per share. Then we expect to use approximately 60% or more of our remaining adjusted free cash flows, a non-U.S. GAAP financial measure, for share repurchases and special dividends, as needed. Any remaining adjusted free cash flows will be used for reducing debt, building cash on our consolidated balance sheet or other general corporate purposes.
Regulatory and Political Updates
InColorado , certain interest groups opposed to oil and natural gas development have proposed ballot initiatives that could hinder or eliminate the ability to develop resources in the state. In 2019, theColorado legislature passedSenate Bill 19-181 ("SB 19-181") to address concerns underlying the ballot initiatives. As part of SB 19-181, a series of rulemaking hearings were conducted, which focused on issues such as permitting requirements, setbacks and siting requirements, resulting in the adoption of new regulatory requirements. Rulemakings focused on financial assurance and permit fees have not been completed. The financial assurance rulemaking could result in increased bonding requirements, though the final language and impact will not be known until early 2022. A key component of SB 19-181 was the change in the COGCC mission from "fostering" the industry to "regulating" the industry. As a result, changes were made to the permitting process inColorado . As ofJanuary 2021 , permits are now designed as Oil and Gas Development Plans ("OGDP"), which streamlines single pad locations or proximate multi-pad locations into a single permitting package. Operators also have an option to pursue a Comprehensive Area Plan ("CAP"). A CAP is designed to represent an overview of oil and gas development over a larger area over a longer period of time, including a comprehensive cumulative impact analysis, an alternative location analysis, and extensive communication with both local elected officials and communities. A CAP will include multiple OGDPs within its boundaries. As both CAPs and OGDPs are new processes and the COGCC staff is working to develop the appropriate requirements and adjusting to their new operating plan, the time needed to obtain a permit has been prolonged. COGCC rules provide that the permitting process could range between six to twelve months or more from submission to approval.
We cannot predict whether future ballot initiatives or other legislation or regulation will be proposed that would limit the areas of the state in which drilling is permitted to occur or impose other requirements or restrictions.
44
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Wattenberg Permits Update. PDC was granted unanimous approval for an 8-well OGDP
located in rural Weld County in October 2021 , our first approval under the new
permitting process resulting from a company-wide collaborative effort. As part
of the permit process, we successfully obtained consent from all nearby
residents and landowners, which was an option designed by the COGCC for
locations with residential building units within 2,000 feet. Additionally, in
September, we submitted our application for an OGDP covering an approximate
70-well, multi-pad development plan. We anticipate a COGCC determination on
approval of this OGDP in the second quarter of 2022.
In December, PDC submitted our first CAP. The application proposes approximately
450 wells spread amongst 25 surface locations in Weld County , to be developed
over several years. We conducted a comprehensive analysis of potential impacts
and have committed to transport all water and commodity production via pipeline
and to provide electrical infrastructure to all locations. These commitments
will lessen the impact of traffic, noise, light and emissions. Additionally, we
developed a dashboard to analyze disproportionately impacted communities in the
area and developed a robust communication plan designed to encourage
communication with and garner feedback from these key stakeholders. We
anticipate a COGCC determination on approval of our CAP by year end 2022 or
early 2023, recognizing that there may be delays in this new process.
Together, these applications represent our planned Wattenberg Field turn-in-line activity into 2027.
Environmental, Social and Governance
We are committed to a meaningful and measurable ESG strategy. Our mission to be a cleaner, safer and more socially responsible company begins with a sound strategy, is supported in the boardroom and is overseen by our newly created ESG&N Committee at the board of directors and is applied at every level of our business. We recognize the importance of reducing our environmental footprint and have created proactive programs and targets related to emission reduction. These initiatives, which include the plugging and abandonment of legacy vertical wells, retrofits of air pneumatics on older facilities, electrification of our facilities, technological innovations and other activities, require capital and operational investments which are proactively and regularly built into our annual budgeting process. We anticipate approximately$80 million in spending relating to ESG in 2022, which include certain expenditures to ensure compliance with state regulations and the plugging and abandonment of approximately 300 legacy vertical wells. We anticipate a similar level of annual spending over the next several years relating to ESG and compliance to achieve our emission target goals outlined below. We do not anticipate these projects having a material impact on our operations. However, we may revise our 2022 ESG budget during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, a significant change in cash flows or regulatory developments.
During 2021, we implemented the following ESG initiatives:
•Formalized our board oversight of ESG issues by incorporating ESG into our N&G Committee, which became the ESG&N Committee. •Issued a Sustainability Report addressing a variety of ESG and sustainability matters, including significantSustainability Accounting Standards Board compliance. The Sustainability Report is available on our website at www.pdce.com and is not incorporated by reference in this report. •Continued board of directors refreshment by adding two diverse directors and one additional diverse director inFebruary 2022 , reflecting a commitment to diversity, refreshment and independence. •Set aggressive targets to (i) reduce greenhouse gas intensity by 60% from 2020 emissions by 2025 and 74% by 2030, (ii) reduce methane emissions intensity by 50% from 2020 emissions by 2025 and 70% by 2030, and (iii) eliminate routine flaring by 2025.
The
45
--------------------------------------------------------------------------------Results of Operations
Summary of Operating Results
The following table presents selected information regarding our operating results for the periods presented:
Year Ended December 31,
Percent Change
2021 2020 2019 2021-2020 2020-2019
(dollars in millions, except per unit data)
Production:
Crude oil (MBbls) 22,682 23,720 19,166 (4) % 24 %
Natural gas (MMcf) 175,747 165,637 115,950 6 % 43 %
NGLs (MBbls) 19,360 17,042 10,923 14 % 56 %
Crude oil equivalent (MBoe) 71,333 68,368 49,414 4 % 38 %
Average Boe per day (Boe) 195,433 186,798 135,381 5 % 38 %
Crude Oil, Natural Gas and NGLs Sales:
Crude oil $ 1,530.8 $ 816.8 $ 1,020.7 87 % (20) %
Natural gas 519.6 178.8 151.0 191 % 18 %
NGLs 502.2 157.0 135.6 220 % 16 %
Total crude oil, natural gas and NGLs
sales $ 2,552.6 $ 1,152.6 $ 1,307.3 121 % (12) %
Net Settlements on Commodity Derivatives: Crude oil$ (289.1) $ 294.4 $ (18.3) (198) % * Natural gas (121.1) (15.1) 0.7 * *
Total net settlements on derivatives
(247) % *
Average Sales Price (excluding net settlements on derivatives): Crude oil (per Bbl) $ 67.49$ 34.44 $ 53.26 96 % (35) % Natural gas (per Mcf) 2.96 1.08 1.30 174 % (17) % NGLs (per Bbl) 25.94 9.21 12.41 182 % (26) % Crude oil equivalent (per Boe) 35.78 16.86 26.46 112 %
(36) %
Average Costs and Expense (per Boe):
Lease operating expense $ 2.53$ 2.36 $ 2.88 7 % (18) % Production taxes 2.32 0.87 1.63 167 % (47) % Transportation, gathering and processing expenses 1.41 1.14 0.94 24 % 21
%
General and administrative expense 1.79 2.36 3.27 (24) %
(28) %
Depreciation, depletion and amortization 8.90 9.06 13.04 (2) %
(31) %
Lease Operating Expense by Operating Region (per Boe): Wattenberg Field $ 2.19$ 2.15 $ 2.50 2 % (14) % Delaware Basin 4.76 3.48 4.15 37 % (16) % ____________
* Percent change is not meaningful.
46
--------------------------------------------------------------------------------Crude Oil, Natural Gas and NGLs Sales
Crude oil, natural gas and NGLs sales for the year endedDecember 31, 2021 increased compared to the year endedDecember 31, 2020 due to the following: Year Ended December 31, 2021 (in millions) Change in: Production $ (3.5) Average crude oil price 749.7 Average natural gas price 329.9 Average NGLs price 323.9 Total change in crude oil, natural gas and NGLs sales revenue $
1,400.0
The negative impact in sales relating to the change in production volumes during the year endedDecember 31, 2021 compared to 2020 was impacted by a 4 percent decrease in crude oil production between periods.
Crude Oil, Natural Gas and NGLs Production
The following table presents crude oil, natural gas and NGLs production for the
periods presented:
Year Ended December 31,
Percent Change
Production by Operating Region 2021 2020 2019 2021-2020 2020-2019
Crude oil (MBbls)
Wattenberg Field 18,901 19,552 14,489 (3) % 35 %
Delaware Basin 3,781 4,168 4,677 (9) % (11) %
Total 22,682 23,720 19,166 (4) % 24 %
Natural gas (MMcf)
Wattenberg Field 154,150 140,845 91,785 9 % 53 %
Delaware Basin 21,597 24,792 24,165 (13) % 3 %
Total 175,747 165,637 115,950 6 % 43 %
NGLs (MBbls)
Wattenberg Field 17,300 14,495 8,198 19 % 77 %
Delaware Basin 2,060 2,547 2,725 (19) % (7) %
Total 19,360 17,042 10,923 14 % 56 %
Crude oil equivalent (MBoe)
Wattenberg Field 61,892 57,521 37,984 8 % 51 %
Delaware Basin 9,441 10,847 11,430 (13) % (5) %
Total 71,333 68,368 49,414 4 % 38 %
Average crude oil equivalent per day
(Boe)
Wattenberg Field 169,567 157,161 104,066 8 % 51 %
Delaware Basin 25,866 29,637 31,315 (13) % (5) %
Total 195,433 186,798 135,381 5 % 38 %
Net production volumes for oil, natural gas and NGLs increased 4 percent during
the year ended December 31, 2021 compared to 2020. The increase in production
volume between periods was primarily due to a greater number of wells
turned-in-line since the fourth quarter of 2020. This increase was partially
offset by normal decline in production from our existing wells and lower
performance of wells turned-in-line in the Delaware Basin during 2021.
47
--------------------------------------------------------------------------------The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented:
Year Ended December 31,
Production Ratio by Operating Region 2021 2020 2019 Wattenberg Field Crude oil 31 % 34 % 38 % Natural gas 41 % 41 % 40 % NGLs 28 % 25 % 22 % Total 100 % 100 % 100 % Delaware Basin Crude oil 40 % 38 % 41 % Natural gas 38 % 38 % 35 % NGLs 22 % 24 % 24 % Total 100 % 100 % 100 % The change in production mix in the Wattenberg Field during the year endedDecember 31, 2021 compared to 2020 and 2019 was driven by our 2021 development plan being focused on areas that have a higher gas/oil ratio and due to less bypass processing of gas which increased our NGLs ratio and economics.
Midstream Capacity
Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, as well as transportation pipelines out of the basin, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. The ultimate timing and availability of adequate infrastructure remains out of our control. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to sufficiently meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls. Our production from the Wattenberg Field andDelaware Basin was not materially affected by midstream or downstream capacity constraints during the year endedDecember 31, 2021 . We continuously monitor infrastructure capacities versus producer activity and production volume forecasts.
Crude Oil, Natural Gas and NGLs Pricing
Our results of operations depend upon many factors. Key factors include market
prices of crude oil, natural gas and NGLs and our ability to market our
production effectively. Crude oil, natural gas and NGLs prices have a high
degree of volatility and our realizations can change substantially. Our weighted
average realized commodity prices increased 112 percent during 2021 as compared
to 2020. The NYMEX average daily crude oil and NYMEX first-of-the-month natural
gas prices increased 72 percent and 81 percent, respectively, as compared
to 2020.
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--------------------------------------------------------------------------------The following table presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented:
Year Ended December 31,
Weighted Average Realized Sales Price by Operating Region Percent Change (excluding net settlements on derivatives) 2021 2020 2019 2021-2020 2020-2019 Crude oil (per Bbl) Wattenberg Field$ 67.49 $ 34.21 $ 52.99 97 % (35) % Delaware Basin 67.47 35.48 54.08 90 % (34) % Weighted average price 67.49 34.44 53.26 96 % (35) % Natural gas (per Mcf) Wattenberg Field 2.98 1.22 1.49 144 % (18) % Delaware Basin 2.81 0.28 0.57 * (51) % Weighted average price 2.96 1.08 1.30 174 % (17) % NGLs (per Bbl) Wattenberg Field 24.77 8.84 11.51 180 % (23) % Delaware Basin 35.72 11.32 15.12 216 % (25) % Weighted average price 25.94 9.21 12.41 182 % (26) % Crude oil equivalent (per Boe) Wattenberg Field 34.95 16.84 26.31 108 % (36) % Delaware Basin 41.25 16.94 26.95 144 % (37) % Weighted average price 35.78 16.86 26.46 112 % (36) % ____________
* Percent change is not meaningful.
Crude oil, natural gas and NGLs revenues are recognized when we transfer control
of crude oil, natural gas or NGLs production to the purchaser. We consider the
transfer of control to occur when the purchaser has the ability to direct the
use of, and obtain substantially all of the remaining benefits from the crude
oil, natural gas or NGLs production.
Our crude oil, natural gas and NGLs sales are recorded using either the
"net-back" or "gross" method of accounting, depending upon the related purchase
agreement. We use the net-back method when control of the crude oil, natural gas
or NGLs has been transferred to the purchasers of these commodities that are
providing transportation, gathering or processing services. In these situations,
the purchaser pays us based on a percent of proceeds or a sales price fixed at
index less specified deductions. The net-back method results in the recognition
of a net sales price that is lower than the index on which the production is
based because the operating costs and profit of the midstream facilities are
embedded in the net price we are paid. We use the gross method of accounting
when control of the crude oil, natural gas or NGLs is not transferred to the
purchaser and the purchaser does not provide transportation, gathering or
processing services as a function of the price we receive. Rather, we contract
separately with midstream providers for the applicable transportation and
processing on a per unit basis. Under this method, we recognize revenues based
on the gross selling price and recognize transportation, gathering and
processing ("TGP") expense.
49
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Information related to the components and classifications of TGP expense on the
consolidated statements of operations is shown below. For crude oil, the average
NYMEX prices shown below are based on average daily prices throughout each month
and, for natural gas, the average NYMEX pricing is based on first-of-the-month
index prices, as in each case this is the method used to sell the majority of
these commodities pursuant to terms of the relevant sales agreements. For NGLs,
we use the NYMEX crude oil price as a reference for presentation purposes. The
average realized price both before and after TGP expense shown in the table
below represents our approximate composite per barrel price for NGLs for the
periods presented.
Average Realized Average Realization Average Realized Average Realization
Average Price Before TGP Percentage Before Average TGP Price After TGP Percentage After TGP
2021 NYMEX Price Expense TGP Expense Expense(1) Expense Expense
Crude oil (per Bbl) $ 67.92 $ 67.49 99 % $ 3.10 $ 64.39 95 %
Natural gas (per MMBtu) 3.76 2.96 79 % 0.13 2.83 75 %
NGLs (per Bbl) 67.92 25.94 38 % - 25.94 38 %
Crude oil equivalent (per
Boe) 49.29 35.78 73 % 1.30 34.48 70 %
Average Realized Average Realization Average Realized Average Realization
Average Price Before TGP Percentage Before Average TGP Price After TGP Percentage After TGP
2020 NYMEX Price Expense TGP Expense Expense(1) Expense Expense
Crude oil (per Bbl) $ 39.40 $ 34.44 87 % $ 2.34 $ 32.10 81 %
Natural gas (per MMBtu) 2.08 1.08 52 % 0.12 0.96 46 %
NGLs (per Bbl) 39.40 9.21 23 % - 9.21 23 %
Crude oil equivalent (per
Boe) 28.52 16.86 59 % 1.10 15.76 55 %
Average Realized Average Realization Average Realized Average Realization
Average Price Before TGP Percentage Before Average TGP Price After TGP Percentage After TGP
2019 NYMEX Price Expense TGP Expense Expense(1) Expense Expense
Crude oil (per Bbl) $ 57.03 $ 53.26 93 % $ 1.24 $ 52.02 91 %
Natural gas (per MMBtu) 2.63 1.30 49 % 0.17 1.13 43 %
NGLs (per Bbl) 57.03 12.41 22 % 0.10 12.31 22 %
Crude oil equivalent (per
Boe) 40.95 26.46 65 % 0.90 25.56 62 %
____________
(1) Average TGP expense excludes unutilized firm transportation fees of $0.11 ,
$0.04 , and $0.04 per Boe for the years ended December 31, 2021 , 2020, and 2019,
respectively.
Our average realization percentages for crude oil, natural gas and NGLs
increased in 2021 as compared to 2020 primarily due to the overall increase in
commodity prices between periods driven by the improvement in oil and gas
product demand that occurred throughout 2021. Additionally, we realized improved
differentials resulting from 2021 sales contracts.
Commodity Price Risk Management
We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price exchanges, and basis protection exchanges on a portion of our estimated crude oil and natural gas production. For our commodity exchanges, we ultimately realize the fixed price value related to the swaps. See Note 7 - Commodity Derivative Financial Instruments in Item 8. Financial Statements and Supplementary Data included elsewhere in this report for a summary of our derivative positions as ofDecember 31, 2021 . Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, and the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production. 50 -------------------------------------------------------------------------------- Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward price curves and changes in certain differentials.
The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net:
Year Ended December 31,
2021 2020 2019
(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price exchanges $ (289.1) $ 294.4 $ (18.3)
Natural gas collars and fixed price exchanges (120.1) (1.4) 8.8
Natural gas basis protection exchanges (1.0) (13.7) (8.1)
Total net settlements of commodity derivative
instruments (410.2) 279.3 (17.6)
Change in fair value of unsettled commodity
derivative instruments:
Reclassification of settlements included in prior
period changes in fair value of commodity derivative
instruments 49.3 (19.9) (81.1)
Crude oil collars and fixed price exchanges (269.3) (49.8) (62.1)
Natural gas collars and fixed price exchanges (61.7) (7.8) 0.1
Natural gas basis protection exchanges (9.6) (21.5) (2.1)
Net change in fair value of unsettled commodity
derivative instruments (291.3) (99.0) (145.2)
Total commodity price risk management gain (loss),
net $ (701.5) $ 180.3 $ (162.8) The significant increase in commodity prices during 2021 had an overall unfavorable impact on the fair value and settlements of our commodity derivatives.
Lease Operating Expense
Lease operating ("LOE") expense increased by 12 percent to $180.7 million in
2021 compared to $161.3 million in 2020. The period-over-period increase in LOE
was primarily due to (i) increased activities and payroll costs at our well
locations from the COVID-19 induced downturn in 2020, (ii) $5.6 million of
additional environmental and regulatory costs in 2021, and (iii) fewer vendor
concessions experienced in 2021 as compared to 2020 as the price of commodities
has improved. LOE per Boe increased 7 percent to $2.53 in 2021 from $2.36 in
2020.
Production Taxes
Production taxes are comprised mainly of severance tax and ad valorem tax, and
are directly related to crude oil, natural gas and NGLs sales and are generally
assessed as a percentage of net revenues. From time to time, there are
adjustments to the statutory rates for these taxes based upon certain credits
that are determined based upon activity levels and relative commodity prices.
Production taxes increased 178 percent to $165.2 million in 2021 compared to
$59.4 million in 2020. Production taxes per Boe increased 167 percent to $2.32
in 2021 compared to $0.87 in 2020. The increase in production taxes was
primarily due to an increase in crude oil, natural gas and NGLs prices between
periods.
51
--------------------------------------------------------------------------------Transportation, Gathering and Processing Expense
TGP expense increased 29 percent to$100.4 million in 2021 compared to$77.8 million in 2020. TGP per Boe increased to$1.41 for 2021 compared to$1.14 for 2020. The overall increase in TGP expense for 2021 compared to 2020 was driven by a$14.4 million increase relating to transportation of our crude oil volumes delivered and a$5.1 million increase in unutilized transportation fees relating to our delivery commitment in theDelaware Basin .
Impairment of Properties and Equipment
The following table sets forth the major components of our impairment of properties and equipment for the periods presented:
Year Ended December 31,
2021 2020 2019
(in millions)
Impairment of proved and unproved properties $ 0.4 $
881.2
Impairment of infrastructure and other - 1.2 27.9
Total impairment of properties and equipment $ 0.4 $
882.4
There were no significant impairment charges recognized related to our proved and unproved oil and gas properties in 2021. If crude oil prices decline, or we change other estimates impacting future net cash flows (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas properties could be subject to additional impairments in future periods. During the first quarter of 2020, we recorded impairment charges of$881.1 million to our proved and unproved properties in theDelaware Basin . These impairment charges were due to a significant decline in crude oil prices, which was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment.
General and Administrative Expense
General and administrative expense decreased to$127.7 million in 2021 compared to$161.1 million in 2020 primarily due to$30.0 million in transaction and transition costs incurred in 2020 related to the SRC Acquisition and consultant fees related to our ERP implementation of$5.3 million .
Depreciation, Depletion and Amortization Expense
Crude oil and natural gas properties. During 2021 and 2020, we invested$583.6 million and$522.3 million , respectively, exclusive of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties. Depreciation, depletion and amortization expense ("DD&A") related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was$627.5 million and$611.0 million in 2021 and 2020, respectively. The increase in total DD&A expense was primarily due to an increase in production volumes as our weighted average depletion rate between periods was comparable. The decrease in weighted average depletion rate during 2021 compared to 2020 was driven by an increase in proved reserves in our Wattenberg Field as a result of improved commodity prices during 2021. 52 --------------------------------------------------------------------------------
The year-over-year change in DD&A expense for related to crude oil and natural gas properties was primarily due to the following:
Year Ended December
31,
2021
(in millions)
Increase in production $ 24.8Decrease in weighted average depreciation, depletion and amortization rates
(8.3)
Total decrease in DD&A expense related to crude oil and natural gas
properties $ 16.5
The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties for the periods presented:
Year Ended December 31,
2021 2020 2019
(per Boe)
Operating Region /Area
Wattenberg Field $ 8.68 $ 8.80 $ 11.77
Delaware Basin 9.59 9.68 16.76
Total weighted average DD&A expense rate 8.80 8.94 12.92
Non-crude oil and natural gas properties. Depreciation expense for non-crude oil
and natural gas properties was
Interest Expense, net
Interest expense, net decreased by$6.0 million to$82.7 million in 2021 compared to$88.7 million in 2020. The decrease was primarily related to reduced borrowings under our revolving credit facility, a full redemption of our 2025 Senior Notes and a partial redemption of our 2024 Senior Notes. These decreases were partially offset by a$6.1 million increase in interest expense related to the issuance of an additional$150 million aggregate principal amount of the 2026 Senior Notes inSeptember 2020 and a$6.9 million loss on extinguishment from partial redemption of our 2024 Senior Notes and full redemption of our 2025 Senior Notes. Provision for Income Taxes We recorded income tax expense of$26.6 million for 2021 and an income tax benefit of$7.9 million for 2020, resulting in effective tax rates of 4.8 percent and 1.1 percent on the respective pre-tax income or loss. The effective tax rates differ from the amount that would be provided by applying the statutoryU.S. federal income tax rate of 21 percent to the pre-tax loss due to the effect of a valuation allowance against our deferred income tax assets atDecember 31, 2021 and 2020. The ultimate realization of deferred tax assets ("DTAs") is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. The oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to continue to provide a valuation allowance against our DTAs as ofDecember 31, 2021 and 2020 since we cannot conclude that it is more likely than not that our DTAs will be fully realized in future periods. Future events or new evidence which may lead us to conclude that it is more likely than not that our DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. Given recent improvements in oil and gas prices and improvements in our current earnings, we believe there is a reasonable possibility that, if oil and natural gas prices remain similar toDecember 31, 2021 pricing levels, sufficient positive evidence may become available within the next 12 months to allow us to reach a conclusion that all or a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense in 53 --------------------------------------------------------------------------------
the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change based on the level of profitability that we actually achieve.
Given recent improvements in oil and gas prices and assumptions based on our current production forecasts, we estimate that we will begin to incur cash federal and state income taxes again in 2022 and 2023.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors impacting net income of
Adjusted net income, a non-U.S. GAAP financial measure, was$799.6 million and for the year endedDecember 31, 2021 and adjusted net loss, a non-U.S. GAAP financial measure, was$625.3 million for the year endedDecember 31, 2020 . With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income (loss). See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparableU.S. GAAP measures.
Financial Condition, Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash and cash equivalents, cash flows from operating activities, unused borrowing capacity from our revolving credit facility, proceeds raised in debt and equity capital market transactions and other sources, such as asset sales. Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile, and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions, capital returns and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as ofDecember 31, 2021 is an indication of a lack of liquidity. We had working capital deficits of$461.5 million and$471.6 million atDecember 31, 2021 and 2020, respectively. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time. From time to time, we may seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise.
Liquidity
Our cash and cash equivalents were$33.8 million atDecember 31, 2021 and availability under our revolving credit facility was$1.48 billion , providing for total liquidity of$1.51 billion as ofDecember 31, 2021 . The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests.
Our material short-term and long-term cash requirements consist primarily of capital expenditures, payments of contractual obligations, dividends, share repurchases and working capital obligations. As commodity prices improve, our
54
--------------------------------------------------------------------------------working capital requirements may increase due to higher operating costs and negative settlements on our outstanding commodity derivative contracts. Funding for these requirements may be provided by any combination of our capital resources previously outlined.
OnFebruary 26, 2022 , we entered into the Acquisition Agreement to acquire Great Western for approximately$1.3 billion , inclusive of Great Western's net debt. Under the terms of the Acquisition Agreement, the purchase price of the Great Western Acquisition will consist of approximately 4.0 million shares of our common stock and approximately$543 million in cash. The cash portion of the purchase price is expected to be funded through a combination of cash on hand and availability under our revolving credit facility. We expect the Great Western Acquisition to be completed in the second quarter of 2022, subject to certain customary closing conditions. Upon closing the Great Western Acquisition, we will be required to pay off and terminate Great Western's revolving credit facility, which had an outstanding balance of$242.0 million as ofDecember 31, 2021 . At closing, we are also expecting to pay off Great Western's$311.9 million 12.0% Senior Notes dueSeptember 1, 2025 , plus a redemption premium. The payments of the debt balances will be funded through the availability under our revolving credit facility. Based on our current production forecast for 2022, we expect 2022 cash flows from operations, which are net of expected cash federal and state income taxes, to exceed our capital investments in crude oil and natural gas properties by approximately$1.1 billion . In addition, based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to fund our planned activities through the 12-month period following the filing of this report. We also believe that we will have sufficient expected cash flows from operations to allow us to execute our capital return plan. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board. Our material cash requirements greater than twelve months from various contractual and other obligations include debt obligations and interest payments; commodity derivative contract liabilities; production taxes; operating and finance leases; asset retirement obligations; and firm transportation and processing agreements included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 3.5:1.0. For purposes of the current ratio covenant, the revolving credit facility's definition of total current assets, in addition to current assets as presented underU.S. GAAP, includes, among other things, unused commitments under the revolving credit facility. Additionally, the current ratio covenant calculation allows us to exclude the current portion of our long-term debt and other short-term loans from theU.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit underU.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. AtDecember 31, 2021 , we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.1:1.0 and a leverage ratio of 0.6:1.0. We expect to remain in compliance with the covenants under our credit facility and our Senior Notes throughout the 12-month period following the filing of this report. 55 --------------------------------------------------------------------------------
Cash Flows
Our cash flows from operating, investing and financing activities are as
follows:
Year ended December 31,
2021 2020 2019
(in thousands)
Cash flows from operating activities $ 1,547,796 $ 870,079 $ 858,226
Cash flows from investing activities (578,804) (687,159) (677,772)
Cash flows from financing activities (937,786) (181,260) (188,890)
Net increase (decrease) in cash and cash
equivalents $ 31,206 $ 1,660 $ (8,436)
Operating Activities. Our net cash flows from operating activities are primarily
impacted by commodity prices, production volumes, net settlements from our
commodity derivative positions, operating costs and general and administrative
expenses. Cash flows from operating activities increased by $677.7 million to
$1,547.8 million in 2021 as compared to $870.1 million in 2020. The increase
between periods was primarily due to a $1.4 billion increase in crude oil,
natural gas and NGLs sales, a $33.4 million decrease in general and
administrative expense, and changes in the timing of vendor payments. These
increases were partially offset by $410.2 million in cash settlement losses on
commodity derivatives in 2021 compared to $279.3 million in cash receipts from
derivative settlements in 2020, a $105.8 million increase in production taxes
and changes in the timing of receivable collections between periods.
Adjusted cash flows from operations, a non-U.S. GAAP financial measure,
increased by $611.0 million in 2021 to $1,532.6 million from $921.6 million in
2020. The increase was primarily due to the factors mentioned above for changes
in cash flows provided by operating activities, without regard to timing of cash
payments and receipts of assets and liabilities. Adjusted free cash flow, a
non-U.S GAAP financial measure, increased by $549.7 million in 2021 to $949.0
million from $399.3 million in 2020. The increase was primarily due to the
increase in cash flows from operating activities, as discussed above.
See Reconciliation of Non-
Investing Activities. As crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our crude oil and natural reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments. Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of$578.8 million during 2021 was primarily related to our drilling and completion activities of$583.1 million , partially offset by$5.1 million in proceeds from the sale of certain properties and equipment.
Net cash used in investing activities of
Financing Activities. Net cash used in financing activities in 2021 of$937.8 million was primarily due to (i) net repayments on our credit facility of$168.0 million , (ii) redemption and retirement of our 2021 Convertible Notes and 2025 Senior Notes for$200 million and$105.5 million , respectively, (iii) partial redemption and retirement of our 2024 Senior Notes for$203.1 million , (iv) the repurchase of 3.8 million shares of our common stock for$156.8 million pursuant to our Stock Repurchase Program and (v) dividend payments totaling$83.6 million . Repurchases of our common stock may extend into 2023 based on current market conditions, although our board of directors could elect to suspend or terminate the program at any time, including if certain share price parameters are not achieved. As ofDecember 31, 2021 ,$187.3 million out of the approved$525 million remained available for repurchases under the program. InFebruary 2022 , our board of directors increased the size of the program to$1.25 billion , which we anticipate fully utilizing byDecember 31, 2023 . Future repurchases of common stock 56 -------------------------------------------------------------------------------- or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board. Net cash used in financing activities in 2020 of$181.3 million was primarily due to the redemption of a portion of the 2025 Senior Notes totaling$452.2 million , the repurchase and retirement of shares of our common stock totaling$23.8 million pursuant to the Stock Repurchase Program and$9.3 million related to purchases of our stock for employee stock-based compensation tax withholding obligations. These financing cash outflows were financed by our net borrowings from our credit facility of$164 million , proceeds from the issuance of 2026 Senior Notes of$148.5 million and cash flows from operating activities.
Subsidiary Guarantor
PDC Permian, Inc. , aDelaware corporation (the "Guarantor"), our wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes and 2026 Senior Notes (collectively, the "Senior Notes"). The Guarantor holds our assets located in theDelaware Basin . The Senior Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions. The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (iii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. 57 -------------------------------------------------------------------------------- The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. As of/Year Ended December 31, 2021 2020 Issuer Guarantor Issuer Guarantor (in millions) Assets Current assets$ 402.6 $ 56.0 $ 271.4 $ (57.8) Intercompany accounts receivable, guarantor subsidiary - 40.8 107.3 - Investment in guarantor subsidiary 1,767.2 - 1,767.2 - Properties and equipment, net 3,875.0 939.9 3,982.1 877.1 Other non-current assets 58.5 4.8 56.6 4.3 Liabilities Current liabilities$ 862.5 $ 57.6 $ 751.3 $ 28.5 Intercompany accounts payable 27.9 - - 94.2 Long-term debt 942.1 - 1,409.5 - Other non-current liabilities 392.3 172.0 254.9 178.1 Statement of Operations Crude oil, natural gas and NGLs sales$ 2,163.1 $ 389.5 $ 968.8 $ 183.7 Commodity price risk management gain (loss), net (701.5) - 180.3 - Total revenues 1,464.5 391.4 1,151.5 182.5 Production costs 892.4 189.0 740.7 177.5 Gross profit (1) 1,270.7 200.4 228.1 6.2 Impairment of properties and equipment 0.4 - 2.0 880.4 Net income (loss) 327.7 194.9 (49.2) (670.0) ____________
(1)Gross profit is calculated as crude oil, natural gas and NGLs sales less production costs.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance withU.S. GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. Our significant accounting policies are described in Note 2 - Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. The following discussion outlines the accounting policies and practices involving the use of estimates and application of significant judgment that are critical in determining our financial results. Changes in the estimates and assumptions discussed below could materially affect the amount or timing of our financial results.
Crude Oil and Natural Gas Reserve Quantities
We account for our crude oil and natural gas properties under the successful
efforts method of accounting. Under this method, costs of proved developed
producing properties, successful exploratory wells and developmental dry hole
costs are capitalized and depleted by the unit-of-production method based on
estimated proved developed producing reserves. The successful efforts method
inherently relies on the estimation of proved crude oil, natural gas and NGL
reserves. In determining the estimates of reserve and economic evaluations,
management utilizes independent petroleum engineers. Reserve quantities and the
related estimates of future net cash flows are used as inputs in our calculation
of depletion, evaluation of proved
58
--------------------------------------------------------------------------------properties for impairment, assessment of expected realizability of our deferred income tax assets and calculation of the standardized measure of discounted future net cash flows.
The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include future production volumes, future operating and development costs and historical commodity prices. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, we continually make revisions to reserve estimates as additional information becomes available. We cannot predict the amounts or timing of such future revisions. If the estimates of proved reserve quantities decline, the rate at which we record depletion expense will increase, which would reduce future net income. Changes in depletion rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified. We cannot reasonably predict future commodity prices. However, assuming all other factors are held constant, we performed a sensitivity analysis on our proved reserve estimates as ofDecember 31, 2021 , to present a decrease of approximately 10 percent in crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. Our proved reserve quantities would decrease by 4.3 MMBoe (1%) and our PV-10 of our proved reserves would decrease by$1.1 billion (11%). During 2021, we had positive revisions to our proved reserve quantities of 52.9 MMBoe as a result of higher average prices for crude oil, natural gas and NGLs. During 2020 and 2019, we had negative revisions of 39.5 and 16.5 MMBoe, respectively, as a result of lower average prices for crude oil, natural gas and NGLs. For more information regarding reserve estimations, including additional crude oil sensitives and descriptions over historical reserve revisions, see Items 1 and 2. Business and Properties - Oil and Gas Production and Operations andSupplemental Oil and Gas Information within our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data included elsewhere in this report.
Impairment of
Upon a triggering event, we assess the valuation of our proved crude oil and
natural gas properties for possible impairment by comparing the carrying value
to estimated undiscounted future net cash flows on a field-by-field basis using
estimated production and prices at which we estimate the commodity will be sold.
If carrying values exceed undiscounted future net cash flows, the measurement of
impairment is based on estimated fair value utilizing a discounted future cash
flows analysis. We estimate the fair value of proved crude oil and natural gas
properties using valuation techniques that convert future cash flows to a single
discounted amount.
Significant inputs and assumptions to the valuation of proved crude oil and
natural gas properties include estimates of reserves volumes, future operating
and development costs, future commodity prices, and a discount factor. Future
commodity prices are estimated by using a combination of assumptions management
uses in its budgeting and forecasting process, historical and future prices
adjusted for geographical location and quality differentials, as well as other
factors that management believes will impact realizable prices. The discount
factor used is the market based weighted average cost of capital which is based
on rates utilized by market participants that are commensurate with the risks
inherent in the development and production of the underlying crude oil and
natural gas.
Unproved properties with individually significant acquisition costs are
periodically assessed for impairment and reduced to fair value based on a review
over our future development plans, estimated future cash flows for probable well
locations and remaining average lease terms. Items that can impact our future
development plans can be driven by drilling results, reservoir performance,
capital resources and seismic interpretations. Changes in our assumptions of the
estimated nonproductive portion of our undeveloped leases could result in
additional impairment expense.
Although our cash flow estimates are based on the relevant information available
at the time the estimates are made, estimates of future cash flows are, by their
nature, highly uncertain and may vary significantly from actual results. We
cannot predict when or if future impairment charges will be recorded because of
the uncertainty in the factors discussed above.
59
--------------------------------------------------------------------------------
There were no significant impairment charges recognized related to our proved
and unproved properties during the year ended December 31, 2021 . We recorded
impairment charges of $881.1 million to our proved and unproved properties to
our Delaware Basin properties in 2020 as a result of the significant decline in
crude oil prices.
Valuation of Business Combinations
We follow the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any deficiency of the purchase price over the estimated fair values of the net assets acquired is recorded as a gain in statements of operations. In estimating the fair values of assets acquired and liabilities assumed the most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Additionally, for acquisitions with significant unproved properties, we may also review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties to determine an estimation of fair value. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value. There were no business combinations during the year endedDecember 31, 2021 .
Recent Accounting Pronouncements
There were no significant new accounting standards adopted or new accounting
pronouncements that would have potential effect on us as of
Reconciliation of Non-
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 underU.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 withU.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 60 -------------------------------------------------------------------------------- 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. PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. 61 -------------------------------------------------------------------------------- The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparableU.S. GAAP measure for the periods presented: Year Ended December 31, 2021 2020 2019 (thousands) Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow: Net cash from operating activities$ 1,547.8 $ 870.1 $ 858.2 Changes in assets and liabilities (15.2) 51.5 (32.8) Adjusted cash flows from operations 1,532.6 921.6 825.4 Capital expenditures for development of crude oil and natural gas properties (583.1) (551.0) (855.9) Change in accounts payable related to capital expenditures for oil and gas development activities (0.5) 28.7 68.2 Adjusted free cash flow$ 949.0 $
399.3
Net income (loss) to adjusted net income (loss): Net income (loss)$ 522.3 $ (724.3) $ (56.7) Loss (gain) on commodity derivative instruments 701.5 (180.3) 162.8 Net settlements on commodity derivative instruments (410.2) 279.3 (17.6) Tax effect of above adjustments (1) (14.0) - (35.2) Adjusted net income (loss)$ 799.6 $
(625.3)
Net income (loss) to adjusted EBITDAX: Net income (loss)$ 522.3 $ (724.3) $ (56.7) Loss (gain) on commodity derivative instruments 701.5 (180.3) 162.8 Net settlements on commodity derivative instruments (410.2) 279.3 (17.6) Non-cash stock-based compensation 23.0 22.2 23.8 Interest expense, net 82.7 88.7 71.1 Income tax expense (benefit) 26.6 (7.9) (3.3) Impairment of properties and equipment 0.4 882.4 38.5 Exploration, geologic and geophysical expense 1.1 1.4 4.1 Depreciation, depletion and amortization 635.2 619.7 644.2 Accretion of asset retirement obligations 12.1 10.1 6.1 Loss (gain) on sale of properties and equipment (0.9) (0.7) 9.7 Adjusted EBITDAX$ 1,593.8 $
990.6
Cash from operating activities to adjusted EBITDAX: Net cash from operating activities
$ 1,547.8 $ 870.1 $ 858.2 Interest expense, net (2) 75.8 88.7 71.1 Amortization and write-off of debt discount, premium and issuance costs (13.5) (16.8) (13.6) Exploration, geologic and geophysical expense 1.1 1.4 4.1 Other (2.2) (4.3) (4.3) Changes in assets and liabilities (15.2) 51.5 (32.8) Adjusted EBITDAX$ 1,593.8 $ 990.6 $ 882.7 PV-10:
Standardized measure of discounted future net cash flows
$ 7,908.2 $ 3,282.2 $ 3,310.3 Present value of estimated future income tax discounted at 10% 1,800.6 172.4 526.7 PV-10$ 9,708.8 $ 3,454.6 $ 3,837.0 _____________ (1)Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the year endedDecember 31, 2020 . (2)Excludes loss on extinguishment from early retirement of our senior notes amounting to$6.9 million for the year endedDecember 31, 2021 . 62
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