ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 2020 to 2021 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 ended December 31, 2021, filed with the SEC on February 28, 2022. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements in Part I of this report.
EXECUTIVE SUMMARY
2022 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. During 2022, crude oil and natural gas prices experienced high levels of volatility. NYMEX WTI spot prices for crude oil reached a high of $130.50 per barrel in March and a low of $70.08 per barrel in December and NYMEX Henry Hub spot prices for natural gas reached a high of $9.85 per MMBtu in August and a low of $3.46 per MMBtu in November. By the end of 2022, crude oil and natural prices had declined significantly from the levels seen earlier in the year.
Crude Oil Markets
During the first half of 2022, crude oil pricing generally increased due to increased demand, restrained OPEC+ production and uncertainties resulting from the Russian invasion of Ukraine. However, throughout 2022, the U.S. has experienced the highest inflation rates since 1981 resulting mainly from the global recovery from COVID-19, supply chain disruptions, higher labor costs, and higher energy costs. To address the increasing inflation rates, the U.S. Federal Reserve started increasing the benchmark federal funds interest rate. The magnitude and overall effectiveness of these actions remains uncertain, but such monetary policy changes can increase the risk of economic slowdown and/or lead to a recession. A slowdown or recession can cause a decrease in short-term or long-term demand for commodities, resulting in industry oversupply and a potential for lower commodity prices, which would impact our drilling program and further increase the volatility of our common stock price.
Natural Gas and NGL Markets
In addition to the crude oil market drivers noted above, natural gas and NGL prices are also affected by structural changes in supply and demand, growth in levels of liquified natural gas and liquified petroleum gas exports and deviations from seasonally normal weather. Europe’s shift away from Russia’s natural gas has led to Europe becoming increasingly dependent on U.S. LNG exports, creating new sources of demand for U.S. natural gas.
Lower inventory levels and lack of reinvestment in supply growth led to higher natural gas and NGL prices in 2022. However, a warmer winter in some parts of the world and a weakened economy has driven down the price of natural gas in early 2023.
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Financial Matters
Year ended December 31, 2022
• Production volumes increased to 85.0 MMboe in 2022, an increase of 19 percent compared to 71.3 MMboe in 2021, primarily driven by production volumes from the Great Western Acquisition and as a result of our turn-in-line activities in 2022.
• Crude oil, natural gas and NGLs sales increased to $4.3 billion in 2022 compared to $2.6 billion in 2021, primarily due to a 41 percent increase in weighted average realized commodity prices and a 19 percent increase in production volumes between periods.
• Negative net cash settlements from our commodity derivative contracts increased to $880 million in 2022 compared to $410 million in 2021 due to continued improvement in commodity pricing year over year and additional commodity derivatives assumed in the Great Western Acquisition.
• Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 59 percent to $3.4 billion from $2.1 billion in 2021.
• Net income increased to $1,778 million, or $18.49 per diluted share, compared to $522 million, or $5.22 per diluted share, in 2021, primarily due to (i) an increase in crude oil, natural gas and NGLs sales of $1,744 million, (ii) a $238 million decrease in net commodity risk management loss and (iii) a gain on bargain purchase in the Great Western Acquisition of $90 million . These positive factors were partially offset by (i) a $428 million increase in income tax expense (ii) a $253 million increase in production costs and (iii) a $115 million increase in depreciation, depletion and amortization expense between periods.
• Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $2.7 billion compared to $1.6 billion in 2021, primarily due to an increase in sales of $1.3 billion, net of negative net derivative settlements, and a $90 million gain on bargain purchase recognized in 2022, partially offset by an increase in costs experienced in operations between periods.
• Cash flows from operations increased to $2.8 billion compared to $1.5 billion in 2021 primarily due to an increase in sales of $1.3 billion, net of negative net derivative settlements, partially offset by an increase in costs experienced in operations between periods. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to $2.5 billion compared to $1.5 billion in 2021. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to $1,421 million from $949 million in 2021.
See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.
Great Western Acquisition
On May 6, 2022, we completed the acquisition of Great Western for approximately $1.4 billion, inclusive of Great Western’s net debt. Great Western was an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. The consideration paid was $542.5 million in cash and approximately 4.0 million shares of our common stock, valued at $293.3 million on the acquisition date. In addition, we paid off Great Western’s secured credit facility totaling $235.8 million, and paid $361.2 million to terminate Great Western’s 12 percent senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash portion of the purchase price and the termination of Great Western’s debt was funded through a combination of cash on hand and availability under our revolving credit facility. As a result of the Great Western Acquisition, we acquired approximately 54,000 net acres in the core Wattenberg Field and production of approximately 50,000 Boe per day.
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Drilling, Completion and Vertical Wells Abandonment Overview
In the Wattenberg Field, we operated one full-time drilling rig and one full-time completion crew during 2022, added a second full-time drilling rig in March 2022 and a third full-time drilling rig plus an intermittent completion crew in May 2022 upon closing the Great Western Acquisition . In addition, we operated one full-time drilling rig during 2022 and had one completion crew in the first half of 2022 in the Delaware Basin. Our total capital investments in crude oil and natural gas properties for the year ended December 31, 2022 were $1.1 billion. Pursuant to our plugging and abandonment program, we operated a full-time workover rig in the Wattenberg Field in 2022. The workover rig was focused on our legacy vertical wells to assist in our horizontal drilling program and to reduce our overall produced well emissions. Separate from our capital investments, we spent $21 million on this program in 2022.
The following table summarize our drilling, completion and vertical well abandonment activities for the year ended December 31, 2022:
Operated Wells
Wattenberg Field
Delaware Basin
Total
Gross
Net
Gross
Net
Gross
Net
In-process as of December 31, 2021
Wells spud
Wells acquired in-process (1)
Wells turned-in-line
Developmental and exploratory dry hole
In-process as of December 31, 2022
Plugged and abandoned - Vertical Wells
(1) Represents in-process wells we obtained as part of the Great Western Acquisition.
Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling.
Capital Returns
Stock Repurchase Program. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.3 billion, which we currently anticipate fully utilizing by December 31, 2023. We repurchased 12.1 million shares of outstanding common stock at a cost of $823 million for the year ended December 31, 2022. As of December 31, 2022, $455 million remained available for repurchase under the program. In February 2023, our board of directors approved a $750 million increase in the size of the program, which we currently anticipate fully utilizing by December 31, 2025.
Dividends . Our board of directors approved the declaration and payment of a quarterly cash dividend of $0.25 per share of common stock in the first quarter of 2022 and increased our base quarterly dividend to $0.35 per share of common stock in the second quarter of 2022. In December 2022, our board of directors declared and paid a special dividend of $0.65 per share of our common stock in addition to the regular fourth quarter dividend. For the year ended December 31, 2022, our dividends declared totaled $184 million or $1.95 per share of outstanding common stock. In February 2023, our board of directors approved an increase in the quarterly base dividend from $0.35 to $0.40 per share.
2023 Operational and Financial Outlook
We anticipate that our production for 2023 will range between 255,000 Boe to 265,000 Boe per day, of which approximately 82,000 Bbls to 86,000 Bbls is expected to be crude oil. Our planned 2023 capital investments in crude oil and natural gas properties, which we expect to be between $1,350 million and $1,500 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. Our 2023 capital budget and operating costs may continue to be impacted by cost inflation, supply chain constraints and availability of labor services.
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We have operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory to best meet our short- and long-term corporate strategy. We may revise our 2023 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds and acquisition and divestiture opportunities.
Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field. Our 2023 capital investment program for the Wattenberg Field represents approximately 80 percent of our expected total capital investments in crude oil and natural gas properties. Our plan includes spudding and turning-in-line 200 to 225 operated wells. To meet our development plan, we intend on running three full-time horizontal drilling rigs and one full-time completion crew plus an intermittent completion crew during the year. As of December 31, 2022, we have approximately 200 gross operated DUCs and 915 approved permitted or CAP locations (i.e., locations that are contemplated by an approved CAP but still require approval under an OGDP).
Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2023 are expected to be approximately 20 percent of our total capital investments. In 2023, we anticipate spudding and turning-in-line 15 to 25 operated wells.
We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2023, we expect 2023 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Our first priority is to pay our quarterly base dividend of $0.40 per share. Then we expect to use approximately 60 percent or more of our remaining adjusted free cash flow, a non-U.S. GAAP financial measure, for share repurchases and special dividends, as needed. Any remaining adjusted free cash flows will be used for reducing debt and other general corporate purposes.
Regulatory and Political Updates
Colorado law requires an operator to obtain an OGDP prior to initiating development work relating to a well. The OGDP process streamlines single pad locations or proximate multi-pad locations into a single permitting package.
Operators in Colorado also have an option to pursue a CAP. A CAP is designed to represent an overview of oil and gas development over a larger area over a longer period of time through means 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.
In June 2022, the COGCC granted PDC unanimous approval for a 69-well OGDP and a 30-well OGDP acquired in the Great Western Acquisition, our second and third approvals under the new Colorado permitting process. Additionally, in December 2022, the COGCC unanimously approved our first CAP, filed in December 2021, which encompasses approximately 450 wells in Weld County, Colorado. Following the approval of the CAP, we will submit individual OGDP packages for each of the locations within the CAP. The CAP, along with our prior OGDPs, represent the majority of our projected Wattenberg Field turn-in-line activity into 2028 based on our current pace and drilling plan in 2023.
Environmental, Social and Governance
We are committed to a meaningful and measurable ESG strategy. Our mission of being a cleaner, safer and more socially responsible company begins with a sound strategy, is supported in the boardroom and is overseen by our Environmental, Social, Governance and Nominating Committee at the board of directors, our internal Steering Committee and is considered at every level of our business.
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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, transportation pipelines, technological innovations and other activities, require capital and operational investments which are proactively and regularly built into our annual budgeting process. In 2022, we spent approximately $80 million on ESG initiatives, which included (i) $20.5 million in plugging and abandonment costs for 243 vertical wells, (ii) approximately $20.0 million on emission reduction devices, such as electric drilling, air pneumatics and vapor recovery units on new and older wells, (iii) $10.5 million on the installment of water pipelines, and (iv) $5.0 million on giving, outreach and community relations. In 2023, additional environmental and compliance transition costs, such as emission reduction costs, are included in our budget. Some of our larger anticipated capital projects in 2023 include $10 million to $15 million for the installation of water pipelines primarily in Adams County, $20 million to $25 million for plugging and abandonment of approximately 250 legacy vertical wells and $15 million to $20 million for the continued increase of electrification in our operations.
As part of our ESG initiatives, we have set aggressive targets to (i) reduce greenhouse gas intensity by 60% from 2020 levels by 2025 and 74% by 2030, (ii) reduce methane emissions intensity by 50% from 2020 levels by 2025 and 70% by 2030, and (iii) eliminate routine flaring, as defined by World Bank, by 2025. In March 2022, we completed our EPA annual filing for 2021 emissions and reported an approximate 12% reduction in GHG emissions, an approximate 17% reduction in methane emissions intensity and an approximate 70% reduction in flared hydrocarbons from 2020 baseline levels (each on a per unit of production basis), putting us on track to meet our goals.
In May 2022, our board of directors approved quantitative metrics for GHG and methane emissions reductions for our 2022 short-term incentive program, including 15% GHG and 30% methane emissions reduction targets from 2021 to 2022. As noted above, this supports the Company’s previously announced sustainability goals. In total, over 25% of our short-term incentive program in 2022 was tied to ESG and other environmental, health and safety initiatives. Our 2022 initial results indicate a reduction of over 30% in GHG and 50% in methane emissions from our 2021 levels.
In 2022 our board of directors was significantly engaged in our Sustainability reporting process, as it and our senior management team underwent its first TCFD process. Additionally, we filed our first Carbon Disclosure Project (“CDP”) Climate Change Questionnaire, examining our future through a range of climate-focused scenarios. In September 2022, we issued our annual Sustainability reports. The reports include key metrics and data from 2021 operations and are aligned with Sustainable Accounting Standards Board (“SASB”) standards and TCFD.
Additional information on our ESG practices, including sustainability goals, key metrics and progress achieved, can be found on the Sustainability page of our website at www.pdce.com. The information on our website, including the Sustainability reports, is not incorporated by reference in this report.
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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
(dollars in millions, except per unit data)
Production:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Crude oil equivalent (MBoe)
Average Boe per day (Boe)
Crude Oil, Natural Gas and NGLs Sales:
Crude oil
Natural gas
NGLs
Total crude oil, natural gas and NGLs sales
Net Settlements on Commodity Derivatives:
Crude oil
Natural gas
Total net settlements on derivatives
Average Sales Price (excluding net settlements on derivatives):
Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
Average Costs and Expense (per Boe):
Lease operating expense
Production taxes
Transportation, gathering and processing expenses
General and administrative expense
Depreciation, depletion and amortization
Lease Operating Expense by Operating Region (per Boe):
Wattenberg Field
Delaware Basin
* Percent change is not meaningful.
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Crude Oil, Natural Gas and NGLs Sales
Crude oil, natural gas and NGLs sales for the year ended December 31, 2022 increased compared to the year ended December 31, 2021 due to the following:
Year Ended December 31, 2022
(in millions)
Change in:
Production
Increase in production from acquisitions
Average crude oil price
Average natural gas price
Average NGLs price
Total change in crude oil, natural gas and NGLs sales revenue
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
Crude oil (MBbls)
Wattenberg Field
Delaware Basin
Total
Natural gas (MMcf)
Wattenberg Field
Delaware Basin
Total
NGLs (MBbls)
Wattenberg Field
Delaware Basin
Total
Crude oil equivalent (MBoe)
Wattenberg Field
Delaware Basin
Total
Average crude oil equivalent per day (Boe)
Wattenberg Field
Delaware Basin
Total
Net production volumes for crude oil, natural gas and NGLs increased 19 percent during the year ended December 31, 2022 compared to 2021. The increase in production volume between periods was primarily due to approximately 11.5 MMboe of additional production volumes as a result of the Great Western Acquisition and the net impact of turn-in-line activities in both basins since the fourth quarter of 2021. The increase was partially offset by normal decline in production from our existing wells.
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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
Wattenberg Field
Crude oil
Natural gas
NGLs
Total
Delaware Basin
Crude oil
Natural gas
NGLs
Total
Midstream Capacity
Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, as well as transportation pipelines out of the basin, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available on a timely basis and at acceptable costs, our production and results of operations could be adversely affected.
The ultimate timing and availability of adequate infrastructure remains out of our control. Weather, regulatory developments, preventative routine maintenance and other factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls.
Our production from the Wattenberg Field and the Delaware Basin was not materially affected by midstream or downstream capacity constraints during the year ended December 31, 2022. We continuously monitor infrastructure capacities versus producer activity and production volume forecasts. Increases in crude oil and natural gas prices in 2022 have incentivized producers in the Permian Basin to increase the level of drilling and completion activities. The increase in production levels and continued increase in development may lead to natural gas transportation constraints out of the Permian Basin in 2023, which may result in lower realized Waha natural gas prices. However, approximately half of PDC’s gas production in the Delaware Basin is dedicated to the Permian Highway Pipeline and is exposed to Houston-based gas pricing. We believe that this reduces the risk of a decrease in realized natural gas prices related to transportation constraints.
Crude Oil, Natural Gas and NGLs Pricing
Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially.
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The following table presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented:
Weighted Average Realized Sales Price by Operating Region
Year Ended December 31,
Percent Change
(excluding net settlements on derivatives)
Crude oil (per Bbl)
Wattenberg Field
Delaware Basin
Weighted average price
Natural gas (per Mcf)
Wattenberg Field
Delaware Basin
Weighted average price
NGLs (per Bbl)
Wattenberg Field
Delaware Basin
Weighted average price
Crude oil equivalent (per Boe)
Wattenberg Field
Delaware Basin
Weighted average price
* 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.
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.
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Average NYMEX Price
Average Realized Price Before TGP Expense
Average Realization Percentage Before TGP Expense
Average TGP Expense (1)
Average Realized Price After TGP Expense
Average Realization Percentage After TGP Expense
Crude oil (per Bbl)
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
Average NYMEX Price
Average Realized Price Before TGP Expense
Average Realization Percentage Before TGP Expense
Average TGP Expense (1)
Average Realized Price After TGP Expense
Average Realization Percentage After TGP Expense
Crude oil (per Bbl)
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
Average NYMEX Price
Average Realized Price Before TGP Expense
Average Realization Percentage Before TGP Expense
Average TGP Expense (1)
Average Realized Price After TGP Expense
Average Realization Percentage After TGP Expense
Crude oil (per Bbl)
Natural gas (per MMBtu)
NGLs (per Bbl)
Crude oil equivalent (per Boe)
(1) Average TGP expense excludes unutilized firm transportation fees of $0.14, $0.11, and $0.04 per Boe for the years ended December 31, 2022, 2021, and 2020, respectively.
Our average realization percentage for crude oil equivalent was relatively consistent in 2022 as compared to 2021 due to the overall increases in commodity prices between periods and realized improved differentials from our 2022 crude oil sales contracts. This was offset by a weakening Mont Belvieu price in the second half of 2022, impacting our realized price for NGLs and higher TGP rates for our natural gas production.
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 6 - 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 of December 31, 2022.
Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, and the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production.
Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The
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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,
(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price exchanges
Natural gas collars and fixed price exchanges
Natural gas basis protection exchanges
Total net settlements of commodity derivative instruments
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments
Crude oil collars and fixed price exchanges
Natural gas collars and fixed price exchanges
Natural gas basis protection exchanges
Net change in fair value of unsettled commodity derivative instruments
Total commodity price risk management gain (loss), net
The significant increase in commodity prices during 2022 had an overall unfavorable impact on the fair value and settlements of our commodity derivatives.
Lease Operating Expense
Lease operating (“LOE”) expense increased by 46 percent to $263.0 million in 2022 compared to $180.7 million in 2021. The period-over-period increase in LOE was primarily due to (i) an approximate $30.0 million increase from operated wells acquired in the Great Western Acquisition, (ii) an increase of $20.0 million from increased activity and the impact of inflation in the Wattenberg Field, (iii) a $15.2 million increase in workover expense relating to activities mainly in the Delaware Basin and (iv) a $12.5 million increase in chemical treatments, water disposal and well services in the Delaware Basin as a result of increased activity and the impact of inflation. LOE per Boe increased 22 percent to $3.09 in 2022 from $2.53 in 2021 primarily due to the additional costs outlined above.
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 89 percent to $311.8 million in 2022 compared to $165.2 million in 2021. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs sales between periods. Production taxes per Boe increased 58 percent to $3.67 in 2022 compared to $2.32 in 2021.
Transportation, Gathering and Processing Expense
TGP expense increased 24 percent to $124.6 million in 2022 compared to $100.4 million in 2021. The increase in TGP expense between periods was primarily due to an increase in gas processing volumes and higher rates in the Delaware Basin. TGP per Boe was $1.46 and $1.41 for 2022 and 2021, respectively.
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Exploration, Geologic, and Geophysical Expense
Exploration, geologic and geophysical expense increased to $13.1 million in 2022 compared to $1.1 million in 2021. In 2022, we drilled and turned-in-line an exploratory well in the Delaware Basin that was not economically viable. During 2022, we expensed the associated lease costs and related infrastructure assets of the exploratory dry hole at a cost of $12.0 million .
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,
(in millions)
Impairment of proved and unproved properties
Impairment of infrastructure and other
Total impairment of properties and equipment
There were no significant impairment charges recognized in relation to our proved and unproved oil and gas properties in 2022 or 2021. If crude oil prices were to 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 the Delaware 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 increased to $156.3 million in 2022 compared to $127.7 million in 2021 primarily due to $18.2 million in transaction and transition costs relating to the Great Western Acquisition and a $6.4 million increase related to salaries, wages and benefits as a result of an increase in headcount from the Great Western Acquisition along with an increase in drilling activity.
Depreciation, Depletion and Amortization Expense
Crude oil and natural gas properties. During 2022 and 2021, we invested $1,107.7 million and $583.6 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 $741.9 million and $627.5 million in 2022 and 2021, respectively. The increase in total DD&A expense was primarily due to a 19 percent increase in production volumes between periods driven by the Great Western Acquisition. The increase was partially offset by a decrease in weighted average depletion rate resulting from the improved reserve quantities as of December 31, 2022 as a result of increased commodity prices in 2022.
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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,
(in millions)
Increase in production
Decrease in weighted average depletion rate
Total decrease in DD&A expense related to crude oil and natural gas properties
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,
(per Boe)
Operating Region/Area
Wattenberg Field
Delaware Basin
Total weighted average DD&A expense rate
Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $7.8 million for the year ended December 31, 2022, compared to $7.7 million for the year ended December 31, 2021.
Interest Expense, net
Interest expense, net decreased by $18.0 million to $64.7 million in 2022 compared to $82.7 million in 2021. The decrease was primarily due to (i) a $17.8 million decrease from a partial redemption of our 2024 Senior Notes and a full redemption of Convertible Notes and certain Senior Notes in the second half of 2021, (ii) a $6.9 million loss on extinguishment recognized in 2021 relating to the redemption of certain other Senior Notes and (iii) an $8.0 million decrease in debt issuance cost amortization as a result of debt expiration and redemptions in 2021. These decreases were partially offset by an $18.4 million increase relating to increased borrowings under our revolving credit facility in 2022 to finance the cash portion of the purchase price of the Great Western Acquisition as well as an overall increase in interest rates on our credit facility.
Gain on Bargain Purchase
We recognized a $90.1 million gain on the bargain purchase of the Great Western Acquisition, net of related income taxes of $28.4 million, in 2022. For additional information, see Note 3 - Business Combination in Item 8. Financial Statements and Supplementary Data included elsewhere in this report.
Provision for Income Taxes
We recorded income tax expense of $454.2 million and $26.6 million for 2022 and 2021, respectively, resulting in effective tax rates of 20.3 percent and 4.8 percent on the respective pre-tax income. The effective tax rates differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax income due to state income taxes and changes in the valuation allowance against our deferred income tax assets.
We consider whether a portion, or all, of our deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of 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 available taxes in carryback periods, the future reversals of existing taxable temporary differences, tax planning strategies and projected future taxable income in making this assessment. Our oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to provide a valuation allowance against our DTAs beginning January 1, 2020 since we previously could not conclude that it is more likely than not that our DTAs will be fully realized in future periods.
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As we previously disclosed, we maintained a valuation allowance on our net federal deferred tax assets and continued to do so until sufficient positive evidence existed to support a reversal of the allowance. In 2022, continued higher commodity prices increased our income, resulting in the reversal of objective negative evidence of cumulative loss in recent years, and we determined that we have sufficient positive evidence to release the valuation allowance. As a result, we released the full valuation allowance of $56.6 million against our deferred income tax assets and recognized a corresponding decrease to income tax expense.
Given recent improvements in oil and gas prices and assumptions based on our current production forecasts, we estimate that we will incur federal and state cash income taxes in 2023.
In August 2022, the IRA was signed into law. The IRA includes implementation of a new alternative minimum tax, an excise tax on stock buybacks, and significant tax incentives for energy and climate initiatives, among other provisions. The alternative minimum tax and excise tax on stock buyback provisions are effective for tax years beginning after December 31, 2022. We continue to monitor updates to the IRA and the impact of the IRA on our financial position, results of operations and liquidity. We do not believe the IRA will have a material impact on our stock buyback program or our financial position in 2023, however, we are still assessing the impact for subsequent years.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors impacting net income of $1,778 million and $522 million in 2022 and 2021, respectively, are discussed above.
Adjusted net income, a non-U.S. GAAP financial measure, was $1,450 million and $800 million for the year ended December 31, 2022 and 2021, respectively. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income. See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.
Financial Condition, Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash and cash equivalents, cash flows from operating activities, unused borrowing capacity from our revolving credit facility, proceeds raised in debt and equity capital market transactions and other sources, such as asset sales.
Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile, and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production.
We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions, capital returns and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. These activities typically result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 2022 is an indication of a lack of liquidity. We had working capital deficits of $826 million and $462 million at December 31, 2022 and 2021, respectively. The increase in working capital deficit since December 31, 2021 primarily was a result of the Great Western Acquisition and a significant increase in production taxes payable due to increase in sales between periods. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time.
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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 $6.5 million at December 31, 2022 and availability under our revolving credit facility was $1.1 billion, providing for total liquidity of $1.1 billion as of December 31, 2022. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests.
Our material short-term and long-term cash requirements consist primarily of capital expenditures, payments of contractual obligations, dividends, share repurchases, income taxes and working capital obligations. If commodity prices increase, our working capital requirements may increase due to higher operating costs and negative settlements on our outstanding commodity derivative contracts. Funding for these requirements may be provided by any combination of our capital resources previously outlined.
As a result of the Great Western Acquisition, we paid $361 million on Great Western’s behalf to pay and discharge Great Western’s 12% senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. Additionally, we paid $236 million on Great Western’s behalf to pay Great Western’s secured credit facility, inclusive of unpaid accrued interest. The termination of Great Western’s debt was funded through a combination of cash on hand and availability under our revolving credit facility.
Based on our current production forecast for 2023, we expect 2023 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. In addition, based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to fund our planned activities through the 12-month period following the filing of this report. We also believe that we will have sufficient expected cash flows from operations to allow us to execute our capital return plan. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board.
Our material long-term cash requirements relate to debt obligations and interest payments, commodity derivative contract liabilities, production taxes, operating and finance leases, asset retirement obligations and firm transportation and processing agreements included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report.
In October 2022, as part of the semi-annual redetermination of the borrowing base under our credit facility, the borrowing base increased from $3.0 billion to $3.5 billion, primarily due to the addition of the reserves acquired from Great Western; however, we maintained our elected commitment level of $1.5 billion. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements (a) to maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 3.5:1.0. For purposes of the current ratio covenant, the revolving credit facility’s definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, among other things, unused commitments under the revolving credit facility and excludes the fair value of commodity derivative assets. Additionally, the current ratio covenant calculation allows us to exclude the fair value of commodity derivative liabilities and the current portion of our long-term debt and other short-term loans from the U.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit under U.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. At December 31, 2022, we were in compliance with all covenants in the revolving credit facility with a current ratio of 1.5:1.0 and a leverage ratio of 0.5:1.0.
We expect to remain in compliance with the covenants under our credit facility and our Senior Notes throughout the 12-month period following the filing of this report.
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Cash Flows
Our cash flows from operating, investing and financing activities are as follows:
Year ended December 31,
(in thousands)
Cash flows from operating activities
Cash flows from investing activities
Cash flows from financing activities
Net increase (decrease) in cash and cash equivalents
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 $1,225 million to $2,772 million in 2022 as compared to $1,548 million in 2021. The increase between periods was primarily due to a $1,744 million increase in crude oil, natural gas and NGLs sales and changes in the timing of receivable collections. These increases were partially offset by a $470 million increase in cash settlement losses on commodity derivatives, a $147 million increase in production taxes, an $82 million increase in lease operating expenses and changes in the timing of vendor and royalty owner payments between periods.
Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $1,006 million in 2022 to $2,538 million from $1,533 million in 2021. 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 $472 million in 2022 to $1,421 million from $949 million in 2021. The increase was primarily due to the increase in cash flows from operating activities, as discussed above, partially offset by an increase in capital investments in crude oil and natural gas properties as a result of our 2022 development plan.
See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.
Investing Activities. As crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our crude oil and natural reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments.
Cash flows from investing activities in 2022 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 $2,150 million during 2022 was primarily due to $1,068 million utilized for the Great Western Acquisition and drilling and completion activities of $1,070 million, partially offset by $16 million in proceeds from the sale of certain properties and equipment.
Net cash used in investing activities of $579 million during 2021 was primarily related to our drilling and completion activities of $583 million, partially offset by $5 million in proceeds from the sale of certain properties and equipment.
Financing Activities. Net cash used in financing activities in 2022 of $650 million was primarily due to (i) the repurchase of 12.1 million shares of our common stock for $818 million pursuant to our stock repurchase program and (ii) dividend payments totaling $182 million, partially offset by net borrowings on our credit facility of $370 million to fund the cash portion of the purchase price of the Great Western Acquisition and to terminate Great Western’s debt. As of December 31, 2022, $455 million out of the approved $1.3 billion remained available for stock repurchases under the program. In February 2023, our board of directors approved a $750 million increase in the size of the program. 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.
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Net cash used in financing activities in 2021 of $938 million was primarily due to (i) net repayments on our credit facility of $168 million, (ii) redemption and retirement of Convertible Notes and other Senior Notes totaling $509 million, (iii) the repurchase of 3.8 million shares of our common stock for $157 million pursuant to our stock repurchase program and (iv) dividend payments totaling $84 million.
Subsidiary Guarantors
PDC Permian, Inc., a Delaware corporation (“Permian”), and Pioneer Water Pipeline LLC, a Delaware limited liability company (“Pioneer” and together with Permian, the “Guarantors”), each a wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”). Permian holds our assets located in the Delaware Basin. Pioneer holds certain water midstream assets located in the Wattenberg Field. The Senior Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantors. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions.
The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (iii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.
The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method.
As of/Year Ended December 31,
Issuer
Guarantors
Issuer
Guarantor
(in millions)
Assets
Current assets
Intercompany accounts receivable, guarantor subsidiary
Investment in guarantor subsidiary
Properties and equipment, net
Other non-current assets
Liabilities
Current liabilities
Intercompany accounts payable
Long-term debt
Other non-current liabilities
Statement of Operations
Crude oil, natural gas and NGLs sales
Commodity price risk management gain (loss), net
Total revenues
Production costs
Gross profit (1)
Impairment of properties and equipment
Net income (loss)
(1) Gross profit is calculated as crude oil, natural gas and NGLs sales less production costs.
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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 with U.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 specialists, specifically 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 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 estimates of reserves 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 predict future commodity prices. However, we performed a sensitivity analysis on our proved reserve estimates as of December 31, 2022, to present a decrease of approximately 20 percent in crude oil price (and holding all other factors constant), as the value of crude oil influences the value of our proved reserves most significantly. As a result, our proved reserve quantities would decrease by 7.8 MMBoe or 1 percent. The decrease would have increased our DD&A rate by $0.03 per Boe and decreased our pre-tax income by $2.2 million for the year ended December 31, 2022. This estimated impact is based on available data as of December 31, 2022, and future events could require different adjustments to our DD&A rate. During 2022 and 2021, we had positive revisions to our proved reserve quantities of 29.8 MMBoe and 52.9 MMBoe, respectively, as a result of higher average prices for crude oil, natural gas and NGLs. During 2020 we had a negative revision of 39.5 MMBoe 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 and Supplemental Oil and Gas Information within our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data included elsewhere in this report.
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Impairment of Crude Oil and Natural Gas Properties
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, and 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.
There were no significant impairment charges recognized related to our proved and unproved properties during the years ended December 31, 2022 or 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 a 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 connection with the Great Western Acquisition in 2022, we allocated $1.5 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the acquisition date. 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. The Great Western Acquisition resulted in a gain on bargain purchase due to the estimated fair value of the identifiable net assets acquired exceeding the purchase consideration transferred by $90.1 million, net of related income taxes of $28.4 million. The bargain purchase was primarily attributable to the increase in commodity price forecasts from the date we entered into the definitive purchase agreement, February 26, 2022, to the closing date of the acquisition, May 6, 2022, when the fair value of the crude oil and natural gas reserves acquired was determined. Additionally, the majority of the acquisition consideration was fixed and therefore did not fluctuate as a result of market increases or decreases between the date of entry into the agreement through the closing date. Assuming all factors are held constant, an approximate 10 percent decrease in future commodity prices used in the valuation of the proved crude oil and natural gas properties would reduce the fair value by approximately $400 million, recognition of approximately $300 million of goodwill and no gain on bargain purchase.
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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.
Recent Accounting Pronouncements
There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of December 31, 2022.
Reconciliation of Non-U.S. GAAP Financial Measures
We use “adjusted cash flows from operations”, “adjusted free cash flow (deficit)”, “adjusted net income (loss)” and “adjusted EBITDAX”, non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.
Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure.
We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations.
Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance.
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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.
The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure for the periods presented:
Year Ended December 31,
(thousands)
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:
Net cash from operating activities
Changes in assets and liabilities
Adjusted cash flows from operations
Capital expenditures for development of crude oil and natural gas properties
Capital expenditures for midstream assets
Change in accounts payable related to capital expenditures for oil and gas development activities and midstream assets
Adjusted free cash flow
Net income (loss) to adjusted net income (loss):
Net income (loss)
Loss (gain) on commodity derivative instruments
Net settlements on commodity derivative instruments
Tax effect of above adjustments (1)
Adjusted net income (loss)
Net income (loss) to adjusted EBITDAX:
Net income (loss)
Loss (gain) on commodity derivative instruments
Net settlements on commodity derivative instruments
Non-cash stock-based compensation
Interest expense, net
Income tax expense (benefit)
Impairment of properties and equipment
Exploration, geologic and geophysical expense
Depreciation, depletion and amortization
Accretion of asset retirement obligations
Loss (gain) on sale of properties and equipment
Adjusted EBITDAX
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Year Ended December 31,
(thousands)
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities
Gain on bargain purchase
Interest expense, net (2)
Amortization and write-off of debt discount, premium and issuance costs
Exploration, geologic and geophysical expense (3)
Other
Changes in assets and liabilities
Adjusted EBITDAX
Standardized measure of discounted future net cash flows
Present value of estimated future income tax discounted at 10%
(1) Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the year ended December 31, 2020.
(2) Excludes loss on extinguishment from early retirement of our senior notes amounting to $6.9 million for the year ended December 31, 2021.
(3) Excludes exploratory dry hole costs of $12.0 million for the year ended December 31, 2022 .
