The following discussion and analysis should be read in conjunction with our condensed consolidated financial statements and related notes included in Item 1. Financial Statements of this report. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements.
EXECUTIVE SUMMARY
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 2021, the global economy continued to recover due to the containment of COVID-19 and related emerging variants, which resulted to an increase in crude oil demand. Overall production from OPEC+ has not increased at the same pace of the demand, creating upward pressure on crude oil prices and tightening of global oil inventories. InFebruary 2022 ,Russia , a major global crude oil exporter, attacked and invadedUkraine , drivingthe United States ("U.S.") and other Western countries to apply sanctions over crude oil imports fromRussia . Additionally, many crude oil purchasers are boycotting Russian crude oil in response to the attacks onUkraine . All of these factors have led to lower global oil supply and significantly higher crude oil prices in the first quarter of 2022 when compared to 2021. The commodity price environment may remain volatile for an extended period due to, among other things, the continued invasion inUkraine , outbreaks caused by coronavirus variants, the recovery of the economy, unexpected supply disruptions in key producing countries including the potential for higherU.S. crude oil production, historically low storage inventories of petroleum products, 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.
Financial Matters
Three months ended
•Production volumes decreased to 17.9 MMboe in the first quarter of 2022, a decrease of 8 percent compared to the fourth quarter of 2021, primarily driven by the timing of our turn-in-line activities and two fewer days in the first quarter of 2022. •Crude oil, natural gas and NGLs sales increased to$882.4 million compared to$848.2 million in the fourth quarter of 2021 primarily due to a 13 percent increase in weighted average realized commodity prices partially offset by 8 percent decrease in production volumes between periods. •Negative net settlements from our commodity derivative contracts decreased to$161.6 million in the first quarter of 2022 compared to$194.8 million in the fourth quarter of 2021 due to a lower volume of commodities hedged in the first quarter of 2022. •Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 10 percent to$720.8 million from$653.3 million in the fourth quarter of 2021. 21 --------------------------------------------------------------------------------PDC ENERGY, INC. •Generated a net loss of$32.0 million , or$0.33 per diluted share for the first quarter of 2022 and a net income of$473.1 million , or$4.78 per diluted share for the fourth quarter of 2021 primarily due to a$568.1 million commodity price risk management loss incurred in 2022 partially offset by an increase in crude oil, natural gas and NGLs sales of$34.2 million between periods. •Adjusted EBITDAX, a non-U.S. GAAP financial measure, was$549.3 million compared to$487.7 million for the fourth quarter of 2021, primarily due to an increase in sales of$67.5 million , net of negative net derivative settlements, partially offset by an increase in costs experienced in operations. •Cash flows from operations decreased to$489.0 million compared to$520.0 million in the fourth quarter of 2021. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to$538.8 million compared to$473.1 million in fourth quarter of 2021. Adjusted free cash flows, a non-U.S. GAAP financial measure, decreased to$318.7 million from$339.5 million in the fourth quarter of 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 comparableU.S. GAAP measures.
Pending Acquisition
OnFebruary 26, 2022 , we entered into the Acquisition Agreement to acquire Great Western for approximately$1.4 billion , inclusive of Great Western's net debt. Great Western is an independent 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 consideration for the Great Western Acquisition will be made through the transfer 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 anticipate that the Great Western Acquisition will be completed inMay 2022 , subject to certain customary closing conditions being met.
Drilling and Completion Overview
In the Wattenberg Field, we operated one full-time drilling rig, one spudder rig and one full-time completion crew during the first quarter of 2022 and added a second full-time drilling rig inmid-March 2022 . In addition, we operated one full-time drilling rig and one completion crew during the first quarter of 2022 in theDelaware Basin . Our total capital investments in crude oil and natural gas properties for the three months endedMarch 31, 2022 were$220.2 million .
The following table summarize our drilling and completion activities for the
three months ended
Operated Wells Wattenberg Field Delaware Basin Total Gross Net Gross Net Gross Net In-process as of December 31, 2021 143 133.0 21 20.6 164 153.6 Wells spud 20 17.8 6 5.9 26 23.7 Wells turned-in-line (40) (38.8) (9) (9.0) (49) (47.8) In-process as of March 31, 2022 123 112.0 18 17.5 141 129.5
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.
22 --------------------------------------------------------------------------------PDC ENERGY, INC.
Capital Returns
Stock Repurchase Program. InFebruary 2022 , our board of directors approved a new stock repurchase program that reset the total repurchase value to$1.25 billion , which we currently anticipate fully utilizing byDecember 31, 2023 . We repurchased 1.3 million shares of outstanding common stock at a cost of$85.3 million for the three months endedMarch 31, 2022 . As ofMarch 31, 2022 ,$1.19 billion of our outstanding common stock remained available for repurchases under the program.
Dividends. For the three months ended
2022 Operational and Financial Outlook
On a PDC standalone basis (without consideration to the Great Western Acquisition), 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 capital budget for 2022 is likely to be impacted by cost inflation if crude oil and natural gas prices remain at current levels or continue to increase. Our 2022 operational and financial projections will be updated after we close the Great Western Acquisition. 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 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, 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. Upon closing the Great Western Acquisition, we plan to add a fifth development area called Ranger. Our 2022 capital investment program for the Wattenberg Field, on a PDC standalone basis, 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. Our plan includes spudding approximately 130 to 145 operated wells and turning-in-line approximately 115 to 130 operated wells. We added a full-time drilling rig inMarch 2022 , bringing us to two full-time horizontal rigs and one completion crew along with a part-time spudder rig planned for the rest of the year.Delaware Basin . Total capital investments in crude oil and natural gas properties in theDelaware Basin for 2022 are expected to be approximately 25 percent, on a PDC standalone basis, of our total capital investments. In 2022, we anticipate spudding and turning-in-line approximately 15 to 20 operated wells with the majority of the wells being 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. 23 --------------------------------------------------------------------------------PDC ENERGY, INC.
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. Pursuant to SB 19-181, a series of rulemaking hearings were conducted, which focused on issues such as permitting requirements, setbacks and siting requirements, and financial assurance, resulting in the adoption of new regulatory requirements. We anticipate that future hearings will be conducted by the COGCC on permit fees, worker certification and well site reclamation. These proceedings could result in new rules that impose increased costs and regulations on our operations. 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. In addition to the changes to the permitting process, the COGCC conducted a rulemaking concerning financial assurance to be provided by operators inColorado . The rulemaking was designed to address and reduce the number of wells that have not been properly plugged by their operators ("orphan wells") due to financial constraints or bankruptcy. As part of that rulemaking, tiers of operators were established based on identified metrics which results in varying levels of financial assurance being required. For our tier, a bond of$40 million will be required in the second quarter of 2022 and will be secured through our existing surety bond program. In addition to the financial assurance, operators will be assessed a fixed fee per existing well that will fund the plugging and abandonment of orphan wells identified by the COGCC. We do not anticipate a material effect on our financial condition or results of operations with meeting the outlined financial assurance requirements.
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.
Wattenberg Permits Update. PDC was granted unanimous approval for an 8-well OGDP located in ruralWeld County inOctober 2021 , our first approval under the new permitting process resulting from a company-wide collaborative effort. Additionally, inSeptember 2021 , 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. InDecember 2021 , PDC submitted our first CAP. The application proposes approximately 450 wells spread amongst 25 surface locations inWeld 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 on a PDC standalone basis.
Environmental, Social and Governance ("ESG")
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 ourEnvironmental, Social, Governance and Nominating Committee at the board of directors and is considered at every level of our business. 24 --------------------------------------------------------------------------------PDC ENERGY, INC. During the first quarter of 2022, we completed ourEnvironmental Protection Agency annual filing for 2021. Our results outline that we have achieved a reduction in greenhouse gas ("GHG") and methane emissions intensity from 2020 baseline targets, that puts us on track to meet our 60% and 50% GHG and methane reduction levels by 2025, respectively. Additional information on our ESG practices, including sustainability goals, key metrics and progress achieved, can be found in our Sustainability Report available on our website at www.pdce.com and is not incorporated by reference in this report. TheSEC and other regulatory bodies are proposing a number of climate-change focused and broader ESG reporting requirements focused on emission reduction. When adopted, we will modify our disclosures accordingly. 25 --------------------------------------------------------------------------------PDC ENERGY, INC.
Results of Operations
InNovember 2020 , theSEC issued Final Rule 33-10890, Management's Discussion and Analysis, Selected Financial Data and Supplementary Financial Information, which modernizes and simplifies certain disclosure requirements of Regulation S-K. One of the updates to Item 303 of Regulation S-K allows registrants to compare the results of the most recently completed quarter to the results of either the immediately preceding quarter or the corresponding quarter of the preceding year. We adopted presenting the results of operations with this approach effectiveJanuary 1, 2022 , as we believe that comparing current quarter results to those of the immediately preceding quarter is more useful in identifying current business trends and provides a more meaningful comparison. Accordingly, we have compared the results for the three months endedMarch 31, 2022 andDecember 31, 2021 below. Additionally, in the first filing after the adoption of this rule change, we are required to disclose a comparison of the results for the current quarter and the corresponding quarter of the preceding fiscal year. Accordingly, the comparison between the results for the three months endedMarch 31, 2022 andMarch 31, 2021 is also presented below.
Summary of Operating Results
The following table presents selected information regarding our operating results: Three Months Ended Percent Change Between March 31, December 31, March 31, 2022 - March 31, 2022 - 2022 2021 March 31, 2021 December 31, 2021 March 31, 2021 (dollars in millions, except per unit data) Production: Crude oil (MBbls) 5,853 6,325 4,857 (7) % 21 % Natural gas (MMcf) 43,119 47,033 40,152 (8) % 7 % NGLs (MBbls) 4,885 5,241 4,192 (7) % 17 % Crude oil equivalent (MBoe) 17,924 19,405 15,740 (8) % 14 % Average Boe per day (Boe) 199,156 210,924 174,889 (6) % 14 % Crude Oil, Natural Gas and NGLs Sales: Crude oil$ 549.7 $ 483.9 $ 273.7 14 % 101 % Natural gas 163.1 192.7 105.6 (15) % 54 % NGLs 169.6 171.6 88.8 (1) % 91 % Total crude oil, natural gas and NGLs sales$ 882.4 $ 848.2 $ 468.1 4 % 89 % Net Settlements on Commodity Derivatives ` Crude oil$ (131.1) $ (122.7) $ (20.5) 7 % * Natural gas (30.5) (72.1) (10.2) (58) % 199 %
Total net settlements on derivatives
$ (30.7) (17) % * Average Sales Price (excluding net settlements on derivatives): Crude oil (per Bbl)$ 93.93 $ 76.50 $ 56.34 23 % 67 % Natural gas (per Mcf) 3.78 4.10 2.63 (8) % 44 % NGLs (per Bbl) 34.70 32.74 21.19 6 % 64 % Crude oil equivalent (per Boe) 49.23 43.71 29.74 13 % 66 % Average Costs and Expenses (per Boe): Lease operating expense$ 3.02 $ 2.62 $ 2.66 15 % 14 % Production taxes 3.51 3.30 1.87 6 % 88 % Transportation, gathering and processing expense 1.56 1.34 1.38 16 % 13 % General and administrative expense 1.90 1.62 2.08 17 % (9) % Depreciation, depletion and amortization 8.43 8.07 9.32 4 % (10) % 26
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PDC ENERGY, INC. Three Months Ended Percent Change Between December 31, March 31, 2022 - March 31, 2022 - March 31, 2022 2021 March 31, 2021 December 31, 2021 March 31, 2021 (dollars in millions, except per unit data) Lease Operating Expense byOperating Region (per Boe) Wattenberg Field $ 2.42$ 2.17 $ 2.31 12 % 5 % Delaware Basin 6.67 5.42 5.27 23 % 27 % ____________
* Percent change is not meaningful.
Crude Oil, Natural Gas and NGLs Sales
The change in crude oil, natural gas and NGLs sales for the three months ended
Change Between March 31, 2022 - March 31, 2022 - December 31, 2021 March 31, 2021 (in millions) Change in: Production $ (63.9) $ 78.6 Average crude oil price 102.0 220.0 Average natural gas price (13.5) 49.7 Average NGLs price 9.6 66.0 Total change in crude oil, natural gas and NGLs sales revenue $ 34.2 $ 414.3
Crude Oil, Natural Gas and NGLs Production
The following table presents crude oil, natural gas and NGLs production for the periods presented: Three Months Ended Percent Change Between March 31, 2022 - March 31, 2022 - Production by Operating Region March 31, 2022 December 31, 2021 March 31, 2021 December 31, 2021 March 31, 2021 Crude oil (MBbls) Wattenberg Field 4,832 5,306 4,173 (9) % 16 % Delaware Basin 1,021 1,019 684 - % 49 % Total 5,853 6,325 4,857 (7) % 21 % Natural gas (MMcf) Wattenberg Field 37,663 40,870 35,561 (8) % 6 % Delaware Basin 5,456 6,163 4,591 (11) % 19 % Total 43,119 47,033 40,152 (8) % 7 % NGLs (MBbls) Wattenberg Field 4,291 4,615 3,800 (7) % 13 % Delaware Basin 594 626 392 (5) % 52 % Total 4,885 5,241 4,192 (7) % 17 % Crude oil equivalent (MBoe) Wattenberg Field 15,400 16,732 13,900 (8) % 11 % Delaware Basin 2,524 2,673 1,840 (6) % 37 % Total 17,924 19,405 15,740 (8) % 14 % 27
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PDC ENERGY, INC. Three Months Ended Percent Change Between March 31, 2022 - March 31, 2022 - Production by Operating Region March 31, 2022 December 31, 2021 March 31, 2021 December 31, 2021 March 31, 2021 Average crude oil equivalent per day (Boe) Wattenberg Field 171,111 181,870 154,444 (6) % 11 % Delaware Basin 28,045 29,054 20,445 (3) % 37 % Total 199,156 210,924 174,889 (6) % 14 % Net production volumes for oil, natural gas and NGLs decreased 8 percent during the three months endedMarch 31, 2022 compared to the three months endedDecember 31, 2021 primarily due to the timing of wells turned-in-line in both basins and two fewer days in the first quarter of 2022 as well as normal decline in production from our existing wells. Net production volumes for oil, natural gas and NGLs increased 14 percent during the three months endedMarch 31, 2022 compared to the same period in 2021. The increase in production volume between periods was primarily due to a greater number of wells turned-in-line since the first quarter of 2021 and a loss in production from temporary shut-ins of a significant portion of our wells driven by severe weather during the first quarter of 2021.
The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented:
Three Months Ended March 31, 2022 Crude Oil Natural Gas NGLs Total Wattenberg Field 31% 41% 28% 100% Delaware Basin 40% 36% 24% 100% Three Months Ended December 31, 2021 Crude Oil Natural Gas NGLs Total Wattenberg Field 32% 41% 27% 100% Delaware Basin 38% 38% 24% 100% Three Months Ended March 31, 2021 Crude Oil Natural Gas NGLs Total Wattenberg Field 30% 43% 27% 100% Delaware Basin 37% 42% 21% 100%
Our production mix in both operating regions remained relatively consistent between all periods.
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 three months endedMarch 31, 2022 . We continuously monitor infrastructure capacities versus producer activity and production volume forecasts. Continued increases in crude oil and natural gas prices 28 --------------------------------------------------------------------------------PDC ENERGY, INC. through early 2022 have incentivized producers in thePermian Basin to increase the level of drilling and completion activities. The potential increase in production levels may lead to natural gas transportation constraints out of thePermian Basin by the end of 2022 through 2023, which may result to lower realized WAHA natural gas prices. However, a majority of PDC's gas production in theDelaware Basin is dedicated to Permian Highway Pipeline and is exposed toHouston -based gas pricing.
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.
The following table presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented:
Three Months Ended Percent Change Between Weighted Average Realized Sales Price byOperating Region (excluding net settlements on December 31, March 31, 2022 - March 31, 2022 - derivatives) March 31, 2022 2021 March 31, 2021 December 31, 2021 March 31, 2021 Crude oil (per Bbl) Wattenberg Field$ 93.52 $ 76.59 $ 56.54 22 % 65 % Delaware Basin 95.86 76.05 55.13 26 % 74 % Weighted-average price 93.93 76.50 56.34 23 % 67 % Natural gas (per Mcf) Wattenberg Field $ 3.82$ 4.18 $ 2.73 (9) % 40 % Delaware Basin 3.56 3.53 1.88 1 % 89 % Weighted-average price 3.78 4.10 2.63 (8) % 44 % NGLs (per Bbl) Wattenberg Field$ 32.37 $ 31.52 $ 20.47 3 % 58 % Delaware Basin 51.54 41.74 28.23 23 % 83 % Weighted-average price 34.70 32.74 21.19 6 % 64 % Crude oil equivalent (per Boe) Wattenberg Field$ 47.69 $ 43.19 $ 29.55 10 % 61 % Delaware Basin 58.59 46.93 31.17 25 % 88 % Weighted-average price 49.23 43.71 29.74 13 % 66 % 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 condensed 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 29 -------------------------------------------------------------------------------- PDC ENERGY, INC. 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 Three Months Ended Average Price Before TGP Percentage Before Average TGP Price After TGP Percentage After TGP March 31, 2022 NYMEX Price Expense TGP Expense Expense (1) Expense Expense Crude oil (per Bbl)$ 94.29 $ 93.93 100 %$ 2.69 $ 91.24 97 % Natural gas (per MMBtu) 4.95 3.78 76 % 0.23 3.55 72 % NGLs (per Bbl) 94.29 34.70 37 % - 34.70 37 % Crude oil equivalent (per Boe) 68.40 49.23 72 % 1.42 47.81 70 % Average Realized Average Realization Average Realized Average Realization Three Months Ended Average Price Before TGP Percentage Before Average TGP Price After TGP Percentage After TGP December 31, 2021 NYMEX Price Expense TGP Expense Expense (1) Expense Expense Crude oil (per Bbl)$ 77.19 $ 76.50 99 %$ 2.72 $ 73.78 96 % Natural gas (per MMBtu) 5.50 4.10 75 % 0.13 3.97 72 % NGLs (per Bbl) 77.19 32.74 42 % - 32.74 42 % Crude oil equivalent (per Boe) 59.33 43.71 74 % 1.19 42.52 72 % Average Realized Average Realization Average Realized Average Realization Three Months Ended Average Price Before TGP Percentage Before Average TGP Price After TGP Percentage After TGP March 31, 2021 NYMEX Price Expense TGP Expense Expense (1) Expense Expense Crude oil (per Bbl)$ 57.84 $ 56.34 97 %$ 3.32 $ 53.02 92 % Natural gas (per MMBtu) 2.69 2.63 98 % 0.11 2.52 94 % NGLs (per Bbl) 57.84 21.19 37 % - 21.19 37 % Crude oil equivalent (per Boe) 40.12 29.74 74 % 1.32 28.42 71 % ____________ (1)Average TGP expense excludes unutilized firm transportation fees of$0.14 per Boe,$0.15 per Boe, and$0.06 per BOE for the three months endedMarch 31, 2022 ,December 31, 2021 , andMarch 31, 2021 , respectively. Our average realization percentages for crude oil, natural gas and NGLs were relatively flat for the three months endedMarch 31, 2022 as compared to the three months endedDecember 31, 2021 . Our average realization percentage for crude oil increased for the three months endedMarch 31, 2022 as compared to the same period in 2021 primarily due to an increased demand for crude oil due to the containment of COVID-19. In addition, we realized improved differentials from our 2022 crude oil sales contracts. Average realization percentage for natural gas decreased for the three months endedMarch 31, 2022 compared to the three months endedMarch 31, 2021 due to strong pricing inFebruary 2021 as a result of severe weather conditions.
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 5 - Commodity Derivative Financial Instruments in Item 1. Financial Statements included elsewhere in this report for a summary of our derivative positions as ofMarch 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. 30 --------------------------------------------------------------------------------PDC ENERGY, INC. 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:
Three Months Ended March 31, 2022 December 31, 2021 March 31, 2021 (in millions) Commodity price risk management gain (loss), net: Net settlements of commodity derivative instruments: Crude oil collars and fixed price exchanges$ (131.1) $ (122.7) $ (20.5) Natural gas collars and fixed price exchanges (28.1) (80.0) (2.8) Natural gas basis protection exchanges (2.3) 7.9 (7.4) Total net settlements of commodity derivative instruments (161.5) (194.8) (30.7) Change in fair value of unsettled commodity derivative instruments: Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments 100.2 198.5 (0.7) Crude oil collars and fixed price exchanges (373.6) (38.9) (137.8) Natural gas collars and fixed price exchanges (140.6) 46.7 (2.1) Natural gas basis protection exchanges 7.4 (5.8) (10.0) Net change in fair value of unsettled commodity derivative instruments (406.6) 200.5 (150.6) Total commodity price risk management gain (loss), net$ (568.1) $ 5.7$ (181.3)
The continued increase in commodity prices during the three months ended
Lease Operating Expense
Lease operating expense ("LOE") increased by 7 percent to$54.2 million for the three months endedMarch 31, 2022 compared to$50.8 million for the three months endedDecember 31, 2021 . The period-over-period increase in LOE was primarily attributable to a$1.7 million increase in workover expense due to the timing of workover activities in theDelaware Basin and$1.5 million in additional chemical treatments and power costs in both basins. LOE per Boe increased 15 percent to$3.02 for the three months endedMarch 31, 2022 from$2.62 for the three months endedDecember 31, 2021 . The increase is primarily driven by the cost increases outlined above as well as a decrease in production of 8 percent period-over-period. LOE increased by 30 percent to$54.2 million for the three months endedMarch 31, 2022 compared to$41.8 million for the three months endedMarch 31, 2021 . The period-over-period increase in LOE was primarily due to (i) increased activities and payroll costs of$4.8 million at our operated and non-operated well locations resulting from an increase in completion activities in both basins, (ii) a$3.2 million increase in chemical treatments, environmental and regulatory costs and (iii) a$2.4 million increase in workover expense due to the timing of workover activities focused in theDelaware Basin . LOE per Boe increased 14 percent to$3.02 for the three months endedMarch 31, 2022 from$2.66 for the three months endedMarch 31, 2021 . 31 --------------------------------------------------------------------------------PDC ENERGY, INC.
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 from year-to-year. Production taxes decreased 2 percent to$62.9 million for the three months endedMarch 31, 2022 compared to$64.1 million for the three months endedDecember 31, 2021 . Production taxes per Boe increased 6 percent to$3.51 for the three months endedMarch 31, 2022 compared to$3.30 for the three months endedDecember 31, 2021 . The increase in production taxes per Boe was primarily due to an increase in crude oil and NGLs prices between periods. Production taxes increased 113 percent to$62.9 million for the three months endedMarch 31, 2022 compared to$29.5 million for the three months endedMarch 31, 2021 . Production taxes per Boe increased 88 percent to$3.51 for the three months endedMarch 31, 2022 compared to$1.87 for the three months endedMarch 31, 2021 . The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between periods.
Transportation, Gathering and Processing Expense
TGP expense increased 8 percent to$28.0 million for the three months endedMarch 31, 2022 compared to$26.0 million for the three months endedDecember 31, 2021 . TGP expense per Boe increased 16 percent to$1.56 for the three months endedMarch 31, 2022 compared to$1.34 for the three months endedDecember 31, 2021 . The increase in TGP expense was primarily due to an increase in gas processing costs in theDelaware Basin between periods. TGP expense increased 29 percent to$28.0 million for the three months endedMarch 31, 2022 compared to$21.7 million for the three months endedMarch 31, 2021 . TGP expense per Boe increased 13 percent to$1.56 for the three months endedMarch 31, 2022 compared to$1.38 for the three months endedMarch 31, 2021 . The overall increase in TGP expense for the three months endedMarch 31, 2022 compared to the same period in 2021 was driven by a$5.6 million increase relating to gas processing costs and a$1.8 million increase in shortfall fees relating to our delivery commitment, both in theDelaware Basin .
Impairment of Properties and Equipment
There were no significant impairment charges recognized related to our proved and unproved oil and gas properties during the three months endedMarch 31, 2022 ,December 31, 2021 , andMarch 31, 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.
General and Administrative Expense
General and administrative expense slightly increased 9 percent to$34.1 million for the three months endedMarch 31, 2022 compared to$31.4 million for the three months endedDecember 31, 2021 , primarily due to an increase in charitable contributions and an increase in professional fees relating to the Great Western Acquisition in the first quarter of 2022. General and administrative expense remained relatively flat with an increase of 4 percent to$34.1 million for the three months endedMarch 31, 2022 compared to$32.7 million for the three months endedMarch 31, 2021 .
Depreciation, Depletion and Amortization Expense
DD&A expense 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$149.3 million for the three months endedMarch 31, 2022 compared to$154.7 million for the three months endedDecember 31, 2021 . The decrease in DD&A expense was primarily due to an 8 percent decrease in production volumes between periods partially offset by an increase in the weighted average DD&A expense rate as a result of capitalized costs of wells turned-in-line in the first quarter of 2022. 32 --------------------------------------------------------------------------------PDC ENERGY, INC. DD&A expense related to crude oil and natural gas properties was$149.3 million for the three months endedMarch 31, 2022 compared to$144.8 million for the comparable period in 2021. The increase in total DD&A expense was primarily due to a 14 percent increase in production volumes between periods primarily due to a greater number of wells turned-in-line since the second quarter of 2021 partially offset by a decrease in the weighted average DD&A expense rate.
The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following:
Change Between
March 31, 2022 - March 31, 2022 - December 31, 2021 March 31, 2021 (in millions) Increase (decrease) in production $ (11.7) $ 20.0
Increase (decrease) in weighted-average depreciation, depletion and amortization rates
6.3 (15.5)
Total increase (decrease) in DD&A expense related to crude oil and natural gas properties
$ (5.4) $ 4.5
The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties for the periods presented:
Three Months Ended March 31, 2022 December 31, 2021 March 31, 2021 (per Boe)Operating Region /Area Wattenberg Field$ 8.00 $ 7.70 $ 9.22 Delaware Basin 10.33 9.71 9.01 Total weighted average DD&A expense rate 8.33 7.97 9.20 Interest Expense, net Interest expense, net decreased$10.6 million to$12.9 million for the three months endedMarch 31, 2022 compared to$23.5 million for the three months endedDecember 31, 2021 . The decrease was primarily related to (i) reduced borrowings under our revolving credit facility between periods, (ii) a full redemption of our 2025 Senior Notes and a partial redemption of our 2024 Senior Notes in December andNovember 2021 , respectively, and (iii) a$6.9 million loss on extinguishment recognized in the fourth quarter of 2021 as a result of aforementioned redemptions of our Senior Notes. Interest expense, net decreased$6.1 million to$12.9 million for the three months endedMarch 31, 2022 compared to$19.0 million for the three months endedMarch 31, 2021 . The decrease was primarily related to (i) reduced borrowings under our revolving credit facility between periods, (ii) expiration and redemption of our 2021 Convertible Notes inSeptember 2021 , and (iii) a full redemption of our 2025 Senior Notes and a partial redemption of our 2024 Senior Notes in December andNovember 2021 , respectively.
Provision for Income Taxes
We recorded income tax expense of$1.2 million ,$26.5 million and$0.1 million for the three months endedMarch 31, 2022 ,December 31, 2021 , andMarch 31, 2021 , resulting in an effective income tax rate of 3.9 percent provision on pre-tax losses, 5.3 percent provision on pre-tax income and 0.6 percent provision on pre-tax losses, respectively. 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 pre-tax loss due to the effect of a valuation allowance against our deferred income tax assets. 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. Our 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 andMarch 31, 2022 since we cannot conclude that it is more likely than not that our DTAs will be fully realized in future periods. 33 --------------------------------------------------------------------------------PDC ENERGY, INC. 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 toMarch 31, 2022 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 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 later in 2022 and 2023.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors impacting a net loss of$32.0 million , net income of$473.1 million , and net loss of$9.0 million for the three months endedMarch 31, 2022 ,December 31, 2021 , andMarch 31, 2021 , respectively, are discussed above. Adjusted net income, a non-U.S. GAAP financial measure, was$358.6 million ,$283.1 million , and$141.6 million for the three months endedMarch 31, 2022 ,December 31, 2021 , andMarch 31, 2021 , respectively. With the exception of the tax-affected net change in fair value of unsettled commodity derivatives, when applicable, 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 ofMarch 31, 2022 is an indication of a lack of liquidity. We had working capital deficits of$541.7 million as ofMarch 31, 2022 and$461.5 million as ofDecember 31, 2021 . The increase in working capital deficit sinceDecember 31, 2021 was primarily due to an increase in the fair value of net derivative liabilities of$272.5 million and an increase in accounts payable of$64.4 million partially offset by an increase in receivables of$138.5 million and an increase in cash and cash equivalents of$137.3 million . 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. 34 --------------------------------------------------------------------------------PDC ENERGY, INC. 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$171.2 million atMarch 31, 2022 and availability under our revolving credit facility was$1.5 billion , providing for a total liquidity position of$1.65 billion as ofMarch 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 and working capital obligations. As commodity prices continue to 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. OnFebruary 26, 2022 , we entered into the Acquisition Agreement to acquire Great Western for approximately$1.4 billion , inclusive of Great Western's net debt. Under the terms of the Acquisition Agreement, the purchase consideration for the Great Western Acquisition will be made through the transfer 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 anticipate that the Great Western Acquisition will be completed inMay 2022 , subject to certain customary closing conditions being met. 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 approximately$227.0 million as ofMarch 31, 2022 . At closing, we are also expecting to pay off Great Western's$311.9 million of 12.0% Senior Notes dueSeptember 1, 2025 , plus a redemption premium. The payments of the debt balances is expected to 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. 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. There are no significant changes to our material cash requirements arising from contractual obligations sinceDecember 31, 2021 . 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 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. AtMarch 31, 2022 , 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 0.4:1.0. 35 --------------------------------------------------------------------------------PDC ENERGY, INC.
In
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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