PDC ENERGY, INC. 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 partial containment of COVID-19, which resulted in an increase in crude oil demand. Recovery has generally continued in 2022 despite a variety of economic headwinds, including outbreaks of COVID-19 variants. Overall production from OPEC+ has not increased at the same pace as 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 six months of 2022 when compared to 2021. During 2022, theU.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 the invasion ofUkraine byRussia . TheU.S. Federal Reserve has responded to the rise in inflation by 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 or lead to a recession. A slowdown or recession can cause a decrease or shift in short-term or long-term demand for crude oil, resulting in industry oversupply and the potential for lower commodity prices.
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 increased to 21.4 MMboe in the second quarter of 2022, an increase of 19 percent compared to 17.9 MMboe in the first quarter, primarily driven by the production volumes from the Great Western Acquisition. •Crude oil, natural gas and NGLs sales increased to$1,237.7 million compared to$882.4 million in the first quarter of 2022 primarily due to a 17 percent increase in weighted average realized commodity prices and a 19 percent increase in production volumes between periods. •Negative net settlements from our commodity derivative contracts increased to$298.7 million in the second quarter of 2022 compared to$161.6 million in the first quarter of 2022 due to a continued increase in commodity prices between periods and additional commodity derivatives acquired from Great Western. •Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 30 percent to$939.0 million from$720.8 million in the first quarter of 2022. 23 --------------------------------------------------------------------------------PDC ENERGY, INC. •Generated net income of$662.4 million , or$6.74 per diluted share, for the second quarter of 2022 and a net loss of$32.0 million , or$0.33 per diluted share, for the first quarter of 2022 primarily due to (i) an increase in crude oil, natural gas and NGLs sales of$355.3 million , (ii) a$466.1 million decrease in commodity risk management loss between periods, and (iii) a gain on bargain purchase from the Great Western Acquisition of$100.3 million , partially offset by an increase in income tax expense of$128.0 million between periods. •Adjusted EBITDAX, a non-U.S. GAAP financial measure, increased to$814.3 million compared to$549.3 million for the first quarter of 2022, primarily due to an increase in sales of$218.2 million , net of negative net derivative settlements, and a$100.3 million gain on bargain purchase recognized in the second quarter of 2022, partially offset by an increase in costs experienced in operations. •Cash flows from operations increased to$747.4 million compared to$489.0 million in the first quarter of 2022. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to$694.7 million compared to$538.8 million in the first quarter of 2022. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to$403.8 million from$318.7 million in the first quarter of 2022.
Six months ended
•Production volumes increased to 39.3 MMboe in 2022, an increase of 19 percent compared to 33.2 MMboe in 2021, primarily driven by production volumes from Great Western Acquisition and as a result of our turn-in-line activities.
•Crude oil, natural gas and NGLs sales increased to$2.1 billion compared to$1.0 billion in 2021 primarily due to a 79 percent increase in weighted average realized commodity prices and a 19 percent increase in production volumes between periods. •Negative net settlements from our commodity derivative contracts increased to$460.3 million in 2022 compared to$85.8 million in 2021 due to improvements in commodity pricing year over year and additional commodity derivatives acquired from Great Western.
•Combined revenue from crude oil, natural gas and NGLs sales and net settlements
from our commodity derivative instruments increased 81 percent to
•Generated net income of$630.4 million , or$6.42 per diluted share, in the 2022 period and a net loss of$96.1 million , or$0.97 per diluted share, in the 2021 period, primarily due to an increase in crude oil, natural gas and NGLs sales of$1,118.8 million and a gain on bargain purchase from the Great Western Acquisition of$100.3 million , partially offset by a$180.5 million increase in commodity risk management loss and a$129.3 million increase in income tax expense between periods . •Adjusted EBITDAX, a non-U.S. GAAP financial measure, increased to$1,363.5 million in 2022 compared to$674.1 million in 2021, primarily due to an increase in sales of$744.3 million , net of negative net derivative settlements, and a$100.3 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$1,236.4 million in 2022 compared to$577.4 million in 2021. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to$1,233.5 million in 2022 compared to$643.0 million in 2021. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to$722.5 million in 2022 from$341.4 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 comparableU.S. GAAP measures. 24 --------------------------------------------------------------------------------
Great Western Acquisition
OnMay 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 ofColorado . 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% 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 were 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.
Drilling and Completion Overview
In the Wattenberg Field, we operated one full-time drilling rig and one full-time completion crew during the first half of 2022, added a second full-time drilling rig inmid-March 2022 and added a third full-time drilling rig upon closing the Great Western Acquisition. In addition, we operated one full-time drilling rig and one completion crew during the first half of 2022 in theDelaware Basin . Our total capital investments in crude oil and natural gas properties for the six months endedJune 30, 2022 were$508.1 million .
The following table summarize our drilling and completion activities for the six
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 74 69.5 10 9.9 84 79.4
Wells acquired in-process (1) 48 44.6 - - 48 44.6
Wells turned-in-line (73) (68.9) (18) (17.8) (91) (86.7)
In-process as of June 30, 2022 192 178.2 13 12.7 205 190.9
_____________(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. 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 4.3 million shares of outstanding common stock at a cost of$300.0 million for the six months endedJune 30, 2022 . As ofJune 30, 2022 ,$978.1 million remained available for repurchases under the program. 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. For the six months endedJune 30, 2022 , our dividends totaled$59.1 million or$0.60 per share of outstanding common stock. 25 --------------------------------------------------------------------------------PDC ENERGY, INC.
2022 Operational and Financial Outlook
Upon completion of the Great Western Acquisition we provided updated guidance in lateMay 2022 . Based on our current operating results from the first half of the year, we now expect full-year 2022 production to range between 230,000 Boe to 240,000 Boe per day, of which approximately 73,000 Bbls to 77,000 Bbls is expected to be crude oil. Our planned 2022 capital investments in crude oil and natural gas properties are now expected to be between$1.025 and$1.075 billion and is focused on continued execution of our development plans in the Wattenberg Field and theDelaware Basin . Our capital budget and operating costs for 2022 will continue to be impacted by cost inflation if crude oil and natural gas prices remain at current levels or continue to increase. 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, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory matters 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, Summit and Range development areas. Our 2022 capital investment program for the Wattenberg Field represents approximately 80 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 and turning-in-line approximately 150 to 175 operated wells. To meet our development plan, we intend on running three full-time horizontal rigs and one full-time plus an intermittent completion crew 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 20 percent of our total capital investments. In 2022, we anticipate spudding 16 operated wells and turning-in-line 20 operated wells with the majority of the wells being 2.0 mile lateral wells. We completed our 2022 completion program in late May and are currently running one full-time drilling rig. 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$0.35 per share. Then we expect to use approximately 60% or more of our remaining adjusted free cash flows, a non-U.S. GAAP financial measure, for share repurchases and special dividends, as needed. Any remaining adjusted free cash flows will be used for reducing debt, building cash on our consolidated balance sheet or other general corporate purposes.
Regulatory and Political Updates
InColorado , certain interest groups opposed to oil and natural gas development have proposed ballot initiatives that could hinder or eliminate the ability to develop resources in the state. In 2019, theColorado legislature passedSenate Bill 19-181 ("SB 19-181") to address concerns underlying the ballot initiatives. 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, the interaction between the state and local governments, 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 26 --------------------------------------------------------------------------------PDC ENERGY, INC.
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 with operators in different tiers being obligated to provide different levels of financial assurance. For our tier, a bond of$40 million will be required in the second half of 2022 and will be secured through our existing surety bond program. In addition to the financial assurance, operators will be assessed an annual 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. In
InDecember 2021 , PDC submitted our first CAP. The application proposes approximately 450 wells spread amongst 22 surface locations, 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, while also improving our ESG metrics. 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 worked with COGCC on comments received on this CAP, submitted updated plans inJune 2022 and received the completeness determination onAugust 2, 2022 . 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 past 2028.
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. OnMarch 31, 2022 , we completed our initialU.S. Environmental Protection Agency ("EPA ") annual filing for 2021 and we reported an approximate 12% reduction in greenhouse gas ("GHG") emissions and an approximate 17% reduction in methane emissions intensity from 2020 baseline levels (each on a per unit of production basis), putting the Company on track to meet its 60% and 50% GHG and methane reduction goals by 2025, respectively. Additionally, inMay 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, respectively. As noted above, this supports the Company's previously announced sustainability goals. In total, over 25% of our short-term incentive program is tied to ESG and Environmental, Health and Safety initiatives. 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. 27 --------------------------------------------------------------------------------
PDC ENERGY, INC.
Results of Operations
Summary of Operating Results
The following table presents selected information regarding our operating
results:
Three Months Ended Six Months Ended
March 31,
June 30, 2022 2022 Percent Change June 30, 2022 June 30, 2021 Percent Change
(dollars in millions, except per unit data)
Production:
Crude oil (MBbls) 6,844 5,853 17 % 12,697 10,248 24 %
Natural gas (MMcf) 49,817 43,119 16 % 92,936 83,512 11 %
NGLs (MBbls) 6,263 4,885 28 % 11,148 8,997 24 %
Crude oil equivalent (MBoe) 21,410 17,924 19 % 39,335 33,164 19 %
Average Boe per day (Boe) 235,275 199,156 18 % 217,320 183,227 19 %
Crude Oil, Natural Gas and NGLs
Sales:
Crude oil $ 740.9 $ 549.7 35 % $ 1,290.6 $ 624.3 107 %
Natural gas 277.7 163.1 70 % 440.8 191.4 130 %
NGLs 219.1 169.6 29 % 388.7 185.6 109 %
Total crude oil, natural gas and NGLs
sales $ 1,237.7 $ 882.4 40 % $ 2,120.1 $ 1,001.3 112 %
Net Settlements on Commodity
Derivatives `
Crude oil $ (231.4) $ (131.1) 77 % $ (362.5) $ (68.4) *
Natural gas (67.3) (30.5) 121 % (97.8) (17.4) *
Total net settlements on derivatives
85 %$ (460.3) $ (85.8) * Average Sales Price (excluding net settlements on derivatives): Crude oil (per Bbl)$ 108.24 $ 93.93 15 %$ 101.64 $ 60.92 67 % Natural gas (per Mcf) 5.57 3.78 47 % 4.74 2.29 107 % NGLs (per Bbl) 34.99 34.70 1 % 34.86 20.61 69 % Crude oil equivalent (per Boe) 57.81 49.23 17 % 53.90 30.19
79 %
Average Costs and Expenses (per Boe): Lease operating expense $ 3.30$ 3.02 9 % $ 3.17 $ 2.54 25 % Production taxes 4.17 3.51 19 % 3.87 1.70 128 % Transportation, gathering and processing expense 1.38 1.56 (12) % 1.46 1.44 1 % General and administrative expense 2.13 1.90 12 % 2.03 1.98 3 % Depreciation, depletion and amortization 8.92 8.43 6 % 8.70 9.32 (7) % Lease Operating Expense by Operating Region (per Boe) Wattenberg Field $ 2.85$ 2.42 18 % $ 2.65 $ 2.23 19 % Delaware Basin 5.98 6.67 (10) % 6.29 4.77 32 % ____________
* Percent change is not meaningful.
28
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PDC ENERGY, INC.
As a result of non-recurring costs incurred during the second quarter of 2022 to
acquire Great Western and integrate it into our operations, our results of
operations are not indicative of future results of operations for the second
half of 2022. Additionally, we anticipate increases in production volumes and
production cost per Boe as the integration of Great Western continues. Further,
we expect increases in DD&A per Boe due to the fair value of Great Western's
crude oil and natural gas properties and a decrease in general and
administrative expenses as acquisition transaction and transition costs wind
down after the integration. Lastly, we expect interest expense to increase in
the second half of 2022 as a result of our increased level of borrowings under
our revolving credit facility resulting from the funding of the Great Western
Acquisition and an overall increase in market interest rates.
Crude Oil, Natural Gas and NGLs Sales
The change in crude oil, natural gas and NGLs sales for the three months endedJune 30, 2022 compared to the three months endedMarch 31, 2022 and the six months endedJune 30, 2022 compared to the six months endedJune 30, 2021 were due to the following: Change Between March 31, 2022 - June 30, 2021 - June 30, 2022 June 30, 2022 (in millions) Change in: Production $ 166.3 $ 215.1 Average crude oil price 97.9 517.1 Average natural gas price 89.3 227.8 Average NGLs price 1.8 158.8
Total change in crude oil, natural gas and NGLs sales revenue
$ 355.3 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 Six Months Ended
Production by Operating Region June 30, 2022 March 31, 2022 Percent Change June 30, 2022 June 30, 2021 Percent Change
Crude oil (MBbls)
Wattenberg Field 5,545 4,832 15 % 10,377 8,670 20 %
Delaware Basin 1,299 1,021 27 % 2,320 1,578 47 %
Total 6,844 5,853 17 % 12,697 10,248 24 %
Natural gas (MMcf)
Wattenberg Field 43,244 37,663 15 % 80,907 73,742 10 %
Delaware Basin 6,573 5,456 20 % 12,029 9,770 23 %
Total 49,817 43,119 16 % 92,936 83,512 11 %
NGLs (MBbls)
Wattenberg Field 5,575 4,291 30 % 9,866 8,153 21 %
Delaware Basin 688 594 16 % 1,282 844 52 %
Total 6,263 4,885 28 % 11,148 8,997 24 %
Crude oil equivalent (MBoe)
Wattenberg Field 18,328 15,400 19 % 33,728 29,113 16 %
Delaware Basin 3,082 2,524 22 % 5,607 4,051 38 %
Total 21,410 17,924 19 % 39,335 33,164 19 %
Average crude oil equivalent per
day (Boe)
Wattenberg Field 201,407 171,111 18 % 186,342 160,846 16 %
Delaware Basin 33,868 28,045 21 % 30,978 22,381 38 %
Total 235,275 199,156 18 % 217,320 183,227 19 %
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PDC ENERGY, INC.
Net production volumes for oil, natural gas and NGLs increased 19 percent during
the three months ended June 30, 2022 compared to the three months ended March
31, 2022 primarily due to 3.0 MMboe of additional production volumes from the
Great Western Acquisition and the net impact of turn-in-line activities in both
basins during the second quarter of 2022.
Net production volumes for oil, natural gas and NGLs increased 19 percent during
the six months ended June 30, 2022 compared to the same period in 2021. The
increase in production volume between periods was primarily due to 3.0 MMboe of
additional production volumes from the Great Western Acquisition and the net
impact of turn-in-line activities in both basins since the second 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 June 30, 2022
Crude Oil Natural Gas NGLs Total
Wattenberg Field 30% 39% 31% 100%
Delaware Basin 42% 36% 22% 100%
Three Months Ended March 31, 2022
Crude Oil Natural Gas NGLs Total
Wattenberg Field 31% 41% 28% 100%
Delaware Basin 40% 36% 24% 100%
Six Months Ended June 30, 2022
Crude Oil Natural Gas NGLs Total
Wattenberg Field 31% 40% 29% 100%
Delaware Basin 41% 36% 23% 100%
Six Months Ended June 30, 2021
Crude Oil Natural Gas NGLs Total
Wattenberg Field 30% 42% 28% 100%
Delaware Basin 39% 40% 21% 100%
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 Delaware Basin was not materially
affected by midstream or downstream capacity constraints during the six months
ended June 30, 2022 . We continuously monitor infrastructure capacities versus
producer activity and production volume forecasts. Continued increases in crude
oil and natural gas prices through early 2022 have incentivized producers in the
Permian 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 the Permian Basin by the end of 2022 or in 2023, which may
result to lower realized Waha natural gas prices. However, a majority of PDC's
gas production in the Delaware Basin is dedicated to Permian Highway Pipeline
and is exposed to Houston -based gas pricing.
30
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PDC ENERGY, INC.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 Six Months Ended
Weighted Average Realized Sales
Price by Operating Region
(excluding net settlements on March 31, June 30,
derivatives) June 30, 2022 2022 Percent Change June 30, 2022 2021 Percent Change
Crude oil (per Bbl)
Wattenberg Field $ 108.05 $ 93.52 16 % $ 101.28 $ 60.84 66 %
Delaware Basin 109.06 95.86 14 % 103.25 61.35 68 %
Weighted average price 108.24 93.93 15 % 101.64 60.92 67 %
Natural gas (per Mcf)
Wattenberg Field $ 5.50 $ 3.82 44 % $ 4.71 $ 2.33 102 %
Delaware Basin 6.09 3.56 71 % 4.94 2.02 145 %
Weighted average price 5.57 3.78 47 % 4.74 2.29 107 %
NGLs (per Bbl)
Wattenberg Field $ 32.56 $ 32.37 1 % $ 32.48 $ 19.78 64 %
Delaware Basin 54.62 51.54 6 % 53.19 28.65 86 %
Weighted average price 34.99 34.70 1 % 34.86 20.61 69 %
Crude oil equivalent (per Boe)
Wattenberg Field $ 55.57 $ 47.69 17 % $ 51.97 $ 29.56 76 %
Delaware Basin 71.13 58.59 21 % 65.48 34.75 88 %
Weighted average price 57.81 49.23 17 % 53.90 30.19 79 %
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.
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PDC ENERGY, INC.
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 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
Average Realized Average Realization Realized Price Average Realization
Three Months Ended Average NYMEX Price Before TGP Percentage Before Average TGP After TGP Percentage After TGP
June 30, 2022 Price Expense TGP Expense Expense (1) Expense Expense
Crude oil (per Bbl) $ 108.41 $ 108.24 100 % $ 2.37 $ 105.87 98 %
Natural gas (per
MMBtu) 7.17 5.58 78 % 0.22 5.36 75 %
NGLs (per Bbl) 108.41 34.99 32 % - 34.99 32 %
Crude oil equivalent
(per Boe) 83.05 57.81 70 % 1.26 56.55 68 %
Average
Average Realized Average Realization Realized Price Average Realization
Three Months Ended Average NYMEX Price Before TGP Percentage Before Average TGP After TGP Percentage After TGP
March 31, 2022 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
Average Realized Average Realization Realized Price Average Realization
Six Months Ended Average NYMEX Price Before TGP Percentage Before Average TGP After TGP Percentage After TGP
June 30, 2022 Price Expense TGP Expense Expense (1) Expense Expense
Crude oil (per Bbl) $ 101.35 $ 101.65 100 % $ 2.52 $ 99.13 98 %
Natural gas (per
MMBtu) 6.06 4.74 78 % 0.22 4.52 75 %
NGLs (per Bbl) 101.35 34.86 34 % - 34.86 34 %
Crude oil equivalent
(per Boe) 75.76 53.90 71 % 1.33 52.57 69 %
Average
Average Realized Average Realization Realized Price Average Realization
Six Months Ended Average NYMEX Price Before TGP Percentage Before Average TGP After TGP Percentage After TGP
June 30, 2021 Price Expense TGP Expense Expense (1) Expense Expense
Crude oil (per Bbl) $ 61.96 $ 60.92 98 % $ 3.32 $ 57.60 93 %
Natural gas (per
MMBtu) 2.76 2.29 83 % 0.11 2.18 79 %
NGLs (per Bbl) 61.96 20.61 33 % - 20.61 33 %
Crude oil equivalent
(per Boe) 42.91 30.19 70 % 1.32 28.87 67 %
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(1)Average TGP expense excludes unutilized firm transportation fees of $0.12 per
Boe and $0.14 per Boe for the three months ended June 30, 2022 and March 31,
2022 , respectively, and 0.13 and $0.12 per Boe for the six months ended June 30,
2022 and 2021, respectively.
Our average realization percentages for crude oil, natural gas and NGLs were
relatively flat for the three months ended
Our average realization percentage for crude oil increased for the six months endedJune 30, 2022 as compared to the same period in 2021 primarily due to an increased demand for crude oil, global supply disruptions and geopolitical issues. In 32 --------------------------------------------------------------------------------PDC ENERGY, INC. addition, we realized improved differentials from our 2022 crude oil sales contracts. Average realization percentage for natural gas decreased for the six months endedJune 30, 2022 compared to the six months endedJune 30, 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 ofJune 30, 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 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 Six Months Ended
June 30, 2022 March 31, 2022 June 30, 2022 June 30, 2021
(in millions)
Commodity price risk management gain
(loss), net:
Net settlements of commodity derivative
instruments:
Crude oil collars and fixed price
exchanges $ (231.4) $
(131.1)
(75.7) (28.1) (103.8) (7.5)
Natural gas basis protection exchanges 8.4 (2.3) 6.1 (9.9)
Total net settlements of commodity
derivative instruments (298.7) (161.5) (460.2) (85.8)
Change in fair value of unsettled
commodity derivative instruments:
Reclassification of settlements included
in prior period changes in fair value of
commodity derivative instruments 173.9 100.2 174.9 (5.4)
Crude oil collars and fixed price
exchanges (6.6) (373.6) (308.0) (329.5)
Natural gas collars and fixed price
exchanges 41.4 (140.6) (71.0) (67.7)
Natural gas basis protection exchanges (12.0) 7.4 (5.7) (1.1)
Net change in fair value of unsettled
commodity derivative instruments 196.7 (406.6) (209.8) (403.7)
Total commodity price risk management
gain (loss), net $ (102.0) $
(568.1)
The continued increase in commodity prices during the three months ended
33
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PDC ENERGY, INC. Lease Operating Expense
Lease operating expense ("LOE") increased by 30 percent to $70.6 million for the
three months ended June 30, 2022 compared to $54.2 million for the three months
ended March 31, 2022 . The period-over-period increase in LOE was primarily
attributable to (i) an approximate $7.0 million increase as a result of the
Great Western Acquisition, (ii) a $4.8 million increase in water disposal, well
and pumper services in both basins as a result of higher commodity prices and
inflation and (iii) $1.8 million in additional environmental costs in the
Wattenberg basin. LOE per Boe increased 9 percent to $3.30 for the three months
ended June 30, 2022 from $3.02 for the three months ended March 31, 2022 . The
increase in LOE per Boe was primarily due to the additional costs outlined
above.
LOE increased by 48 percent to $124.8 million for the six months ended June 30,
2022 compared to $84.2 million for the six months ended June 30, 2021 . The
period-over-period increase in LOE was primarily due to (i) a $7.0 million
increase a as a result of the Great Western Acquisition, (ii) increased
activities and payroll costs of $12.8 million resulting from an increase in
activities in both basins, (iii) an $11.4 million increase in chemical
treatments, water disposal and environmental costs as a result of higher
commodity prices and inflation and (iv) a $6.2 million increase in workover
expense due to the timing of workover activities focused mainly in the Delaware
Basin . LOE per Boe increased 25 percent to $3.17 for the six months ended
June 30, 2022 from $2.54 for the six months ended June 30, 2021 , an increase
that was 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 from year-to-year. Production taxes increased 42 percent to$89.3 million for the three months endedJune 30, 2022 compared to$62.9 million for the three months endedMarch 31, 2022 . Production taxes per Boe increased 19 percent to$4.17 for the three months endedJune 30, 2022 compared to$3.51 for the three months endedMarch 31, 2022 . The increase in production taxes was primarily due to additional production volumes from the Great Western Acquisition and higher crude oil, natural gas and NGL prices between periods. Production taxes increased 170 percent to$152.2 million for the six months endedJune 30, 2022 compared to$56.5 million for the six months endedJune 30, 2021 . Production taxes per Boe increased 128 percent to$3.87 for the six months endedJune 30, 2022 compared to$1.70 for the six months endedJune 30, 2021 . The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between periods and additional production from the Great Western Acquisition.
Transportation, Gathering and Processing Expense
TGP expense increased 6 percent to$29.6 million for the three months endedJune 30, 2022 compared to$28.0 million for the three months endedMarch 31, 2022 . The increase in TGP expense between periods was primarily due to a$1.7 million increase relating to additional production volumes from the Great Western Acquisition. TGP expense per Boe decreased 12 percent to$1.38 for the three months endedJune 30, 2022 compared to$1.56 for the three months endedMarch 31, 2022 . The decrease in TGP expense per Boe between periods was primarily due to lower TGP rates on the acquired Great Western production. TGP expense increased 21 percent to$57.6 million for the six months endedJune 30, 2022 compared to$47.7 million for the six months endedJune 30, 2021 . The increase in TGP expense between periods was primarily due to a$1.7 million increase relating to additional production volumes from the Great Western Acquisition in 2022 and a$10.5 million increase relating to gas processing volumes and rates in theDelaware basin. TGP expense per Boe increased 1 percent to$1.46 for the six months endedJune 30, 2022 compared to$1.44 for the six months endedJune 30, 2021 . TGP expense per Boe for the six months endedJune 30, 2022 compared to the same period in 2021 was relatively flat due to the net impact of lower TGP rates on the acquired Great Western production offset by higher gas processing costs. 34 --------------------------------------------------------------------------------PDC ENERGY, INC.
Impairment of Properties and Equipment
There were no significant impairment charges recognized related to our proved and unproved oil and gas properties for the three months endedJune 30, 2022 orMarch 31, 2022 or for the six months endedJune 30, 2022 or 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 increased 34 percent to$45.6 million for the three months endedJune 30, 2022 compared to$34.1 million for the three months endedMarch 31, 2022 , primarily due to$13.0 million in transaction and transition costs recognized in the second quarter of 2022 relating to the Great Western Acquisition. General and administrative expense increased 22 percent to$79.8 million for the six months endedJune 30, 2022 compared to$65.5 million for the six months endedJune 30, 2021 , primarily due to$13.0 million in transaction and transition costs recognized in the second quarter of 2022 relating to the Great Western Acquisition.
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$189.1 million for the three months endedJune 30, 2022 compared to$149.3 million for the three months endedMarch 31, 2022 . The increase in DD&A expense was primarily due to (i) a 19 percent increase in production volumes between periods, (ii) an increase in the weighted average DD&A expense rate primarily due to the fair value of proved crude oil and natural gas properties acquired from Great Western and (iii) capitalized costs for wells turned-in-line in the second quarter of 2022. DD&A expense related to crude oil and natural gas properties was$338.4 million for the six months endedJune 30, 2022 compared to$305.0 million for the comparable period in 2021. The increase in total DD&A expense was primarily due to a 19 percent increase in production volumes between periods and capitalized costs for wells turned-in-line since the second quarter of 2021 partially offset by a decrease in weighted average DD&A expense rate resulting from our improved reserve quantities as ofDecember 31, 2021 .
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 - June 30, 2021 -
June 30, 2022 June 30, 2022
(in millions)
Increase (decrease) in production $ 29.2 $ 57.4
Increase (decrease) in weighted average depreciation, depletion and amortization rates
10.7 (24.0)
Total increase (decrease) in DD&A expense related to crude oil and natural gas properties
$ 39.9 $ 33.4
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 Six Months Ended
June 30, 2022 March 31, 2022 June 30, 2022 June 30, 2021
(per Boe)
Operating Region /Area
Wattenberg Field $ 8.52 $ 8.00 $ 8.28 $ 9.10
Delaware Basin 10.68 10.33 10.52 9.89
Total weighted average DD&A expense
rate 8.83 8.33 8.60 9.20
35
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PDC ENERGY, INC. Interest Expense, net
Interest expense, net increased$4.6 million to$17.6 million for the three months endedJune 30, 2022 compared to$12.9 million for the three months endedMarch 31, 2022 . The increase was primarily due to a$5.4 million increase relating to increased borrowings under our revolving credit facility in the second quarter of 2022 to finance the cash portion of the purchase price of the Great Western Acquisition. Interest expense, net decreased$8.6 million to$30.5 million for the six months endedJune 30, 2022 compared to$39.1 million for the six months endedJune 30, 2021 . The decrease was primarily due to a$6.0 million decrease from the expiration and redemption of our 2021 Convertible Notes inSeptember 2021 and a$9.3 million decrease from the full redemption of our 2025 Senior Notes and a partial redemption of our 2024 Senior Notes in December andNovember 2021 , respectively. The decrease was partially offset by$5.5 million 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.
Gain on Bargain Purchase
We recognized a$100.3 million gain on the bargain purchase of the Great Western Acquisition, net of related income taxes of$31.5 million , for the three and six months endedJune 30, 2022 . For additional information, see Note 2 - Business Combination to our condensed consolidated financial statements included elsewhere in this report.
Provision for Income Taxes
We recorded income tax expense of$128.0 million , excluding our discrete gain on bargain purchase of$100.3 million , and$1.2 million for the three months endedJune 30, 2022 andMarch 31, 2022 , respectively, resulting in an effective income tax rate of 18.5 percent provision on pre-tax income, and 3.9 percent provision on pre-tax losses, respectively. We recorded income tax expense of$129.2 million , excluding our discrete gain on bargain purchase of$100.3 million , and$0.1 million for the six months endedJune 30, 2022 andJune 30, 2021 , respectively, resulting in an effective income tax rate of 19.6 percent provision on pre-tax income, and 0.2 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 the valuation allowance or changes in the 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 became 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 continue to provide a valuation allowance against our DTAs beginningJanuary 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. During the period endedJune 30, 2022 , sufficient positive evidence became available that allowed us to reach a conclusion that it is more likely than not that our DTAs will be realized and the valuation allowance is no longer be needed. As we previously disclosed in our 2021 Form 10-K, we maintained a valuation allowance on our net federal deferred tax assets and would continue to do so until sufficient positive evidence exists to support a reversal of the allowance. In the second quarter, continued higher commodity prices have 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$22.4 million of the valuation allowance against our deferred income tax assets and recognized a corresponding decrease to income tax expense in the period endedJune 30, 2022 . The remainder of the valuation allowance of$34.2 million will be recognized as a decrease to income taxes expense over the second half of 2022. Given recent improvements in oil and gas prices and assumptions based on our current production forecasts, we estimate that we will incur significant cash federal and state income taxes in 2023. 36 --------------------------------------------------------------------------------PDC ENERGY, INC.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors impacting a net income of$662.4 million and a net loss of$32.0 million for the three months endedJune 30, 2022 andMarch 31, 2022 , respectively, and a net income of$630.4 million and a net loss of$96.1 million for the six months endedJune 30, 2022 andJune 30, 2021 , respectively, are discussed above. Adjusted net income, a non-U.S. GAAP financial measure, was$502.1 million and$358.6 million for the three months endedJune 30, 2022 andMarch 31, 2022 , respectively, and$798.2 million and$307.6 million for the six months endedJune 30, 2022 , andJune 30, 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 ofJune 30, 2022 is an indication of a lack of liquidity. We had working capital deficits of$1,090.0 million as ofJune 30, 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$400.7 million and by a net deficit in working capital items as result of the Great Western Acquisition. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time. From time to time, we may seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise.
Liquidity
Our cash and cash equivalents were
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. If 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.
37
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PDC ENERGY, INC.
As a result of the Great Western Acquisition, we paid $361.2 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 off Great Western's secured credit facility
totaling $235.7 million , 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 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 since December 31, 2021 .
In April 2022 , as part of our 2022 semi-annual borrowing base redetermination,
the borrowing base increased from $2.4 billion to $3.0 billion ; however, we
maintained our elected commitment amount 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. Additionally, the
current ratio covenant calculation allows us to exclude 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 June 30, 2022 , we were in compliance with all covenants in
the revolving credit facility with a current ratio of 1.3:1.0 and a leverage
ratio of 0.7:1.0.
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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