ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. Throughout the following discussion, we explain changes between the three months ended March 31, 2022, compared with the three months ended December 31, 2021 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the three months ended March 31, 2022, compared with the three months ended March 31, 2021 (“YTD 2022-over-YTD 2021”).
Overview of the Company
General Overview
Our strategic objective is to be a premier operator of top-tier oil and gas assets. Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our short-term operational and financial goals include generating positive cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization. Our long-term vision is to sustainably grow value for all of our stakeholders. Our strategy for achieving our goals is to focus on high-quality economic drilling, completion, and production opportunities. Our investment portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.
We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive impact in the communities where we live and work; and transparency in reporting on our progress in these areas. We have prioritized ESG initiatives by, among other things, integrating enhanced environmental and social programs throughout the organization and setting near-term and medium-term goals that include reducing flaring and greenhouse gas emissions intensity and maintaining low methane emissions intensity. Additionally, we are putting systems in place to track additional ESG metrics to enable increased reporting in the future and to increase employee awareness. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s ESG policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures.
Prices for the commodities produced by our industry remained strong during the first quarter of 2022 with benchmark oil prices increasing compared with the fourth quarter of 2021, in part due to the impact of the conflict between Russia and Ukraine on global commodity and financial markets, and in response to economic and trade sanctions that certain countries have imposed on Russia. Additionally, although the Pandemic remains a global health crisis and continues to evolve, consumer demand has strengthened as cases of the Omicron variant of COVID-19 have decreased from winter levels. Increased demand for oil and gas products has outpaced increased supply, resulting in strong commodity prices which, for 2021, rose to their highest average annual prices since 2014. However, global commodity and financial markets remain subject to heightened levels of uncertainty and volatility related to these events, and future disruptions and industry-specific impacts could result, which may require us to adjust our business plan. For additional detail, please refer to the Risk Factors section in Part I, Item 1A of our 2021 Form 10-K. Despite continuing impacts of geopolitical issues, the Pandemic, and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top-tier Midland Basin and South Texas assets. Throughout the Pandemic, the safety of our employees, contractors, and the communities where we work has remained our first priority. While our core business operations required certain individuals to be physically present at well site locations, the majority of our office-based employees worked remotely from the onset of the Pandemic through February of 2022. We maintain and continually assess procedures designed to limit the spread of COVID-19, and we continue to communicate to and train all of our employees regarding best practices for maintaining a healthy and safe work environment. We believe that we meet or exceed Centers for Disease Control and Prevention and federal Occupational Safety and Health Act guidelines related to the prevention of the transmission of COVID-19. Throughout the Pandemic, we have operated without significant disruptions to our business, and we believe that our pre-existing control environment and internal controls continue to be effective.
Areas of Operations
Our Midland Basin assets are comprised of approximately 80,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the first quarter of 2022, drilling and completion activities within our RockStar and Sweetie Peck positions continued to focus primarily on development optimization and further delineating our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
Our South Texas assets are comprised of approximately 155,000 net acres located in the Maverick Basin in Dimmit and Webb Counties, Texas (“South Texas”). In the first quarter of 2022, our operations in South Texas were focused on production from both the Austin Chalk formation and Eagle Ford shale formation, and further development of the Austin Chalk formation. Our overlapping acreage position in the Maverick Basin covers a significant portion of the western Eagle Ford shale and Austin Chalk formations, and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.
First Quarter 2022 Overview and Outlook for the Remainder of 2022
During the first quarter of 2022, we remained committed to our goal of reducing the principal balance of our outstanding debt through cash flow generation. For the three months ended March 31, 2022, net cash provided by operating activities exceeded net cash used in investing activities by $192.0 million, and we reduced the principal balance of our total outstanding long-term debt by $104.8 million. Further, cash and cash equivalents increased from $332.7 million at December 31, 2021, to $419.9 million at March 31, 2022. We executed on this goal through strong operational performance and a diligent focus on cost management, and we benefited from increased commodity pricing which has improved from historic lows experienced during the height of the Pandemic.
Our 2022 capital program is expected to be approximately $750.0 million. Our financial and operational flexibility allows us to continually monitor the economic environment and adjust our activity level as warranted. Our 2022 capital program remains focused on highly economic oil development projects in both our Midland Basin and South Texas assets. We believe that our high-quality asset portfolio is capable of generating strong returns in the current macroeconomic environment, which we expect will enable us to grow cash flows, improve leverage metrics, and maintain strong financial flexibility. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2022 capital program.
Financial and Operational Results. Average net daily equivalent production for the three months ended March 31, 2022, decreased three percent sequentially to 153.3 MBOE, primarily driven by a decrease in oil volumes of 15 percent, or 12.7 MBbl per day, which was the result of timing of well completions. The decrease in oil volumes was partially offset by an increase of 37 percent, or 6.3 MBbl per day, in NGL volumes.
Increases in benchmark oil prices during the first quarter of 2022 resulted in an increased realized oil price, before the effect of derivative settlements, of 24 percent sequentially. Gas and NGL realized prices, before the effect of derivative settlements, decreased sequentially by 15 percent, and three percent, respectively. Total realized price before the effect of derivative settlements (“realized price” or “realized prices”) per BOE increased six percent sequentially. The increase in total realized price per BOE was partially offset by the decrease in total net equivalent production volumes, resulting in a one percent increase in oil, gas, and NGL production revenue, which was $858.7 million for the three months ended March 31, 2022, compared with $852.4 million for the three months ended December 31, 2021. Oil, gas, and NGL production expense per BOE of $10.49 for the three months ended March 31, 2022, increased seven percent sequentially, primarily as a result of increased ad valorem tax expense, production tax expense, and transportation costs per BOE.
We recorded a net derivative loss of $418.5 million for the three months ended March 31, 2022, compared to a net derivative gain of $22.5 million for the three months ended December 31, 2021. Included within these amounts are derivative settlement losses of $168.2 million and $268.7 million for the three months ended March 31, 2022, and December 31, 2021, respectively, resulting from increased benchmark commodity prices.
Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021 below for additional discussion.
Operational and financial activities during the three months ended March 31, 2022, resulted in the following:
•Net cash provided by operating activities of $342.1 million for the three months ended March 31, 2022, compared with $429.6 million for the three months ended December 31, 2021.
•A cash and cash equivalents balance of $419.9 million and no outstanding balance on the revolving credit facility as of March 31, 2022, and a reduction of the principal balance of our total outstanding long-term debt of $104.8 million from December 31, 2021, to March 31, 2022.
•Net income of $48.8 million, or $0.39 per diluted share, for the three months ended March 31, 2022, compared with net income of $424.9 million, or $3.43 per diluted share, for the three months ended December 31, 2021. Net income for the three months ended March 31, 2022, was primarily a result of strong oil pricing partially offset by a net derivative loss of $418.5 million. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021 below for additional discussion regarding the components of net income (loss) for the periods presented.
•Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2022, was $524.6 million, compared with $406.9 million for the three months ended December 31, 2021. Please refer to the caption Non-GAAP
Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income (loss) and net cash provided by operating activities.
Operational Activities. In our Midland Basin program, we operated three drilling rigs and one completion crew, and drilled 16 gross (14 net) wells and completed six gross (five net) wells during the first quarter of 2022. Net equivalent production volumes decreased sequentially by 17 percent to 7.9 MMBOE. Costs incurred in our Midland Basin program during the three months ended March 31, 2022, totaled $84.4 million, or 48 percent of our total costs incurred for the period. During the remainder of 2022, we anticipate operating three drilling rigs and one completion crew, which will continue to utilize both zipper or simul-frac techniques, where two or more horizontal wells are stimulated at the same time using a single fleet. Activity will focus primarily on developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions in the Midland Basin.
In our South Texas program, we operated two drilling rigs and one completion crew, and drilled nine gross (nine net) wells and completed 13 gross (13 net) wells during the first quarter of 2022. Net equivalent production volumes increased sequentially by 16 percent to 5.9 MMBOE. Costs incurred in our South Texas program during the three months ended March 31, 2022, totaled $76.1 million, or 43 percent of our total costs incurred for the period. During the remainder of 2022, we anticipate operating two drilling rigs and one completion crew, focused primarily on developing the Austin Chalk formation.
The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three months ended March 31, 2022:
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| Midland Basin | | South Texas (1) | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
Wells drilled but not completed at December 31, 2021 | 30 | | | 27 | | | 32 | | | 32 | | | 62 | | | 59 | |
Wells drilled | 16 | | | 14 | | | 9 | | | 9 | | | 25 | | | 23 | |
Wells completed | (6) | | | (5) | | | (13) | | | (13) | | | (19) | | | (18) | |
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Wells drilled but not completed at March 31, 2022 | 40 | | | 36 | | | 28 | | | 28 | | | 68 | | | 64 | |
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(1) The South Texas drilled but not completed well count as of March 31, 2022, includes 11 gross (11 net) wells that are not included in our five-year development plan, 10 of which are in the Eagle Ford shale.
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $175.1 million for the three months ended March 31, 2022, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above.
Production Results. The table below presents our production by product type for each of our assets for the three months ended March 31, 2022, December 31, 2021, and March 31, 2021:
| | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended |
| March 31, 2022 | | December 31, 2021 | | | | March 31, 2021 |
Midland Basin Production: | | | | | | | |
Oil (MMBbl) | 5.3 | | | 6.7 | | | | | 5.1 | |
Gas (Bcf) | 15.5 | | | 16.5 | | | | | 10.6 | |
NGLs (MMBbl) | — | | | — | | | | | — | |
Equivalent (MMBOE) | 7.9 | | | 9.4 | | | | | 6.9 | |
Average net daily equivalent (MBOE per day) | 87.4 | | | 102.6 | | | | | 76.1 | |
Relative percentage | 57 | % | | 65 | % | | | | 68 | % |
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South Texas Production: | | | | | | | |
Oil (MMBbl) | 1.2 | | | 1.1 | | | | | 0.3 | |
Gas (Bcf) | 15.9 | | | 14.7 | | | | | 11.0 | |
NGLs (MMBbl) | 2.1 | | | 1.6 | | | | | 1.0 | |
Equivalent (MMBOE) | 5.9 | | | 5.1 | | | | | 3.2 | |
Average net daily equivalent (MBOE per day) | 65.8 | | | 55.7 | | | | | 35.5 | |
Relative percentage | 43 | % | | 35 | % | | | | 32 | % |
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Total Production: | | | | | | | |
Oil (MMBbl) | 6.5 | | | 7.8 | | | | | 5.4 | |
Gas (Bcf) | 31.4 | | | 31.3 | | | | | 21.5 | |
NGLs (MMBbl) | 2.1 | | | 1.6 | | | | | 1.0 | |
Equivalent (MMBOE) | 13.8 | | | 14.6 | | | | | 10.0 | |
Average net daily equivalent (MBOE per day) | 153.3 | | | 158.3 | | | | | 111.6 | |
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Note: Amounts may not calculate due to rounding.
Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021 below for discussion on production.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.
The following table summarizes commodity price data, as well as the effect of derivative settlements, for the three months ended March 31, 2022, December 31, 2021, and March 31, 2021:
| | | | | | | | | | | | | | | | | |
| For the Three Months Ended |
| March 31, 2022 | | December 31, 2021 | | March 31, 2021 |
Oil (per Bbl): | | | | | |
Average NYMEX contract monthly price | $ | 94.29 | | | $ | 77.19 | | | $ | 57.84 | |
Realized price | $ | 94.03 | | | $ | 76.08 | | | $ | 56.33 | |
Effect of oil derivative settlements | $ | (20.00) | | | $ | (22.97) | | | $ | (10.38) | |
Gas: | | | | | |
Average NYMEX monthly settle price (per MMBtu) | $ | 4.95 | | | $ | 5.83 | | | $ | 2.69 | |
Realized price (per Mcf) | $ | 5.42 | | | $ | 6.35 | | | $ | 4.16 | |
Effect of gas derivative settlements (per Mcf) | $ | (0.86) | | | $ | (2.05) | | | $ | (1.88) | |
NGLs (per Bbl): | | | | | |
Average OPIS price (1) | $ | 48.36 | | | $ | 44.21 | | | $ | 30.47 | |
Realized price | $ | 38.56 | | | $ | 39.63 | | | $ | 26.93 | |
Effect of NGL derivative settlements | $ | (5.67) | | | $ | (16.64) | | | $ | (10.79) | |
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(1) Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
Oil prices continued to increase during the first quarter of 2022, compared with 2021. However, given the uncertainty surrounding the ongoing conflict between Russia and Ukraine, the economic and trade sanctions that certain countries have imposed on Russia, the dynamic nature of the Pandemic, and the potential impacts to global commodity and financial markets, we expect future benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result. In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies. Our realized prices at local sales points may also be affected by infrastructure capacity in the area of our operations and beyond. Please refer to First Quarter 2022 Overview and Outlook for the Remainder of 2022 above for additional discussion of factors impacting pricing.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of April 20, 2022, and March 31, 2022:
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| As of April 20, 2022 | | As of March 31, 2022 |
NYMEX WTI oil (per Bbl) | $ | 96.54 | | | $ | 93.25 | |
NYMEX Henry Hub gas (per MMBtu) | $ | 6.89 | | | $ | 5.72 | |
OPIS NGLs (per Bbl) | $ | 47.89 | | | $ | 47.30 | |
We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain of our senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.
Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months ended March 31, 2022, and the preceding three quarters:
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| For the Three Months Ended |
| March 31, | | December 31, | | September 30, | | June 30, |
| 2022 | | 2021 | | 2021 | | 2021 |
| | | | | | | |
| (in millions) |
Production (MMBOE) | 13.8 | | | 14.6 | | | 14.3 | | | 12.4 | |
Oil, gas, and NGL production revenue | $ | 858.7 | | | $ | 852.4 | | | $ | 759.8 | | | $ | 562.6 | |
Oil, gas, and NGL production expense | $ | 144.7 | | | $ | 143.3 | | | $ | 135.7 | | | $ | 125.5 | |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 159.5 | | | $ | 200.0 | | | $ | 202.7 | | | $ | 204.7 | |
Exploration | $ | 9.0 | | | $ | 12.6 | | | $ | 8.7 | | | $ | 8.7 | |
General and administrative | $ | 25.0 | | | $ | 37.1 | | | $ | 25.5 | | | $ | 24.6 | |
Net income (loss) | $ | 48.8 | | | $ | 424.9 | | | $ | 85.6 | | | $ | (223.0) | |
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Note: Amounts may not calculate due to rounding.
Selected Performance Metrics
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| For the Three Months Ended |
| March 31, | | December 31, | | September 30, | | June 30, |
| 2022 | | 2021 | | 2021 | | 2021 |
Average net daily equivalent production (MBOE per day) | 153.3 | | | 158.3 | | | 155.8 | | | 136.5 | |
Lease operating expense (per BOE) | $ | 4.25 | | | $ | 4.21 | | | $ | 4.20 | | | $ | 4.62 | |
Transportation costs (per BOE) | $ | 2.74 | | | $ | 2.61 | | | $ | 2.41 | | | $ | 3.01 | |
Production taxes as a percent of oil, gas, and NGL production revenue | 4.7 | % | | 4.8 | % | | 4.7 | % | | 4.5 | % |
Ad valorem tax expense (per BOE) | $ | 0.58 | | | $ | 0.22 | | | $ | 0.38 | | | $ | 0.45 | |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) | $ | 11.56 | | | $ | 13.74 | | | $ | 14.14 | | | $ | 16.48 | |
General and administrative (per BOE) | $ | 1.81 | | | $ | 2.55 | | | $ | 1.78 | | | $ | 1.98 | |
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Note: Amounts may not calculate due to rounding.
Overview of Selected Production and Financial Information, Including Trends | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | For the Three Months Ended | | Amount Change Between the Three Months Ended | | Percent Change Between the Three Months Ended |
| | | | | | March 31, 2022 | | December 31, 2021 | | March 31, 2021 | | March 31, 2022 & December 31, 2021 | | March 31, 2022 & 2021 | | March 31, 2022 & December 31, 2021 | | March 31, 2022 & 2021 |
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Net production volumes: (1) | | | | | | | | | | | | | | | | | | | | | |
Oil (MMBbl) | | | | | | | | | 6.5 | | | 7.8 | | | 5.4 | | | (1.3) | | | 1.0 | | | (17) | % | | 19 | % |
Gas (Bcf) | | | | | | | | | 31.4 | | | 31.3 | | | 21.5 | | | 0.1 | | | 9.8 | | | — | % | | 46 | % |
NGLs (MMBbl) | | | | | | | | | 2.1 | | | 1.6 | | | 1.0 | | | 0.5 | | | 1.1 | | | 34 | % | | 105 | % |
Equivalent (MMBOE) | | | | | | | | | 13.8 | | | 14.6 | | | 10.0 | | | (0.8) | | | 3.7 | | | (5) | % | | 37 | % |
Average net daily production: (1) | | | | | | | | |
Oil (MBbl per day) | | | | | | | | | 71.8 | | | 84.5 | | | 60.3 | | | (12.7) | | | 11.4 | | | (15) | % | | 19 | % |
Gas (MMcf per day) | | | | | | | | | 348.4 | | | 339.7 | | | 239.4 | | | 8.7 | | | 109.1 | | | 3 | % | | 46 | % |
NGLs (MBbl per day) | | | | | | | | | 23.4 | | | 17.2 | | | 11.4 | | | 6.3 | | | 12.0 | | | 37 | % | | 105 | % |
Equivalent (MBOE per day) | | | | | | | | | 153.3 | | | 158.3 | | | 111.6 | | | (5.0) | | | 41.6 | | | (3) | % | | 37 | % |
Oil, gas, and NGL production revenue (in millions): (1) | | | | | | | | |
Oil production revenue | | | | | | | | | $ | 607.3 | | | $ | 591.3 | | | $ | 305.8 | | | $ | 16.0 | | | $ | 301.5 | | | 3 | % | | 99 | % |
Gas production revenue | | | | | | | | | 170.0 | | | 198.5 | | | 89.7 | | | (28.5) | | | 80.4 | | | (14) | % | | 90 | % |
NGL production revenue | | | | | | | | | 81.4 | | | 62.6 | | | 27.7 | | | 18.8 | | | 53.6 | | | 30 | % | | 193 | % |
Total oil, gas, and NGL production revenue | | | | | | | | | $ | 858.7 | | | $ | 852.4 | | | $ | 423.2 | | | $ | 6.4 | | | $ | 435.6 | | | 1 | % | | 103 | % |
Oil, gas, and NGL production expense (in millions): (1) | | | | | | | | |
Lease operating expense | | | | | | | | | $ | 58.6 | | | $ | 61.3 | | | $ | 46.7 | | | $ | (2.8) | | | $ | 11.9 | | | (5) | % | | 26 | % |
Transportation costs | | | | | | | | | 37.7 | | | 38.1 | | | 29.6 | | | (0.3) | | | 8.2 | | | (1) | % | | 28 | % |
Production taxes | | | | | | | | | 40.4 | | | 40.7 | | | 19.5 | | | (0.3) | | | 20.9 | | | (1) | % | | 107 | % |
Ad valorem tax expense | | | | | | | | | 8.0 | | | 3.2 | | | 5.2 | | | 4.8 | | | 2.8 | | | 150 | % | | 53 | % |
Total oil, gas, and NGL production expense | | | | | | | | | $ | 144.7 | | | $ | 143.3 | | | $ | 100.9 | | | $ | 1.4 | | | $ | 43.8 | | | 1 | % | | 43 | % |
Realized price: | | | | | | | | |
Oil (per Bbl) | | | | | | | | | $ | 94.03 | | | $ | 76.08 | | | $ | 56.33 | | | $ | 17.95 | | | $ | 37.70 | | | 24 | % | | 67 | % |
Gas (per Mcf) | | | | | | | | | $ | 5.42 | | | $ | 6.35 | | | $ | 4.16 | | | $ | (0.93) | | | $ | 1.26 | | | (15) | % | | 30 | % |
NGLs (per Bbl) | | | | | | | | | $ | 38.56 | | | $ | 39.63 | | | $ | 26.93 | | | $ | (1.07) | | | $ | 11.63 | | | (3) | % | | 43 | % |
Per BOE | | | | | | | | | $ | 62.25 | | | $ | 58.54 | | | $ | 42.11 | | | $ | 3.71 | | | $ | 20.14 | | | 6 | % | | 48 | % |
Per BOE data: (1) | | | | | | | | | | | | | | | | | | | | | |
Oil, gas, and NGL production expense: | | | | | | | | | | | | |
Lease operating expense | | | | | | | | | $ | 4.25 | | | $ | 4.21 | | | $ | 4.64 | | | $ | 0.04 | | | $ | (0.39) | | | 1 | % | | (8) | % |
Transportation costs | | | | | | | | | 2.74 | | | 2.61 | | | 2.94 | | | 0.13 | | | (0.20) | | | 5 | % | | (7) | % |
Production taxes | | | | | | | | | 2.93 | | | 2.80 | | | 1.94 | | | 0.13 | | | 0.99 | | | 5 | % | | 51 | % |
Ad valorem tax expense | | | | | | | | | 0.58 | | | 0.22 | | | 0.52 | | | 0.36 | | | 0.06 | | | 164 | % | | 12 | % |
Total oil, gas, and NGL production expense | | | | | | | | | $ | 10.49 | | | $ | 9.84 | | | $ | 10.04 | | | $ | 0.65 | | | $ | 0.45 | | | 7 | % | | 4 | % |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | | | | | | | | | $ | 11.56 | | | $ | 13.74 | | | $ | 16.62 | | | $ | (2.18) | | | $ | (5.06) | | | (16) | % | | (30) | % |
General and administrative | | | | | | | | | $ | 1.81 | | | $ | 2.55 | | | $ | 2.46 | | | $ | (0.74) | | | $ | (0.65) | | | (29) | % | | (26) | % |
Derivative settlement loss (2) | | | | | | | | | $ | (12.19) | | | $ | (18.45) | | | $ | (10.74) | | | $ | 6.26 | | | $ | (1.45) | | | 34 | % | | (14) | % |
Earnings per share information (in thousands, except per share data): (3) | | | | | | | | |
Basic weighted-average common shares outstanding | | | | | | | | | 121,907 | | | 121,535 | | | 114,759 | | | 372 | | | 7,148 | | | — | % | | 6 | % |
Diluted weighted-average common shares outstanding | | | | | | | | | 124,179 | | | 124,019 | | | 114,759 | | | 160 | | | 9,420 | | | — | % | | 8 | % |
Basic net income (loss) per common share | | | | | | | | | $ | 0.40 | | | $ | 3.50 | | | $ | (2.19) | | | $ | (3.10) | | | $ | 2.59 | | | (89) | % | | 118 | % |
Diluted net income (loss) per common share | | | | | | | | | $ | 0.39 | | | $ | 3.43 | | | $ | (2.19) | | | $ | (3.04) | | | $ | 2.58 | | | (89) | % | | 118 | % |
______________________________________
(1) Amounts and percentage changes may not calculate due to rounding.
(2) Derivative settlements for the three months ended March 31, 2022, and 2021, are included within the net derivative loss line item in the accompanying statements of operations.
(3) Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.
Average net daily equivalent production for the three months ended March 31, 2022, decreased three percent sequentially consisting of a 15 percent decrease from our Midland Basin assets due to the timing of well completions, partially offset by an 18 percent increase from our South Texas assets. Average net daily equivalent production for the three months ended March 31, 2022, increased 37 percent compared with the same period in 2021, consisting of an increase of 85 percent from our South Texas assets as a result of increased capital allocation to our Austin Chalk assets and strong well performance, and an increase of 15 percent from our Midland Basin assets as a result of strong well performance. Average net daily equivalent production for the three months ended March 31, 2021, was negatively impacted by a significant cold weather event in the state of Texas which resulted in reduced production for approximately 14 days in February 2021.
We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.
Our realized price on a per BOE basis increased $3.71 sequentially as a result of strengthening benchmark oil prices. The loss on the settlement of our derivative contracts decreased $6.26 per BOE as a result of a lower percentage of volumes covered by commodity derivative contracts settled during the first quarter of 2022, compared with the fourth quarter of 2021. Our realized price on a per BOE basis increased $20.14 YTD 2022-over-YTD 2021, primarily as a result of higher benchmark commodity prices, which increased throughout 2021 in response to global macroeconomic events. The positive impact on oil, gas, and NGL production revenues resulting from the YTD 2022-over-YTD 2021 realized price increase was slightly offset by an increase in the loss on the settlement of our derivative contracts of $1.45 per BOE.
LOE on a per BOE basis remained flat sequentially and decreased eight percent YTD 2022-over-YTD 2021. The YTD 2022-over-YTD 2021 decrease was driven by the decreased percentage of oil in our total product mix, which has higher lifting costs per BOE. For the full year 2022, we expect LOE on a per BOE basis to slightly increase, compared with 2021, due to anticipated increases in service provider costs and workover activity, which we expect to be partially offset by increasing activity in the Austin Chalk. We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, and industry activity, all of which impact total LOE.
Transportation costs on a per BOE basis increased five percent sequentially and decreased seven percent YTD 2022-over-YTD 2021. The sequential quarterly increase was the result of a 16 percent increase in net equivalent production volumes from our South Texas assets, which incur the majority of our transportation costs. The YTD 2022-over-YTD 2021 decrease was the result of increased net equivalent production volumes outpacing increased transportation expense on an absolute basis as we benefited from transportation contract cost reductions during the second half of 2021. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets. For the full year 2022, we expect transportation costs on a per BOE basis to increase compared with 2021.
Production tax expense on a per BOE basis increased five percent sequentially, and 51 percent YTD 2022-over-YTD 2021, primarily driven by increases in realized prices. Our overall production tax rate for the three months ended March 31, 2022, was 4.7 percent compared with 4.8 percent and 4.6 percent for the three months ended December 31, 2021, and March 31, 2021, respectively. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.
Ad valorem tax expense on a per BOE basis increased 164 percent sequentially and 12 percent YTD 2022-over-YTD 2021 as a result of changes to the expected value assessments of our producing properties, which are driven by increases in commodity prices. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis decreased 16 percent sequentially and 30 percent YTD 2022-over-YTD 2021 as a result of increased estimated proved reserves and increased activity in our Austin Chalk program, which has lower DD&A rates compared with our Midland Basin assets. Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes. We expect DD&A expense per BOE and DD&A expense on an absolute basis to decrease in 2022, compared with 2021, primarily as a result of increased estimated proved reserves and increased activity in our Austin Chalk program, as these assets have a lower DD&A rate than our Midland Basin assets.
General and administrative (“G&A”) expense on a per BOE basis decreased 29 percent sequentially as a result of decreased compensation expense. G&A expense recorded during the three months ended December 31, 2021, reflected an increase to full-year 2021 compensation expense resulting from the Company’s full-year performance against performance targets established at the
beginning of the year. G&A expense on a per BOE basis decreased 26 percent YTD 2022-over-YTD 2021 as a result of a 37 percent increase in net equivalent production volumes. Despite inflationary pressures, for the full year 2022 we currently expect G&A expense to slightly decrease on an absolute basis and to decrease on a per BOE basis, compared with 2021.
Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021 below for additional discussion on operating expenses.
Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021
Average net daily equivalent production, production revenue, and production expense
Sequential Quarterly Changes. The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the three months ended March 31, 2022, and December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Net Equivalent Production Increase (Decrease) | | Production Revenue Increase (Decrease) | | Production Expense Increase (Decrease) |
| | | | | | | | | | | |
| (MBOE per day) | | (in millions) | | (in millions) |
Midland Basin | (15.1) | | | | | $ | (34.8) | | | | | $ | (2.6) | | | |
South Texas | 10.2 | | | | | 41.1 | | | | | 4.0 | | | |
Total | (5.0) | | | | | $ | 6.4 | | | | | $ | 1.4 | | | |
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes decreased three percent, consisting of a 15 percent decrease from our Midland Basin assets, partially offset by an 18 percent increase from our South Texas assets. Our realized oil price increased 24 percent, while our realized gas and NGL prices decreased 15 percent and three percent, respectively. The six percent increase in total realized price per BOE was mostly offset by the decrease in average net daily equivalent production volumes, resulting in a slight increase in oil, gas, and NGL production revenue. Total production expense remained flat.
YTD 2022-over-YTD 2021. The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the three months ended March 31, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Net Equivalent Production Increase | | Production Revenue Increase | | Production Expense Increase |
| | | | | | | | | | | |
| (MBOE per day) | | (in millions) | | (in millions) |
Midland Basin | 11.3 | | | | | $ | 252.3 | | | | | $ | 23.7 | | | |
South Texas | 30.3 | | | | | 183.2 | | | | | 20.1 | | | |
Total | 41.6 | | | | | $ | 435.6 | | | | | $ | 43.8 | | | |
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes increased 37 percent, consisting of increases of 85 percent and 15 percent from our South Texas assets and our Midland Basin assets, respectively. Realized prices for oil, gas, and NGLs increased 67 percent, 30 percent, and 43 percent, respectively. As a result of increases in benchmark commodity prices and an increase in production volumes, oil, gas, and NGL production revenue increased 103 percent. Total production expense increased 43 percent, primarily as a result of increased production taxes and LOE.
Please refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | March 31, 2021 | | | | |
| | | | | | | | | |
| (in millions) |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 159.5 | | | $ | 200.0 | | | $ | 167.0 | | | | | |
DD&A expense decreased 20 percent sequentially and four percent YTD 2022-over-YTD 2021. These decreases were driven by increased estimated proved reserves and increased activity in our Austin Chalk program, which has lower DD&A rates compared with our Midland Basin assets. Please refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion of DD&A expense on a per BOE basis.
Exploration
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | March 31, 2021 | | | | |
| | | | | | | | | |
| (in millions) |
Geological and geophysical expenses | $ | — | | | $ | 0.2 | | | $ | 0.3 | | | | | |
Overhead and other expenses | 9.0 | | | 12.4 | | | 9.0 | | | | | |
Total | $ | 9.0 | | | $ | 12.6 | | | $ | 9.3 | | | | | |
Exploration expense decreased 28 percent sequentially and three percent YTD 2022-over-YTD 2021. The sequential quarterly decrease was primarily a result of decreases in overhead and other expenses. Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and unsuccessful exploration activities, if any.
Impairment
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | March 31, 2021 | | | | |
| | | | | | | | | |
| (in millions) |
| | | | | | | | | |
| | | | | | | | | |
Impairment | $ | 1.0 | | | $ | 8.8 | | | $ | 8.8 | | | | | |
Impairment expense recorded during the periods presented consists entirely of unproved property abandonments and impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks. Impairment expense decreased both sequentially and YTD 2022-over-YTD 2021, as a result of fewer actual and anticipated lease expirations and title defects.
We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or title defects, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments.
Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as of April 20, 2022, we do not expect any material oil and gas property impairments in the second quarter of 2022 resulting from commodity price impacts. We expect abandonment and impairment expense related to unproved properties to decrease for the full year 2022 compared with 2021.
Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion of impairment expense.
General and administrative
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | March 31, 2021 | | | | |
| | | | | | | | | |
| (in millions) |
General and administrative | $ | 25.0 | | | $ | 37.1 | | | $ | 24.7 | | | | | |
G&A expense decreased 33 percent sequentially and remained flat YTD 2022-over-YTD 2021. G&A expense recorded during the three months ended December 31, 2021, reflected an increase to full-year 2021 compensation expense resulting from the Company’s full-year performance against performance targets established at the beginning of the year. Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for additional discussion of G&A expense in total and on a per BOE basis.
Net derivative (gain) loss
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | March 31, 2021 | | | | |
| | | | | | | | | |
| (in millions) |
Net derivative (gain) loss | $ | 418.5 | | | $ | (22.5) | | | $ | 344.7 | | | | | |
Net derivative (gain) loss is a result of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. The net derivative losses for the three months ended March 31, 2022, and 2021, resulted from increases in benchmark commodity prices. The net derivative gain for the three months ended December 31, 2021, was the result of decreases in the forward price curves for gas and NGLs, partially offset by an increase in the forward price curve for oil. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.
Interest expense
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | March 31, 2021 | | | | |
| | | | | | | | | |
| (in millions) |
Interest expense | $ | (39.4) | | | $ | (40.1) | | | $ | (39.9) | | | | | |
Interest expense remained relatively flat for the periods presented. We expect interest expense related to our Senior Notes to continue to decrease during 2022 compared with 2021 primarily as a result of the reduction in aggregate principal amount of Senior Notes through various transactions in 2021 and 2022, including the redemption of our 2024 Senior Notes on February 14, 2022, and the announced redemption of our 2025 Senior Secured Notes, which will be redeemed on June 17, 2022. Total interest expense is impacted by, and can vary based on, the timing and amount of borrowings under our revolving credit facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report and Overview of Liquidity and Capital Resources below for additional discussion.
Income tax expense
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | March 31, 2021 | | | | |
| | | | | | | | | |
| (in millions, except tax rate) |
Income tax expense | $ | (12.9) | | | $ | (10.0) | | | $ | (0.1) | | | | | |
Effective tax rate | 20.9 | % | | 2.3 | % | | — | % | | | | |
The sequential quarterly increase in the effective tax rate was primarily due to the effect of increased forecasted net income for the full-year 2022, compared with 2021. Additionally, as a result of commodity price increases discussed in Overview of the Company above, we anticipate that a significant portion of the valuation allowance recorded against the derivative deferred tax asset as of December 31, 2021, could be reversed during 2022. The effect of this anticipated reversal is included in the effective tax rate for the three months ended March 31, 2022. Please refer to Note 4 - Income Taxes included in Part II, Item 8 of our 2021 Form 10-K for discussion of the valuation allowance recorded as of December 31, 2021. The YTD 2022-over-YTD 2021 increase in the effective tax rate was primarily due to the effect of higher full-year 2022 forecasted net income as of March 31, 2022, compared with the amount of forecasted net income for the full-year 2021 as of March 31, 2021.
The tax rates for each period presented reflect the effect of valuation allowance adjustments against the statutory rate, the proportional effects of excess tax deficiencies from stock-based compensation awards, and limits on expensing of certain covered individual’s compensation. Based on current projections, we estimate that between six percent and eight percent of full-year 2022 income tax expense will be current.
Changes in federal income tax laws or enactment of proposed legislation to increase the corporate tax rate and eliminate or reduce certain oil and gas industry deductions could have a material impact on our effective tax rate and current tax expense. Please refer to the Risk Factors section in Part I, Item 1A of our 2021 Form 10-K for additional discussion. Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.
Overview of Liquidity and Capital Resources
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our current financial obligations. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.
Sources of Cash
For the three months ended March 31, 2022, our capital program was funded with cash flows from operating activities and we expect that to continue for the remainder of 2022. Although we expect cash flows from operations to be sufficient to fund our expected 2022 capital program, we may also use borrowings under our revolving credit facility or raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, tax law changes, and volumes produced, all of which affect us and our industry.
Our credit ratings impact the availability of and cost for us to borrow additional funds. Three major credit rating agencies have upgraded our credit ratings during 2022, reflecting our top-tier assets and operational performance, the redemption of our 2024 Senior Notes, and our strong liquidity profile, among other factors. The credit rating agencies also cited our priorities of continuing to reduce debt and improve our leverage metrics, and our expected ability to generate meaningful cash flows, among other reasons for the rating upgrades.
We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of settlement of those contracts.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, and a borrowing base and aggregate lender commitments of $1.1 billion. The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each as determined by our lender group. Subsequent to March 31, 2022, the semi-annual borrowing base redetermination was completed, which reaffirmed both our borrowing base and aggregate lender commitments at $1.1 billion. The next borrowing base redetermination date is scheduled for October 1, 2022. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities, all as provided for in the Credit Agreement. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion, as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under our Credit Agreement as of April 20, 2022, March 31, 2022, and December 31, 2021.
We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. We were in compliance with all financial and non-financial covenants as of March 31, 2022, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
We had no revolving credit facility borrowings during the three months ended March 31, 2022, due to our cash and cash equivalents balance resulting from cash flows from operating activities exceeding cash flows from investing and financing activities. Our daily weighted-average revolving credit facility debt balance for the three months ended December 31, 2021, and March 31, 2021, was $21.0 million and $134.2 million, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, repayment of scheduled debt maturities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.
Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue interest based on LIBOR which was discontinued as a global reference rate for new loans and contracts after December 31, 2021. Our Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. In advance of the maturity date of our existing Credit Agreement, we expect to enter into a new credit agreement during 2022 that will, in addition to other negotiated terms, conditions, agreements, and other provisions, specify a new interest rate for Eurodollar loans. We currently do not expect to incur borrowings in the form of Eurodollar
loans prior to that time, and we currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business.
Weighted-Average Interest and Weighted-Average Borrowing Rates
Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, the non-cash amortization of the discount related to the 2025 Senior Secured Notes, and for the three months ended March 31, 2021, the non-cash amortization of the discount related to the 1.50% 2021 Senior Secured Convertible Notes due July 1, 2021 (“2021 Senior Secured Convertible Notes”). Our weighted-average borrowing rate includes paid and accrued interest only.
The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the periods presented:
| | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended |
| March 31, 2022 | | December 31, 2021 | | | | March 31, 2021 |
Weighted-average interest rate | 8.2 | % | | 7.9 | % | | | | 7.7 | % |
Weighted-average borrowing rate | 7.2 | % | | 7.0 | % | | | | 6.7 | % |
Our weighted-average interest rates and our weighted-average borrowing rates increased both sequentially and YTD 2022-over-YTD 2021, as the remaining Senior Notes outstanding as of March 31, 2022 have higher interest rates than the Senior Notes redeemed during 2021 and during the first quarter of 2022.
Our weighted-average interest rate and weighted-average borrowing rate are impacted by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rates are impacted by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the acceleration of unamortized deferred financing costs, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2021 Senior Secured Convertible Notes were retired upon maturity on July 1, 2021. After this date, the weighted-average interest rate was no longer impacted by the non-cash amortization of deferred financing costs or the non-cash amortization of the discount related to the 2021 Senior Secured Convertible Notes.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During the three months ended March 31, 2022, we spent approximately $150.1 million on capital expenditures. This amount differs from the costs incurred amount of $175.1 million for the three months ended March 31, 2022, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.
The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. Our 2022 capital program is expected to be approximately $750.0 million. We will continue to monitor the economic environment through the remainder of the year and adjust our activity level as warranted.
We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. On February 14, 2022, we redeemed all of the $104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes. On April 28, 2022, we issued a notice of redemption to the holders of our 2025 Senior Secured Notes notifying such holders that we intend to redeem the $446.7 million aggregate principal amount outstanding of our 2025 Senior Secured Notes on June 17, 2022 (“Redemption Date”). In accordance with the terms of the indenture governing the 2025 Senior Secured Notes, the redemption price will be equal to 107.5 percent of the principal amount of the 2025 Senior Secured Notes on the Redemption Date ($1,075 per $1,000 principal amount outstanding), plus accrued and unpaid interest. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. As part of our strategy for 2022, we continue to focus on reducing absolute debt and improving our debt metrics.
As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing each series of our outstanding Senior Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During the three months ended March 31, 2022, we did not repurchase any shares of our common stock.
Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2022, and 2021
The following tables present changes in cash flows between the three months ended March 31, 2022, and 2021, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report.
Operating activities
| | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, | | Amount Change Between Periods | | |
| 2022 | | 2021 | | |
| | | | | | | |
| (in millions) | | |
Net cash provided by operating activities | $ | 342.1 | | | $ | 105.6 | | | $ | 236.5 | | | |
Net cash provided by operating activities increased for the three months ended March 31, 2022, compared with the same period in 2021, primarily due to a $371.9 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes partially offset by a $104.5 million increase in cash paid on settled derivative trades. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.
Investing activities
| | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, | | Amount Change Between Periods | | |
| 2022 | | 2021 | | |
| | | | | | | |
| (in millions) | | |
Net cash used in investing activities | $ | (150.1) | | | $ | (147.6) | | | $ | (2.5) | | | |
Net cash used in investing activities slightly increased for the three months ended March 31, 2022, compared with the same period in 2021, primarily due to increased capital expenditures of $2.6 million.
Financing activities
| | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, | | Amount Change Between Periods | | |
| 2022 | | 2021 | | |
| | | | | | | |
| (in millions) | | |
Net cash provided by (used in) financing activities | $ | (104.8) | | | $ | 42.0 | | | $ | (146.8) | | | |
During the three months ended March 31, 2022, we redeemed the $104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes using cash on hand.
For the three months ended March 31, 2021, net borrowings under our revolving credit facility increased $42.0 million.
Interest Rate Risk
We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of March 31, 2022, we had no outstanding balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Unsecured Notes or fixed-rate Senior Secured Notes, but can impact their fair values. As of March 31, 2022, our outstanding principal amount of fixed-rate debt totaled $2.0 billion and we had no floating-rate debt outstanding. Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.
Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, profitability, access to capital, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last several years. Oil prices continued to increase during the first quarter of 2022. However, commodity prices remain subject to heightened levels of uncertainty and volatility related to the ongoing conflict between Russia and Ukraine, the economic and trade sanctions that certain countries have imposed on Russia, the dynamic nature of the Pandemic, and the potential impacts to global commodity and financial markets. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our production for the three months ended March 31, 2022, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $60.7 million, $17.0 million, and $8.1 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the three months ended March 31, 2022, would have offset the declines in oil, gas, and NGL production revenue by approximately $38.0 million.
We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of March 31, 2022, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $144.3 million, $18.5 million, and $5.9 million, respectively.
Off-Balance Sheet Arrangements
We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.
We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the three months ended March 31, 2022, or through the filing of this report.
Critical Accounting Policies and Estimates
Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2021 Form 10-K for discussion of our accounting policies and estimates. Accounting Matters
Please refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for information on new authoritative accounting guidance.
Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in the 2021 Form 10-K. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default. The following table provides reconciliations of our net income (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:
| | | | | | | | | | | | | | | | | |
| | | For the Three Months Ended March 31, |
| | | | | 2022 | | | | 2021 |
| | | | | | | | | |
| | | | | (in thousands) |
Net income (loss) (GAAP) | | | | | $ | 48,764 | | | | | $ | (251,269) | |
Interest expense | | | | | 39,387 | | | | | 39,871 | |
Income tax expense | | | | | 12,861 | | | | | 106 | |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | | | | | 159,481 | | | | | 166,960 | |
Exploration (1) | | | | | 8,055 | | | | | 8,039 | |
Impairment | | | | | 1,000 | | | | | 8,750 | |
Stock-based compensation expense | | | | | 4,274 | | | | | 5,737 | |
Net derivative loss | | | | | 418,521 | | | | | 344,689 | |
Derivative settlement loss | | | | | (168,183) | | | | | (107,885) | |
| | | | | | | | | |
| | | | | | | | | |
Other, net | | | | | 404 | | | | | (10) | |
Adjusted EBITDAX (non-GAAP) | | | | | 524,564 | | | | | 214,988 | |
Interest expense | | | | | (39,387) | | | | | (39,871) | |
Income tax expense | | | | | (12,861) | | | | | (106) | |
Exploration (1) | | | | | (8,055) | | | | | (8,039) | |
Amortization of debt discount and deferred financing costs | | | | | 4,010 | | | | | 4,723 | |
Deferred income taxes | | | | | 11,948 | | | | | (52) | |
Other, net | | | | | (165) | | | | | (14,582) | |
Net change in working capital | | | | | (137,962) | | | | | (51,437) | |
Net cash provided by operating activities (GAAP) | | | | | $ | 342,092 | | | | | $ | 105,624 | |
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(1) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.