filings.toolsItem 2. . Management’s Discussion and Analysis of Financial Condition and Results of Operations
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Item 2. . Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis addresses material changes in our results of operations for the three-month period ended March 31, 2022 compared to previous periods and in our financial condition and liquidity since December 31, 2021. For information regarding our critical accounting policies and estimates, see our 2021 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Executive Over****view
The Merger has helped us become a leading unconventional oil producer in the U.S., with an asset base underpinned by premium acreage in the economic core of the Delaware Basin. This strategic combination accelerated our transition to a cash-return business model, including the implementation of a fixed plus variable dividend strategy. We remain focused on building economic value by executing on our strategic priorities of moderating growth, emphasizing capital efficiencies, maintaining and improving operational and corporate synergies, reducing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. Our recent performance highlights for these priorities include the following items:
First quarter oil production totaled 288 MBbls/d, exceeding our plan by 1%.
As of March 31, 2022, have completed approximately 40% of our authorized $2.0 billion share repurchase program, with approximately 4.0 million of our common shares repurchased in the first quarter of 2022 for approximately $230 million, or $57.74 per share.
Exited the first quarter with $5.6 billion of liquidity, including $2.6 billion of cash, with no debt maturities until the third quarter of 2023.
Generated $1.8 billion of operating cash flow in the first quarter of 2022.
Including variable dividends, paid dividends of approximately $667 million in the first quarter of 2022 and have declared $838 million of dividends to be paid in the second quarter of 2022.
We remain committed to capital discipline and delivering the objectives that underpin our current plan. Those objectives prioritize value creation through moderated capital investment and production growth, particularly with a view of the steep backwardation in commodity prices, supply chain constraints and the economic uncertainty arising from recent geopolitical events.
Commodity prices strengthened throughout 2021 and oil prices continued to increase in the first quarter of 2022, which has significantly improved our earnings and cash flow generation. The increase in commodity prices during 2021 was primarily driven by increased demand resulting from the initial recovery from the COVID-19 pandemic, as well as OPEC+ and other oil and natural gas producers not rapidly increasing production levels. The military conflict between Russia and Ukraine and related economic sanctions imposed on Russia has further exacerbated supply shortages, causing oil prices to increase even more during the first quarter of 2022.
Trends of our quarterly earnings, operating cash flow, EBITDAX and capital expenditures are shown below. “Core earnings” and “EBITDAX” are financial measures not prepared in accordance with GAAP. For a description of these measures, including reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.
Our earnings decreased from the fourth quarter of 2021 to the first quarter of 2022 primarily due to non-cash adjustments related to the value of commodity hedges, lower sold volumes resulting from natural declines and winter weather downtime and lower gas prices. Henry Hub decreased 15% from the fourth quarter of 2021 to the first quarter of 2022. These decreases were partially offset by a 23% increase in WTI from the fourth quarter of 2021 to the first quarter of 2022 which contributed to a 16% increase in our unhedged combined realized prices.
Our net earnings in recent quarters have been significantly impacted by non-cash adjustments to the value of our commodity hedges. Net earnings in the first quarter of 2021, the second quarter of 2021 and the first quarter of 2022 each included a hedge valuation loss, net of tax of $0.2 billion, $0.3 billion and $0.3 billion, respectively. Net earnings in the fourth quarter of 2021 included a hedge valuation gain, net of tax of $0.4 billion. Excluding these amounts, our core earnings have been more stable over recent quarters and continue to trend upward while remaining sensitive to volatile commodity prices.
Like earnings, our operating cash flow is sensitive to volatile commodity prices. Our cash flow and EBITDAX have continued to trend upward primarily due to improved commodity prices and overall market conditions as well as strong operating performance. However, volumes were down slightly in the first quarter of 2022 primarily due to natural declines across the asset portfolio as well as downtime related to winter weather which negatively impacted earnings.
We exited the first quarter of 2022 with $5.6 billion of liquidity, comprised of $2.6 billion of cash and $3.0 billion of available credit under our Senior Credit Facility. We currently have $6.5 billion of debt outstanding with no maturities until August 2023. We currently have approximately 25% and 35% of our anticipated 2022 oil and gas production hedged, respectively. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub and NYMEX last day natural gas indices. Additionally, we have entered into regional basis swaps in an effort to protect price realizations across our portfolio.
As commodity prices and our operating performance strengthen and bolster our financial condition, we have authorized opportunistic repurchases of up to $2.0 billion of our common shares with an expiration date of May 4, 2023. We repurchased approximately 4.0 million shares in the first quarter of 2022 for approximately $230 million, or $57.74 per share. As of March 31, 2022, we have repurchased approximately 18 million shares for approximately $819 million, or $45.61 per share, since the inception of the program. Additionally, we continue funding our fixed plus variable dividends, which totaled $667 million in the first quarter of 2022. We recently declared a dividend payable in the second quarter of 2022 for $838 million.
Res****ults of Operations
The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. To facilitate the review, these numbers are being presented before consideration of noncontrolling interests.
Q1 2022 vs. Q4 2021
Our first quarter 2022 net earnings were $995 million, compared to net earnings of $1.5 billion for the fourth quarter of 2021. The graph below shows the change in net earnings from the fourth quarter of 2021 to the first quarter of 2022. The material changes are further discussed by category on the following pages.
Production Volumes
| Q1 2022 | % of Total | Q4 2021 | Change | |||||||||||||
| Oil (MBbls/d) | ||||||||||||||||
| Delaware Basin | 209 | 73 | % | 213 | -2 | % | ||||||||||
| Anadarko Basin | 14 | 5 | % | 14 | 2 | % | ||||||||||
| Williston Basin | 32 | 11 | % | 36 | -12 | % | ||||||||||
| Eagle Ford | 17 | 6 | % | 19 | -11 | % | ||||||||||
| Powder River Basin | 12 | 4 | % | 14 | -9 | % | ||||||||||
| Other | 4 | 1 | % | 4 | -9 | % | ||||||||||
| Total | 288 | 100 | % | 300 | -4 | % |
| Q1 2022 | % of Total | Q4 2021 | Change | |||||||||||||
| Gas (MMcf/d) | ||||||||||||||||
| Delaware Basin | 561 | 62 | % | 577 | -3 | % | ||||||||||
| Anadarko Basin | 210 | 23 | % | 222 | -5 | % | ||||||||||
| Williston Basin | 54 | 6 | % | 64 | -15 | % | ||||||||||
| Eagle Ford | 61 | 7 | % | 60 | 3 | % | ||||||||||
| Powder River Basin | 19 | 2 | % | 19 | -3 | % | ||||||||||
| Other | 1 | 0 | % | 1 | -4 | % | ||||||||||
| Total | 906 | 100 | % | 943 | -4 | % |
| Q1 2022 | % of Total | Q4 2021 | Change | |||||||||||||
| NGLs (MBbls/d) | ||||||||||||||||
| Delaware Basin | 92 | 67 | % | 107 | -14 | % | ||||||||||
| Anadarko Basin | 25 | 19 | % | 27 | -4 | % | ||||||||||
| Williston Basin | 8 | 6 | % | 9 | -16 | % | ||||||||||
| Eagle Ford | 9 | 6 | % | 9 | -1 | % | ||||||||||
| Powder River Basin | 2 | 2 | % | 2 | -10 | % | ||||||||||
| Other | — | 0 | % | — | N/M | |||||||||||
| Total | 136 | 100 | % | 154 | -12 | % |
| Q1 2022 | % of Total | Q4 2021 | Change | |||||||||||||
| Combined (MBoe/d) | ||||||||||||||||
| Delaware Basin | 394 | 69 | % | 416 | -5 | % | ||||||||||
| Anadarko Basin | 75 | 13 | % | 78 | -4 | % | ||||||||||
| Williston Basin | 48 | 8 | % | 55 | -13 | % | ||||||||||
| Eagle Ford | 36 | 6 | % | 38 | -5 | % | ||||||||||
| Powder River Basin | 18 | 3 | % | 19 | -7 | % | ||||||||||
| Other | 4 | 1 | % | 5 | -11 | % | ||||||||||
| Total | 575 | 100 | % | 611 | -6 | % |
From the fourth quarter of 2021 to the first quarter of 2022, the change in volumes contributed to a $220 million decrease in earnings. The decrease in volumes was primarily due to natural declines across the asset portfolio as well as downtime in the Delaware Basin and Williston Basin related to winter weather.
Realized Prices
| Q1 2022 | Realization | Q4 2021 | Change | |||||||||||
| Oil (per Bbl) | ||||||||||||||
| WTI index | $ | 94.45 | $ | 76.91 | 23 | % | ||||||||
| Realized price, unhedged | $ | 92.94 | 98% | $ | 75.36 | 23 | % | |||||||
| Cash settlements | $ | (11.32 | ) | $ | (13.14 | ) | ||||||||
| Realized price, with hedges | $ | 81.62 | 86% | $ | 62.22 | 31 | % |
| Q1 2022 | Realization | Q4 2021 | Change | |||||||||||
| Gas (per Mcf) | ||||||||||||||
| Henry Hub index | $ | 4.96 | $ | 5.84 | -15 | % | ||||||||
| Realized price, unhedged | $ | 3.77 | 76% | $ | 4.68 | -19 | % | |||||||
| Cash settlements | $ | (0.62 | ) | $ | (1.42 | ) | ||||||||
| Realized price, with hedges | $ | 3.15 | 64% | $ | 3.26 | -3 | % |
| Q1 2022 | Realization | Q4 2021 | Change | |||||||||||
| NGLs (per Bbl) | ||||||||||||||
| WTI index | $ | 94.45 | $ | 76.91 | 23 | % | ||||||||
| Realized price, unhedged | $ | 37.76 | 40% | $ | 35.36 | 7 | % | |||||||
| Cash settlements | $ | — | $ | (0.54 | ) | |||||||||
| Realized price, with hedges | $ | 37.76 | 40% | $ | 34.82 | 8 | % |
| Q1 2022 | Q4 2021 | Change | ||||||||||
| Combined (per Boe) | ||||||||||||
| Realized price, unhedged | $ | 61.40 | $ | 53.12 | 16 | % | ||||||
| Cash settlements | $ | (6.65 | ) | $ | (8.78 | ) | ||||||
| Realized price, with hedges | $ | 54.75 | $ | 44.34 | 23 | % |
From the fourth quarter of 2021 to the first quarter of 2022, realized prices contributed to a $410 million increase in earnings. Unhedged realized oil and NGL prices increased primarily due to higher WTI and Mont Belvieu index prices while realized gas prices decreased slightly due to a lower Henry Hub index price. The increase in WTI and Mont Belvieu index prices was partially offset by hedge cash settlements related to oil and gas commodities.
We currently have approximately 25% and 35% of our anticipated 2022 oil and gas production hedged, respectively.
Hedge Settlements
| Q1 2022 | Q4 2021 | Change | ||||||||||
| Q | ||||||||||||
| Oil | $ | (293 | ) | $ | (362 | ) | 19 | % | ||||
| Natural gas | (51 | ) | (123 | ) | 59 | % | ||||||
| NGL | — | (8 | ) | N/M | ||||||||
| Total cash settlements (1) | $ | (344 | ) | $ | (493 | ) | 30 | % |
(1)
Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Production Expenses
| Q1 2022 | Q4 2021 | Change | ||||||||||
| LOE | $ | 224 | $ | 235 | -5 | % | ||||||
| Gathering, processing & transportation | 161 | 173 | -7 | % | ||||||||
| Production taxes | 214 | 197 | 9 | % | ||||||||
| Property taxes | 19 | — | N/M | |||||||||
| Total | $ | 618 | $ | 605 | 2 | % | ||||||
| Per Boe: | ||||||||||||
| LOE | $ | 4.33 | $ | 4.18 | 4 | % | ||||||
| Gathering, processing & transportation | $ | 3.11 | $ | 3.08 | 1 | % | ||||||
| Percent of oil, gas and NGL sales: | ||||||||||||
| Production taxes | 6.7 | % | 6.6 | % | 2 | % |
Production expenses remained relatively flat from the fourth quarter of 2021 to the first quarter of 2022. LOE and gathering, processing and transportation expenses decreased primarily due to lower volumes which was offset by an increase in property taxes and production taxes which resulted from higher commodity prices.
Field-Level Cash Margin
The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL sales less production expenses and is not a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
| Q1 2022 | $ per BOE | Q4 2021 | $ per BOE | |||||||||||||
| Field-level cash margin (Non-GAAP) | ||||||||||||||||
| Delaware Basin | $ | 1,877 | $ | 52.99 | $ | 1,706 | $ | 44.59 | ||||||||
| Anadarko Basin | 204 | $ | 30.31 | 212 | $ | 29.65 | ||||||||||
| Williston Basin | 207 | $ | 47.65 | 209 | $ | 40.95 | ||||||||||
| Eagle Ford | 158 | $ | 48.92 | 149 | $ | 42.70 | ||||||||||
| Powder River Basin | 86 | $ | 54.32 | 80 | $ | 45.61 | ||||||||||
| Other | 25 | $ | 61.96 | 24 | $ | 55.14 | ||||||||||
| Total | $ | 2,557 | $ | 49.45 | $ | 2,380 | $ | 42.37 |
DD&A
| Q1 2022 | Q4 2021 | Change | ||||||||||
| Oil and gas per Boe | $ | 8.95 | $ | 9.79 | -9 | % | ||||||
| Oil and gas | $ | 463 | $ | 550 | -16 | % | ||||||
| Other property and equipment | 26 | 27 | -3 | % | ||||||||
| Total | $ | 489 | $ | 577 | -15 | % |
DD&A decreased in the first quarter of 2022 primarily due to lower DD&A rates compared to 2021. The decrease in DD&A rates was primarily due to increases to oil, gas and NGL reserve estimates at December 31, 2021, resulting from higher prices.
General and Administrative Expense
| Q1 2022 | Q4 2021 | Change | ||||||||||
| G&A per Boe | $ | 1.82 | $ | 1.70 | 7 | % | ||||||
| Labor and benefits | $ | 58 | $ | 58 | 0 | % | ||||||
| Non-labor | 36 | 37 | -3 | % | ||||||||
| Total | $ | 94 | $ | 95 | -1 | % |
The G&A per BOE rate increased in the first quarter of 2022 primarily due to lower volumes resulting from natural declines and winter weather downtime.
Other Items
| Q1 2022 | Q4 2021 | Change in earnings | ||||||||||
| Commodity hedge valuation changes (1) | $ | (339 | ) | $ | 515 | $ | (854 | ) | ||||
| Marketing and midstream operations | (4 | ) | — | (4 | ) | |||||||
| Exploration expenses | 2 | 5 | 3 | |||||||||
| Asset dispositions | (1 | ) | (49 | ) | (48 | ) | ||||||
| Net financing costs | 85 | 86 | 1 | |||||||||
| Restructuring and transaction costs | — | 28 | 28 | |||||||||
| Other, net | (61 | ) | (2 | ) | 59 | |||||||
| $ | (815 | ) |
(1)
Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.
We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Asset dispositions in the fourth quarter of 2021 includes $49 million related to the re-valuation of contingent earnout payments associated with prior divestitures. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
For discussion on other, net, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Income Taxes
| Q1 2022 | Q4 2021 | |||||||
| Current expense | $ | 103 | $ | 1 | ||||
| Deferred expense | 164 | 149 | ||||||
| Total expense | $ | 267 | $ | 150 | ||||
| Effective income tax rate | 21 | % | 9 | % |
For discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Q1 2022 vs. Q1 2021
Our first quarter 2022 net earnings were $995 million, compared to net earnings of $216 million for the first quarter of 2021. The graph below shows the change in net earnings from the first quarter of 2022 to the first quarter of 2021. The material changes are further discussed by category on the following pages.
Production Volumes
| Q1 2022 | % of Total | Q1 2021 | Change | |||||||||||||
| Oil (MBbls/d) | ||||||||||||||||
| Delaware Basin | 209 | 73 | % | 172 | 22 | % | ||||||||||
| Anadarko Basin | 14 | 5 | % | 13 | 11 | % | ||||||||||
| Williston Basin | 32 | 11 | % | 44 | -29 | % | ||||||||||
| Eagle Ford | 17 | 6 | % | 16 | 8 | % | ||||||||||
| Powder River Basin | 12 | 4 | % | 17 | -27 | % | ||||||||||
| Other | 4 | 1 | % | 6 | -38 | % | ||||||||||
| Total | 288 | 100 | % | 268 | 8 | % |
| Q1 2022 | % of Total | Q1 2021 | Change | |||||||||||||
| Gas (MMcf/d) | ||||||||||||||||
| Delaware Basin | 561 | 62 | % | 471 | 19 | % | ||||||||||
| Anadarko Basin | 210 | 23 | % | 200 | 5 | % | ||||||||||
| Williston Basin | 54 | 6 | % | 49 | 10 | % | ||||||||||
| Eagle Ford | 61 | 7 | % | 47 | 31 | % | ||||||||||
| Powder River Basin | 19 | 2 | % | 21 | -10 | % | ||||||||||
| Other | 1 | 0 | % | 3 | -60 | % | ||||||||||
| Total | 906 | 100 | % | 791 | 15 | % |
| Q1 2022 | % of Total | Q1 2021 | Change | |||||||||||||
| NGLs (MBbls/d) | ||||||||||||||||
| Delaware Basin | 92 | 67 | % | 60 | 52 | % | ||||||||||
| Anadarko Basin | 25 | 19 | % | 21 | 19 | % | ||||||||||
| Williston Basin | 8 | 6 | % | 8 | 0 | % | ||||||||||
| Eagle Ford | 9 | 6 | % | 6 | 35 | % | ||||||||||
| Powder River Basin | 2 | 2 | % | 3 | -21 | % | ||||||||||
| Other | — | 0 | % | 1 | N/M | |||||||||||
| Total | 136 | 100 | % | 99 | 37 | % |
| Q1 2022 | % of Total | Q1 2021 | Change | |||||||||||||
| Combined (MBoe/d) | ||||||||||||||||
| Delaware Basin | 394 | 69 | % | 310 | 27 | % | ||||||||||
| Anadarko Basin | 75 | 13 | % | 68 | 11 | % | ||||||||||
| Williston Basin | 48 | 8 | % | 61 | -20 | % | ||||||||||
| Eagle Ford | 36 | 6 | % | 30 | 19 | % | ||||||||||
| Powder River Basin | 18 | 3 | % | 23 | -23 | % | ||||||||||
| Other | 4 | 1 | % | 7 | -38 | % | ||||||||||
| Total | 575 | 100 | % | 499 | 15 | % |
From the first quarter of 2021 to the first quarter of 2022, the change in volumes contributed to a $212 million increase in earnings. The increase in volumes was primarily due to continued development in the Delaware Basin as well as increased activity in the Anadarko Basin and Eagle Ford. These increases were partially offset by lower volumes in the Williston Basin and Powder River Basin primarily due to natural declines.
Realized Prices
| Q1 2022 | Realization | Q1 2021 | Change | |||||||||||
| Oil (per Bbl) | ||||||||||||||
| WTI index | $ | 94.45 | $ | 57.87 | 63 | % | ||||||||
| Realized price, unhedged | $ | 92.94 | 98% | $ | 55.28 | 68 | % | |||||||
| Cash settlements | $ | (11.32 | ) | $ | (9.13 | ) | ||||||||
| Realized price, with hedges | $ | 81.62 | 86% | $ | 46.15 | 77 | % |
| Q1 2022 | Realization | Q1 2021 | Change | |||||||||||
| Gas (per Mcf) | ||||||||||||||
| Henry Hub index | $ | 4.96 | $ | 2.71 | 83 | % | ||||||||
| Realized price, unhedged | $ | 3.77 | 76% | $ | 2.84 | 33 | % | |||||||
| Cash settlements | $ | (0.62 | ) | $ | (0.15 | ) | ||||||||
| Realized price, with hedges | $ | 3.15 | 64% | $ | 2.69 | 17 | % |
| Q1 2022 | Realization | Q1 2021 | Change | |||||||||||
| NGLs (per Bbl) | ||||||||||||||
| WTI index | $ | 94.45 | $ | 57.87 | 63 | % | ||||||||
| Realized price, unhedged | $ | 37.76 | 40% | $ | 25.01 | 51 | % | |||||||
| Cash settlements | $ | — | $ | (0.20 | ) | |||||||||
| Realized price, with hedges | $ | 37.76 | 40% | $ | 24.81 | 52 | % |
| Q1 2022 | Q1 2021 | Change | ||||||||||
| Combined (per Boe) | ||||||||||||
| Realized price, unhedged | $ | 61.40 | $ | 39.14 | 57 | % | ||||||
| Cash settlements | $ | (6.65 | ) | $ | (5.17 | ) | ||||||
| Realized price, with hedges | $ | 54.75 | $ | 33.97 | 61 | % |
From the first quarter of 2021 to the first quarter of 2022, realized prices contributed to a $1.2 billion increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices. The increase in index prices was partially offset by hedge cash settlements related to oil and gas commodities.
Hedge Settlements
| Q1 2022 | Q1 2021 | Change | ||||||||||
| Oil | $ | (293 | ) | $ | (220 | ) | -33 | % | ||||
| Natural gas | (51 | ) | (10 | ) | -410 | % | ||||||
| NGL | — | (2 | ) | N/M | ||||||||
| Total cash settlements (1) | $ | (344 | ) | $ | (232 | ) | -48 | % |
(1)
Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Production Expenses
| Q1 2022 | Q1 2021 | Change | ||||||||||
| LOE | $ | 224 | $ | 199 | 13 | % | ||||||
| Gathering, processing & transportation | 161 | 129 | 25 | % | ||||||||
| Production taxes | 214 | 117 | 83 | % | ||||||||
| Property taxes | 19 | 13 | 46 | % | ||||||||
| Total | $ | 618 | $ | 458 | 35 | % | ||||||
| Per Boe: | ||||||||||||
| LOE | $ | 4.33 | $ | 4.44 | -3 | % | ||||||
| Gathering, processing & transportation | $ | 3.11 | $ | 2.87 | 8 | % | ||||||
| Percent of oil, gas and NGL sales: | ||||||||||||
| Production taxes | 6.7 | % | 6.6 | % | 2 | % |
Production expenses increased primarily due to higher volumes as well as an increase in production taxes resulting from higher commodity prices.
Field-Level Cash Margin
The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL sales less production expenses and is not a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
| Q1 2022 | $ per BOE | Q1 2021 | $ per BOE | |||||||||||||
| Field-level cash margin (Non-GAAP) | ||||||||||||||||
| Delaware Basin | $ | 1,877 | $ | 52.99 | $ | 895 | $ | 32.07 | ||||||||
| Anadarko Basin | 204 | $ | 30.31 | 85 | $ | 14.01 | ||||||||||
| Williston Basin | 207 | $ | 47.65 | 161 | $ | 29.70 | ||||||||||
| Eagle Ford | 158 | $ | 48.92 | 72 | $ | 26.57 | ||||||||||
| Powder River Basin | 86 | $ | 54.32 | 67 | $ | 31.99 | ||||||||||
| Other | 25 | $ | 61.96 | 19 | $ | 28.21 | ||||||||||
| Total | $ | 2,557 | $ | 49.45 | $ | 1,299 | $ | 28.95 |
DD&A and Asset Impairments
| Q1 2022 | Q1 2021 | Change | ||||||||||
| Oil and gas per Boe | $ | 8.95 | $ | 9.78 | -8 | % | ||||||
| Oil and gas | $ | 463 | $ | 439 | 5 | % | ||||||
| Other property and equipment | 26 | 28 | -6 | % | ||||||||
| Total | $ | 489 | $ | 467 | 5 | % |
DD&A increased primarily due to higher volumes which was partially offset by lower DD&A rates. The decrease in DD&A rates was primarily due to increases to oil, gas and NGL reserve estimates at December 31, 2021, resulting from higher prices.
General and Administrative Expense
| Q1 2022 | Q1 2021 | Change | ||||||||||
| G&A per Boe | $ | 1.82 | $ | 2.40 | -24 | % | ||||||
| Labor and benefits | $ | 58 | $ | 72 | -19 | % | ||||||
| Non-labor | 36 | 35 | 3 | % | ||||||||
| Total | $ | 94 | $ | 107 | -12 | % |
General and administrative expenses decreased primarily due to synergies resulting from the Merger.
Other Items
| Q1 2022 | Q1 2021 | Change in earnings | ||||||||||
| Commodity hedge valuation changes (1) | $ | (339 | ) | $ | (296 | ) | $ | (43 | ) | |||
| Marketing and midstream operations | (4 | ) | (21 | ) | 17 | |||||||
| Exploration expenses | 2 | 3 | 1 | |||||||||
| Asset dispositions | (1 | ) | (32 | ) | (31 | ) | ||||||
| Net financing costs | 85 | 77 | (8 | ) | ||||||||
| Restructuring and transaction costs | — | 189 | 189 | |||||||||
| Other, net | (61 | ) | (29 | ) | 32 | |||||||
| $ | 157 |
(1)
Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.
We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Asset dispositions include $35 million in the first quarter of 2021 related to the sale of non-core assets in the Rockies. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Net financing costs include a $20 million gain in the first quarter of 2021 related to debt retirements. For additional information, see Note 13 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Restructuring and transaction costs in the first quarter of 2021 reflect workforce reductions in conjunction with the Merger, as well as various transaction costs related to the Merger. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
For discussion on other, net, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Income Taxes
| Q1 2022 | Q1 2021 | |||||||
| Current expense (benefit) | $ | 103 | $ | (5 | ) | |||
| Deferred expense (benefit) | 164 | (243 | ) | |||||
| Total expense (benefit) | $ | 267 | $ | (248 | ) | |||
| Effective income tax rate | 21 | % | 763 | % |
For discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Cap****ital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the three months ended March 31, 2022 and 2021.
| Three Months Ended March 31, | ||||||||
| 2022 | 2021 | |||||||
| Operating cash flow | $ | 1,837 | $ | 592 | ||||
| WPX acquired cash | — | 344 | ||||||
| Divestitures of property and equipment | 26 | 15 | ||||||
| Capital expenditures | (537 | ) | (499 | ) | ||||
| Equity method investment activity, net | (14 | ) | 10 | |||||
| Debt activity, net | — | (560 | ) | |||||
| Repurchases of common stock | (211 | ) | — | |||||
| Common stock dividends | (667 | ) | (203 | ) | ||||
| Noncontrolling interest activity, net | (8 | ) | (28 | ) | ||||
| Other | (72 | ) | (30 | ) | ||||
| Net change in cash, cash equivalents and restricted cash | $ | 354 | $ | (359 | ) | |||
| Cash, cash equivalents and restricted cash at end of period | $ | 2,625 | $ | 1,878 |
Operating Cash Flow and WPX Acquired Cash
As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow more than tripled during the three months ended March 31, 2022 compared to the three months ended March 31, 2021. The increase was primarily due to significantly increased commodity prices as well as higher volumes for the first three months of 2022 compared to 2021.
Divestitures of Property and Equipment
During the first three months of 2022 and 2021, we received contingent consideration related to asset divestitures and sold non-core assets, respectfully. For additional information, please see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Capital Expenditures
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.
| Three Months Ended March 31, | ||||||||
| 2022 | 2021 | |||||||
| Delaware Basin | $ | 395 | $ | 397 | ||||
| Anadarko Basin | 10 | 9 | ||||||
| Williston Basin | 23 | 28 | ||||||
| Eagle Ford | 26 | 14 | ||||||
| Powder River Basin | 33 | 33 | ||||||
| Other | 3 | — | ||||||
| Total oil and gas | 490 | 481 | ||||||
| Midstream | 29 | 5 | ||||||
| Other | 18 | 13 | ||||||
| Total capital expenditures | $ | 537 | $ | 499 |
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Our capital investment program is driven by a disciplined allocation process focused on moderating our production growth and maximizing our returns. As such, our 2022 capital expenditures represent approximately 30% of our operating cash flow.
Equity Method Investments
During the first three months of 2022 and 2021, Devon received distributions from our equity method investments of $8 million and $10 million, respectively. Devon contributed $22 million to our equity method investments during the first three months of 2022.
Debt Activity
Subsequent to the Merger closing, we redeemed $533 million of senior notes in the first quarter of 2021. We also paid $27 million of cash retirement costs related to these redemptions.
Shareholder Distributions and Stock Activity
We repurchased approximately 4.0 million shares of common stock for $230 million in the first quarter of 2022 under the share repurchase program authorized by our Board of Directors. For additional information, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
The following table summarizes our common stock dividends during the first quarter 2022 and 2021. In February 2022, our Board of Directors increased our fixed dividend rate by 45% to $0.16 per share. In addition to the fixed quarterly dividend, we paid a variable dividend of $0.84 per share in the first quarter of 2022 and $0.19 per share in the first quarter of 2021.
| Fixed | Variable | Total | Rate Per Share | ||||||||||||
| 2022: | |||||||||||||||
| First quarter | $ | 109 | $ | 558 | $ | 667 | $ | 1.00 | |||||||
| 2021: | |||||||||||||||
| First quarter | $ | 76 | $ | 127 | $ | 203 | $ | 0.30 |
Noncontrolling Interest Activity, net
During the first three months of 2022 and 2021, we distributed $8 million and $4 million, respectively, to our noncontrolling interests in CDM. In the first quarter of 2021, we paid $24 million to purchase the noncontrolling interest portion of a partnership that WPX had formed to acquire minerals in the Delaware Basin.
Liquidity
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.
Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements as discussed in this section as well as accelerate our cash-return business model.
Operating Cash Flow
Key inputs into determining our planned capital investment are the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of the first quarter of 2022, we held approximately $2.6 billion of cash, inclusive of approximately $150 million of cash restricted primarily for retained obligations related to divested assets. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as actual results may differ from our expectations.
Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other highly variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control.
To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. The key terms to our oil, gas and NGL derivative financial instruments as of March 31, 2022 are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” of this report.
Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Additionally, we remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2022. We will continue to prioritize economic value over growing volumes, which is driven partially by current commodity price backwardation, supply chain constraints and economic uncertainty arising from recent geopolitical events.
Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices. Furthermore, the COVID-19 pandemic has contributed to disruption and volatility in our supply chain, which has resulted, and may continue to result in labor shortages, increased costs and delays for pipe and other materials needed for our operations.
Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint interest owners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or cash collateral postings.
Credit Availability
As of March 31, 2022, we had approximately $3.0 billion of available borrowing capacity under our Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At March 31, 2022, there were no borrowings under our commercial paper program, and we were in compliance with the Senior Credit Facility’s financial covenant.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Baa3 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.
There are no “rating triggers” in any of our contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.
Fixed Plus Variable Dividend
We are committed to a “fixed plus variable” dividend strategy. Our Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. In February 2022, our Board of Directors increased our quarterly fixed dividend rate by 45% to $0.16 per share. In addition to the fixed quarterly dividend, we may pay a variable dividend up to 50% of our excess free cash flow, which is a non-GAAP measure. Each quarter’s excess free cash flow is computed as operating cash flow (a GAAP measure) before balance sheet changes, less capital expenditures and the fixed dividend. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on our financial results, cash requirements, future prospects and other factors deemed relevant by the Board.
In May 2022, Devon announced a cash dividend in the amount of $1.27 per share payable in the second quarter of 2022. The dividend consists of a fixed quarterly dividend in the amount of approximately $106 million (or $0.16 per share) and a variable quarterly dividend in the amount of approximately $732 million (or $1.11 per share).
Share Repurchases
In May 2022, our Board of Directors increased our share repurchase program by $0.4 billion to a total authorized amount of $2.0 billion, and extended the expiration date to May 4, 2023. Through April 29, 2022, we had executed $891 million of the authorized program.
Capital Expenditures
Our 2022 exploration and development budget for the remainder of 2022 is expected to range from approximately $1.4 billion to $1.7 billion.
Critical Accounting Est****imates
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Further, in the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change has occurred during 2022 for Devon, but the Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next two years.
For additional information regarding our critical accounting policies and estimates, see our 2021 Annual Report on Form 10-K.
Non-GA****AP Measures
We make reference to “core earnings attributable to Devon” and “core earnings per share attributable to Devon” in “Executive Overview” in this Item 2 that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain non-cash and other items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded relate to asset dispositions, non-cash asset impairments (including non-cash unproved asset impairments), deferred tax asset valuation allowance, fair value changes in derivative financial instruments and foreign currency, costs associated with early retirement of debt and restructuring and transaction costs associated with the workforce reductions described further in Note 5.
We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.
Below are reconciliations of core earnings and core earnings per share attributable to Devon to comparable GAAP measures.
| Three Months Ended March 31, | |||||||||||||||
| Before Tax | After Tax | After Noncontrolling Interests | Per Diluted Share | ||||||||||||
| 2022 | |||||||||||||||
| Earnings attributable to Devon (GAAP) | $ | 1,262 | $ | 995 | $ | 989 | $ | 1.48 | |||||||
| Adjustments: | |||||||||||||||
| Asset dispositions | (1 | ) | — | — | — | ||||||||||
| Deferred tax asset valuation allowance | — | 6 | 6 | 0.01 | |||||||||||
| Fair value changes in financial instruments | 338 | 260 | 260 | 0.39 | |||||||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 1,599 | $ | 1,261 | $ | 1,255 | $ | 1.88 | |||||||
| 2021 | |||||||||||||||
| Earnings (loss) attributable to Devon (GAAP) | $ | (32 | ) | $ | 216 | $ | 213 | $ | 0.32 | ||||||
| Adjustments: | |||||||||||||||
| Asset dispositions | (32 | ) | (24 | ) | (24 | ) | (0.04 | ) | |||||||
| Asset and exploration impairments | 1 | — | — | — | |||||||||||
| Deferred tax asset valuation allowance | — | (263 | ) | (263 | ) | (0.40 | ) | ||||||||
| Fair value changes in financial instruments and foreign currency | 294 | 225 | 225 | 0.34 | |||||||||||
| Restructuring and transaction costs | 189 | 162 | 162 | 0.25 | |||||||||||
| Early retirement of debt | (20 | ) | (15 | ) | (15 | ) | (0.02 | ) | |||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 400 | $ | 301 | $ | 298 | $ | 0.45 |
EBITDAX and Field-Level Cash Margin
To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings before income tax expense; financing costs, net; exploration expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL sales less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.
We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.
We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from operations.
Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.
| Three Months Ended March 31, | |||||||
| 2022 | 2021 | ||||||
| Net earnings (GAAP) | $ | 995 | $ | 216 | |||
| Financing costs, net | 85 | 77 | |||||
| Income tax expense (benefit) | 267 | (248 | ) | ||||
| Exploration expenses | 2 | 3 | |||||
| Depreciation, depletion and amortization | 489 | 467 | |||||
| Asset dispositions | (1 | ) | (32 | ) | |||
| Share-based compensation | 20 | 20 | |||||
| Derivative and financial instrument non-cash valuation changes | 339 | 296 | |||||
| Restructuring and transaction costs | — | 189 | |||||
| Accretion on discounted liabilities and other | (61 | ) | (29 | ) | |||
| EBITDAX (Non-GAAP) | 2,135 | 959 | |||||
| Marketing and midstream revenues and expenses, net | 4 | 21 | |||||
| Commodity derivative cash settlements | 344 | 232 | |||||
| General and administrative expenses, cash-based | 74 | 87 | |||||
| Field-level cash margin (Non-GAAP) | $ | 2,557 | $ | 1,299 |
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