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 and nine-month periods ended September 30, 2021 compared to previous periods and in our financial condition and liquidity since December 31, 2020. To help facilitate comparisons to the three-month period ended June 30, 2021, information regarding our second quarter 2021 financial results can be found in our Second Quarter 2021 Quarterly Report on Form 10-Q . Additionally, for information regarding our critical accounting policies and estimates, see our 2020 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Executive Overview
On September 26, 2020, we entered into the Merger Agreement, providing for an all-stock merger of equals with WPX which successfully closed on January 7, 2021. The Merger has created 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 accelerates 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 disciplined oil volume growth while capturing 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:
| • | Third quarter oil production totaled 303 MBbls/d, exceeding our plan by 3%. |
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| • | On pace to achieve approximately $600 million in annual cost savings by the end of 2021. |
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| • | Redeemed approximately $1.2 billion of senior notes in 2021. |
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| • | Exited the third quarter with $5.3 billion of liquidity, including $2.3 billion of cash, with no debt maturities until 2023. |
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| • | Generated $3.3 billion of operating cash flow through the first three quarters of 2021. |
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| • | Including variable dividends, paid dividends of approximately $761 million in the first nine months of 2021 and have declared $568 million of dividends to be paid in the fourth quarter of 2021. |
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| • | Authorized a $1.0 billion share repurchase program, representing 4% of outstanding shares at the time of announcement. |
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We operate under a disciplined returns-driven strategy focused on delivering strong operational results, financial strength and value to our shareholders and continuing our commitment to ESG excellence, which provides us with a strong foundation to grow returns, margin and profitability. We continue to execute on our strategy and navigate through various economic environments by protecting our financial strength, maintaining a commitment to capital discipline, improving our cash cost structure and preserving operational continuity.
Commodity prices have strengthened throughout 2021 which has significantly improved our earnings and cash flow generation. The increase in commodity prices has been 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 current production levels.
Trends of our quarterly earnings, operating cash flow, EBITDAX and capital expenditures are shown below. The quarterly earnings chart and cash flow chart present amounts pertaining to Devon’s continuing operations. “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 increased from the second quarter of 2021 to the third quarter of 2021 primarily due to an increase in overall commodity prices as well as higher sold volumes. Led by a 42% and 7% increase in Henry Hub and WTI from the second quarter of 2021 to the third quarter of 2021, respectively, our unhedged combined realized price rose 13%. Volumes increased due to new well activity in the Delaware Basin and Eagle Ford.
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 second quarter of 2021, the first quarter of 2021, the fourth quarter of 2020 and the third quarter of 2020 each included a hedge valuation loss, net of tax of $0.3 billion, $0.2 billion, $0.1 billion and $0.1 billion, respectively. Excluding these amounts, our core earnings have been more stable over recent quarters but continue to be heavily influenced by commodity prices.
Like earnings, our operating cash flow is sensitive to volatile commodity prices. Our cash flow and EBITDAX increased during the first, second and third quarters of 2021 primarily due to higher commodity prices and an increase in sold volumes driven by our WPX merger and improved post-merger operating performance.
We exited the third quarter of 2021 with $5.3 billion of liquidity, comprised of $2.3 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 45% and 50% of our remaining 2021 oil and gas production hedged, respectively, and 20% and 30% of our 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 $1.0 billion of our common shares through the end of 2022. Additionally, we continue funding our fixed plus variable dividends, which have grown 13%, 44% and 71% over the past three quarters, respectively, including the recently declared dividend payable in the fourth quarter of 2021.
Results 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 earnings attributable to discontinued operations or noncontrolling interests.
Q3 2021 vs. Q2 2021
Our third quarter 2021 net earnings were $844 million, compared to net earnings of $261 million for the second quarter of 2021. The graph below shows the change in net earnings from the second quarter of 2021 to the third quarter of 2021. The material changes are further discussed by category on the following pages.
Production Volumes
| Q3 2021 | % of Total | Q2 2021 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil (MBbls/d) | ||||||||||||||||
| Delaware Basin | 213 | 70 | % | 191 | +11 | % | ||||||||||
| Anadarko Basin | 14 | 5 | % | 17 | - 15 | % | ||||||||||
| Williston Basin | 39 | 13 | % | 46 | - 15 | % | ||||||||||
| Eagle Ford | 20 | 6 | % | 18 | +11 | % | ||||||||||
| Powder River Basin | 14 | 5 | % | 16 | - 13 | % | ||||||||||
| Other | 3 | 1 | % | 3 | +1 | % | ||||||||||
| Total | 303 | 100 | % | 291 | +4 | % |
| Q3 2021 | % of Total | Q2 2021 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gas (MMcf/d) | ||||||||||||||||
| Delaware Basin | 578 | 62 | % | 513 | +13 | % | ||||||||||
| Anadarko Basin | 219 | 23 | % | 225 | - 3 | % | ||||||||||
| Williston Basin | 59 | 6 | % | 61 | - 4 | % | ||||||||||
| Eagle Ford | 67 | 7 | % | 59 | +14 | % | ||||||||||
| Powder River Basin | 19 | 2 | % | 21 | - 10 | % | ||||||||||
| Other | 1 | 0 | % | 2 | - 45 | % | ||||||||||
| Total | 943 | 100 | % | 881 | +7 | % |
| Q3 2021 | % of Total | Q2 2021 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| NGLs (MBbls/d) | ||||||||||||||||
| Delaware Basin | 100 | 68 | % | 82 | +23 | % | ||||||||||
| Anadarko Basin | 25 | 17 | % | 26 | - 4 | % | ||||||||||
| Williston Basin | 9 | 6 | % | 9 | - 3 | % | ||||||||||
| Eagle Ford | 11 | 7 | % | 9 | +25 | % | ||||||||||
| Powder River Basin | 3 | 2 | % | 3 | - 4 | % | ||||||||||
| Other | — | 0 | % | — | N/M | |||||||||||
| Total | 148 | 100 | % | 129 | +15 | % |
| Q3 2021 | % of Total | Q2 2021 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Combined (MBoe/d) | ||||||||||||||||
| Delaware Basin | 409 | 67 | % | 358 | +14 | % | ||||||||||
| Anadarko Basin | 75 | 12 | % | 80 | - 6 | % | ||||||||||
| Williston Basin | 58 | 10 | % | 66 | - 12 | % | ||||||||||
| Eagle Ford | 42 | 7 | % | 37 | +15 | % | ||||||||||
| Powder River Basin | 20 | 3 | % | 22 | - 12 | % | ||||||||||
| Other | 4 | 1 | % | 4 | +0 | % | ||||||||||
| Total | 608 | 100 | % | 567 | +7 | % |
From the second quarter of 2021 to the third quarter of 2021, the change in volumes contributed to a $149 million increase in earnings. The increase in volumes was primarily due to new well activity in the Delaware Basin and Eagle Ford which was partially offset by lower volumes in the Anadarko, Williston and Powder River Basins.
Realized Prices
| Q3 2021 | Realization | Q2 2021 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil (per Bbl) | ||||||||||||||||
| WTI index | $ | 70.64 | $ | 66.04 | +7 | % | ||||||||||
| Realized price, unhedged | $ | 68.19 | 97% | $ | 63.63 | +7 | % | |||||||||
| Cash settlements | $ | (10.60 | ) | $ | (13.29 | ) | ||||||||||
| Realized price, with hedges | $ | 57.59 | 82% | $ | 50.34 | +14 | % |
| Q3 2021 | Realization | Q2 2021 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gas (per Mcf) | ||||||||||||||||
| Henry Hub index | $ | 4.02 | $ | 2.83 | +42 | % | ||||||||||
| Realized price, unhedged | $ | 3.55 | 88% | $ | 2.35 | +51 | % | |||||||||
| Cash settlements | $ | (0.78 | ) | $ | (0.15 | ) | ||||||||||
| Realized price, with hedges | $ | 2.77 | 69% | $ | 2.20 | +26 | % |
| Q3 2021 | Realization | Q2 2021 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| NGLs (per Bbl) | ||||||||||||||||
| WTI index | $ | 70.64 | $ | 66.04 | +7 | % | ||||||||||
| Realized price, unhedged | $ | 31.25 | 44% | $ | 23.89 | +31 | % | |||||||||
| Cash settlements | $ | (0.45 | ) | $ | (0.25 | ) | ||||||||||
| Realized price, with hedges | $ | 30.80 | 44% | $ | 23.64 | +30 | % |
| Q3 2021 | Q2 2021 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Combined (per Boe) | ||||||||||||
| Realized price, unhedged | $ | 47.08 | $ | 41.75 | +13 | % | ||||||
| Cash settlements | $ | (6.60 | ) | $ | (7.11 | ) | ||||||
| Realized price, with hedges | $ | 40.48 | $ | 34.64 | +17 | % |
From the second quarter of 2021 to the third quarter of 2021, realized prices contributed to a $332 million increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices.
We currently have approximately 45% of our remaining 2021 oil production hedged with an average floor price of $40/Bbl and approximately 50% of our remaining 2021 gas production hedged with an average floor price of $2.60/Mcf. We currently have approximately 20% of our 2022 oil production hedged with an average floor price of $45/Bbl and approximately 30% of our 2022 gas production hedged with an average floor price of $2.70/Mcf.
Hedge Settlements
| Q3 2021 | Q2 2021 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Q | ||||||||||||
| Oil | $ | (296 | ) | $ | (352 | ) | +16 | % | ||||
| Natural gas | (68 | ) | (12 | ) | N/M | |||||||
| NGL | (6 | ) | (3 | ) | - 100 | % | ||||||
| Total cash settlements (1) | $ | (370 | ) | $ | (367 | ) | - 1 | % |
| (1) | Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings. |
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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
| Q3 2021 | Q2 2021 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| LOE | $ | 215 | $ | 210 | +2 | % | ||||||
| Gathering, processing & transportation | 157 | 147 | +7 | % | ||||||||
| Production taxes | 176 | 143 | +23 | % | ||||||||
| Property taxes | 7 | 13 | - 46 | % | ||||||||
| Total | $ | 555 | $ | 513 | +8 | % | ||||||
| Per Boe: | ||||||||||||
| LOE | $ | 3.85 | $ | 4.06 | - 5 | % | ||||||
| Gathering, processing & transportation | $ | 2.81 | $ | 2.85 | - 1 | % | ||||||
| Percent of oil, gas and NGL sales: | ||||||||||||
| Production taxes | 6.7 | % | 6.7 | % | - 0 | % |
Production expenses increased from the second quarter of 2021 to the third quarter of 2021 primarily due to new well activity in the Delaware Basin. Production taxes also increased due to the rise in 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.
| Q3 2021 | $ per BOE | Q2 2021 | $ per BOE | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Field-level cash margin (Non-GAAP) | ||||||||||||||||
| Delaware Basin | $ | 1,480 | $ | 39.28 | $ | 1,102 | $ | 33.79 | ||||||||
| Anadarko Basin | 174 | $ | 25.20 | 145 | $ | 19.86 | ||||||||||
| Williston Basin | 192 | $ | 36.12 | 197 | $ | 32.98 | ||||||||||
| Eagle Ford | 147 | $ | 37.81 | 106 | $ | 31.88 | ||||||||||
| Powder River Basin | 69 | $ | 38.18 | 74 | $ | 36.78 | ||||||||||
| Other | 18 | $ | 49.53 | 17 | $ | 42.85 | ||||||||||
| Total | $ | 2,080 | $ | 37.17 | $ | 1,641 | $ | 31.79 |
DD&A and Asset Impairments
| Q3 2021 | Q2 2021 | Change | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil and gas per Boe | $ | 9.85 | $ | 9.88 | - 0 | % | |||||||
| Oil and gas | $ | 551 | $ | 510 | +8 | % | |||||||
| Other property and equipment | 27 | 26 | +4 | % | |||||||||
| Total | $ | 578 | $ | 536 | +8 | % |
DD&A increased in the third quarter of 2021 primarily due to higher volumes.
Other Items
| Q3 2021 | Q2 2021 | Change in earnings | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Commodity hedge valuation changes (1) | $ | 35 | $ | (336 | ) | $ | 371 | |||||
| Marketing and midstream operations | 1 | 1 | — | |||||||||
| Exploration expenses | 3 | 3 | — | |||||||||
| Asset dispositions | — | (87 | ) | (87 | ) | |||||||
| Net financing costs | 86 | 80 | (6 | ) | ||||||||
| Restructuring and transaction costs | 18 | 23 | 5 | |||||||||
| Other, net | 2 | (14 | ) | (16 | ) | |||||||
| $ | 267 |
| (1) | Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings. |
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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 second quarter of 2021 includes $65 million related to the re-valuation of contingent earnout payments associated with our divested Barnett Shale assets. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Income Taxes
| Q3 2021 | Q2 2021 | |||||||
|---|---|---|---|---|---|---|---|---|
| Current expense | $ | 1 | $ | 19 | ||||
| Deferred expense | 119 | 24 | ||||||
| Total expense | $ | 120 | $ | 43 | ||||
| Effective income tax rate | 12 | % | 14 | % |
For discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
September 30, 2021 YTD vs. September 30, 2020 YTD
Our nine months ended September 30, 2021 net earnings were $1.3 billion, compared to a net loss of $2.5 billion (excludes discontinued operations) for the nine months ended September 30, 2020. The graph below shows the change in the net earnings (loss) from the nine months ended September 30, 2020 to the nine months ended September 30, 2021. The material changes are further discussed by category on the following pages.
Production Volumes
| Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | % of Total | 2020 | Change | |||||||||||||
| Oil (MBbls/d) | ||||||||||||||||
| Delaware Basin | 192 | 67 | % | 80 | +140 | % | ||||||||||
| Anadarko Basin | 14 | 5 | % | 21 | - 32 | % | ||||||||||
| Williston Basin | 43 | 15 | % | — | N/M | |||||||||||
| Eagle Ford | 18 | 6 | % | 25 | - 29 | % | ||||||||||
| Powder River Basin | 16 | 5 | % | 20 | - 23 | % | ||||||||||
| Other | 4 | 2 | % | 8 | - 42 | % | ||||||||||
| Total | 287 | 100 | % | 154 | +87 | % |
| Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | % of Total | 2020 | Change | |||||||||||||
| Gas (MMcf/d) | ||||||||||||||||
| Delaware Basin | 521 | 60 | % | 241 | +116 | % | ||||||||||
| Anadarko Basin | 215 | 25 | % | 258 | - 17 | % | ||||||||||
| Williston Basin | 56 | 6 | % | — | N/M | |||||||||||
| Eagle Ford | 57 | 7 | % | 82 | - 30 | % | ||||||||||
| Powder River Basin | 21 | 2 | % | 24 | - 14 | % | ||||||||||
| Other | 2 | 0 | % | 4 | - 48 | % | ||||||||||
| Total | 872 | 100 | % | 609 | +43 | % |
| Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | % of Total | 2020 | Change | |||||||||||||
| NGLs (MBbls/d) | ||||||||||||||||
| Delaware Basin | 81 | 65 | % | 35 | +132 | % | ||||||||||
| Anadarko Basin | 24 | 19 | % | 28 | - 16 | % | ||||||||||
| Williston Basin | 9 | 7 | % | — | N/M | |||||||||||
| Eagle Ford | 9 | 7 | % | 11 | - 18 | % | ||||||||||
| Powder River Basin | 3 | 2 | % | 3 | +0 | % | ||||||||||
| Other | — | 0 | % | 1 | - 100 | % | ||||||||||
| Total | 126 | 100 | % | 78 | +62 | % |
| Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | % of Total | 2020 | Change | |||||||||||||
| Combined (MBoe/d) | ||||||||||||||||
| Delaware Basin | 360 | 64 | % | 155 | +132 | % | ||||||||||
| Anadarko Basin | 74 | 13 | % | 92 | - 20 | % | ||||||||||
| Williston Basin | 61 | 11 | % | — | N/M | |||||||||||
| Eagle Ford | 36 | 7 | % | 50 | - 27 | % | ||||||||||
| Powder River Basin | 22 | 4 | % | 27 | - 19 | % | ||||||||||
| Other | 5 | 1 | % | 9 | - 43 | % | ||||||||||
| Total | 558 | 100 | % | 333 | +68 | % |
From the nine months ended 2020 to the nine months ended 2021, the change in volumes contributed to a $1.5 billion increase in earnings. Due to the Merger closing on January 7, 2021, volumes now include WPX legacy assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Volumes associated with these WPX legacy assets were approximately 225 MBoe/d for the nine months ended 2021. Continued development of Devon legacy assets in the Delaware Basin also increased volumes. These increases were partially offset by reduced activity across Devon’s remaining legacy assets.
Realized Prices
| Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | Realization | 2020 | Change | |||||||||||||
| Oil (per Bbl) | ||||||||||||||||
| WTI index | $ | 64.85 | $ | 38.57 | +68 | % | ||||||||||
| Realized price, unhedged | $ | 62.69 | 97% | $ | 34.63 | +81 | % | |||||||||
| Cash settlements | $ | (11.06 | ) | $ | 7.06 | |||||||||||
| Realized price, with hedges | $ | 51.63 | 80% | $ | 41.69 | +24 | % |
| Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | Realization | 2020 | Change | |||||||||||||
| Gas (per Mcf) | ||||||||||||||||
| Henry Hub index | $ | 3.19 | $ | 1.88 | +70 | % | ||||||||||
| Realized price, unhedged | $ | 2.93 | 92% | $ | 1.32 | +122 | % | |||||||||
| Cash settlements | $ | (0.38 | ) | $ | 0.24 | |||||||||||
| Realized price, with hedges | $ | 2.55 | 80% | $ | 1.56 | +63 | % |
| Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | Realization | 2020 | Change | |||||||||||||
| NGLs (per Bbl) | ||||||||||||||||
| WTI index | $ | 64.85 | $ | 38.57 | +68 | % | ||||||||||
| Realized price, unhedged | $ | 27.11 | 42% | $ | 10.66 | +154 | % | |||||||||
| Cash settlements | $ | (0.32 | ) | $ | 0.25 | |||||||||||
| Realized price, with hedges | $ | 26.79 | 41% | $ | 10.91 | +146 | % |
| Nine Months Ended September 30, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | Change | ||||||||||
| Combined (per Boe) | ||||||||||||
| Realized price, unhedged | $ | 42.94 | $ | 20.91 | +105 | % | ||||||
| Cash settlements | $ | (6.35 | ) | $ | 3.76 | |||||||
| Realized price, with hedges | $ | 36.59 | $ | 24.67 | +48 | % |
From the nine months ended 2020 to the nine months ended 2021, realized prices contributed to a $3.1 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 all products in the first nine months of 2021.
Hedge Settlements
| Nine Months Ended September 30, | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | Change | ||||||||
| Oil | $ | (868 | ) | $ | 298 | N/M | ||||
| Natural gas | (90 | ) | 40 | N/M | ||||||
| NGL | (11 | ) | 5 | N/M | ||||||
| Total cash settlements (1) | $ | (969 | ) | $ | 343 | N/M |
| (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
| Nine Months Ended September 30, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | Change | ||||||||||
| LOE | $ | 624 | $ | 334 | +87 | % | ||||||
| Gathering, processing & transportation | 433 | 378 | +15 | % | ||||||||
| Production taxes | 436 | 123 | +254 | % | ||||||||
| Property taxes | 33 | 17 | +94 | % | ||||||||
| Total | $ | 1,526 | $ | 852 | +79 | % | ||||||
| Per Boe: | ||||||||||||
| LOE | $ | 4.09 | $ | 3.66 | +12 | % | ||||||
| Gathering, processing & transportation | $ | 2.84 | $ | 4.15 | - 31 | % | ||||||
| Percent of oil, gas and NGL sales: | ||||||||||||
| Production taxes | 6.7 | % | 6.4 | % | +4 | % |
Production expenses increased primarily due to the Merger closing on January 7, 2021. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report. Partially offsetting increases to gathering, processing and transportation costs were approximately $39 million of Anadarko volume commitments which expired at the end of 2020. Production taxes also increased due to the rise in 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.
| Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | $ per BOE | 2020 | $ per BOE | |||||||||||||
| Field-level cash margin (Non-GAAP) | ||||||||||||||||
| Delaware Basin | $ | 3,477 | $ | 35.41 | $ | 602 | $ | 14.16 | ||||||||
| Anadarko Basin | 404 | $ | 19.93 | 143 | $ | 5.62 | ||||||||||
| Williston Basin | 550 | $ | 32.91 | — | N/M | |||||||||||
| Eagle Ford | 325 | $ | 32.74 | 170 | $ | 12.54 | ||||||||||
| Powder River Basin | 210 | $ | 35.53 | 121 | $ | 16.45 | ||||||||||
| Other | 54 | $ | 37.69 | 21 | $ | 8.77 | ||||||||||
| Total | $ | 5,020 | $ | 32.93 | $ | 1,057 | $ | 11.58 |
DD&A and Asset Impairments
| Nine Months Ended September 30, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | Change | ||||||||||
| Oil and gas per Boe | $ | 9.84 | $ | 10.19 | - 3 | % | ||||||
| Oil and gas | $ | 1,500 | $ | 929 | +61 | % | ||||||
| Other property and equipment | 81 | 70 | +16 | % | ||||||||
| Total | $ | 1,581 | $ | 999 | +58 | % | ||||||
| Asset impairments | $ | — | $ | 2,666 | N/M |
DD&A increased in 2021 primarily due to the Merger closing on January 7, 2021. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Asset impairments were $2.7 billion for the nine months ended 2020 due to significant decreases in commodity prices resulting primarily from the COVID-19 pandemic. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
General and Administrative Expense
| Nine Months Ended September 30, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | Change | ||||||||||
| G&A per Boe | $ | 1.94 | $ | 2.81 | - 31 | % | ||||||
| Labor and benefits | $ | 197 | $ | 157 | +25 | % | ||||||
| Non-labor | 99 | 99 | +0 | % | ||||||||
| Total | $ | 296 | $ | 256 | +16 | % |
Labor and benefits increased primarily due to the Merger closing on January 7, 2021. However, Devon’s G&A per Boe rate decreased 31% primarily due to synergies resulting from the Merger.
Other Items
| Nine Months Ended September 30, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | Change in earnings | ||||||||||
| Commodity hedge valuation changes (1) | $ | (597 | ) | $ | (71 | ) | $ | (526 | ) | |||
| Marketing and midstream operations | (19 | ) | (28 | ) | 9 | |||||||
| Exploration expenses | 9 | 163 | 154 | |||||||||
| Asset dispositions | (119 | ) | — | 119 | ||||||||
| Net financing costs | 243 | 200 | (43 | ) | ||||||||
| Restructuring and transaction costs | 230 | 32 | (198 | ) | ||||||||
| Other, net | (41 | ) | (35 | ) | 6 | |||||||
| $ | (479 | ) |
| (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.
Exploration expenses decreased primarily due to unproved asset impairments of $149 million in the first nine months of 2020. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Asset dispositions includes $65 million related to the re-valuation of contingent earnout payments associated with our divested Barnett Shale assets and $35 million 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 increased as a result of WPX debt assumed in the Merger, partially offset by a $30 million gain associated with our debt retirements in the first nine months of 2021. For additional information, see Note 13 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Restructuring and transaction costs in 2021 reflect workforce reductions in conjunction with the Merger, as well as various transaction costs related to the Merger. For additional information, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Income Taxes
| Nine Months Ended September 30, | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | |||||||
| Current expense (benefit) | $ | 15 | $ | (199 | ) | |||
| Deferred benefit | (100 | ) | (311 | ) | ||||
| Total benefit | $ | (85 | ) | $ | (510 | ) | ||
| Effective income tax rate | (7 | %) | 17 | % |
For discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the three and nine months ended September 30, 2021 and 2020.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||
| Operating cash flow from continuing operations | $ | 1,598 | $ | 427 | $ | 3,283 | $ | 1,106 | |||||||||
| WPX acquired cash | — | — | 344 | — | |||||||||||||
| Divestitures of property and equipment | 1 | 1 | 65 | 29 | |||||||||||||
| Capital expenditures | (474 | ) | (204 | ) | (1,477 | ) | (936 | ) | |||||||||
| Debt activity, net | — | — | (1,302 | ) | — | ||||||||||||
| Repurchases of common stock | — | — | — | (38 | ) | ||||||||||||
| Common stock dividends | (329 | ) | (43 | ) | (761 | ) | (119 | ) | |||||||||
| Noncontrolling interest activity, net | (5 | ) | (3 | ) | (35 | ) | 2 | ||||||||||
| Other | (9 | ) | — | (33 | ) | (22 | ) | ||||||||||
| Net change in cash, cash equivalents and restricted cash from discontinued operations | — | 50 | — | 31 | |||||||||||||
| Net change in cash, cash equivalents and restricted cash | $ | 782 | $ | 228 | $ | 84 | $ | 53 | |||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | 2,321 | $ | 1,897 | $ | 2,321 | $ | 1,897 |
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 nearly tripled during the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. The increase was due to the Merger and prices significantly increasing in the first nine months of 2021. Additionally, despite our portfolio enhancements, aggressive cost reductions and operational advancements, our 2020 financial results were challenged by commodity prices and deterioration of the macro-economic environment resulting from the unprecedented COVID-19 pandemic.
Divestitures of Property and Equipment
During the first nine months of 2021, we sold non-core assets for approximately $65 million, net of customary purchase price adjustments. 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 September 30, | Nine Months Ended September 30, | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | 2021 | 2020 | |||||||||||||
| Delaware Basin | $ | 375 | $ | 147 | $ | 1,150 | $ | 560 | ||||||||
| Anadarko Basin | 11 | 2 | 29 | 20 | ||||||||||||
| Williston Basin | 13 | — | 59 | — | ||||||||||||
| Eagle Ford | 45 | 17 | 88 | 153 | ||||||||||||
| Powder River Basin | 13 | 24 | 53 | 155 | ||||||||||||
| Other | 1 | 3 | 1 | 9 | ||||||||||||
| Total oil and gas | 458 | 193 | 1,380 | 897 | ||||||||||||
| Midstream | 5 | 7 | 53 | 26 | ||||||||||||
| Other | 11 | 4 | 44 | 13 | ||||||||||||
| Total capital expenditures | $ | 474 | $ | 204 | $ | 1,477 | $ | 936 |
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Capital expenditures increased in 2021 primarily due to the Merger closing on January 7,
2021 and results now include activity related to WPX legacy assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. Our capital program is designed to operate within operating cash flow. This is evidenced by our operating cash flow funding all of our capital expenditures for the nine months ended September 30, 2021. Our capital investment program is driven by a disciplined allocation process focused on returns.
Debt Activity
Subsequent to the Merger closing, we redeemed $1.2 billion of senior notes in the first nine months of 2021. We also paid $59 million of cash retirement costs related to these redemptions.
Shareholder Distributions and Stock Activity
The following table summarizes our common stock dividends during the third quarter and total for the first nine months of 2021 and 2020. We raised our quarterly dividend by 22% to $0.11 per share in the second quarter of 2020. In addition to the fixed quarterly dividend, we paid a variable dividend in each quarter of 2021.
| Fixed | Variable | Total | Rate Per Share | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021: | |||||||||||||||
| First quarter | $ | 76 | $ | 127 | $ | 203 | $ | 0.30 | |||||||
| Second quarter | 75 | 154 | 229 | $ | 0.34 | ||||||||||
| Third quarter | 74 | 255 | 329 | $ | 0.49 | ||||||||||
| Total year-to-date | $ | 225 | $ | 536 | $ | 761 | |||||||||
| 2020: | |||||||||||||||
| First quarter | $ | 34 | $ | — | $ | 34 | $ | 0.09 | |||||||
| Second quarter | 42 | — | 42 | $ | 0.11 | ||||||||||
| Third quarter | 43 | — | 43 | $ | 0.11 | ||||||||||
| Total year-to-date | $ | 119 | $ | — | $ | 119 |
We repurchased 2.2 million shares of common stock for $38 million in the first nine months of 2020. For additional information, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Noncontrolling Interest Activity, net
During the first nine months of 2021, we received $4 million of contributions from our noncontrolling interests in CDM and distributed $15 million 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.
During the first nine months of 2020, we received $12 million in contributions from our noncontrolling interests in CDM and distributed $10 million to our noncontrolling interests in CDM.
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.
On January 7, 2021, Devon and WPX completed an all-stock merger of equals. With the Merger, we accelerated our transition to a cash-return business model, which moderates growth, emphasizes capital efficiencies and prioritizes cash returns to shareholders. These principles will position Devon to be a consistent builder of economic value through the cycle. The post-merger scalability enhanced Devon’s free cash flow, credit profile and decreased the overall cost of capital.
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 post-merger 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 third quarter of 2021, we held approximately $2.3 billion of cash, inclusive of $177 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 these variables 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. We hedge our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of favorable market conditions. The key terms to our oil, gas and NGL derivative financial instruments as of September 30, 2021 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, as commodity prices have increased, we remain committed to a maintenance capital program for the foreseeable future. We do not intend to add any growth projects until market fundamentals recover, excess inventory clears up and OPEC+ curtailed volumes are effectively absorbed by the world markets.
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.
Merger Synergies – Cost savings from synergies resulting from the Merger are expected to be attained through cost reductions and efficiencies related to our capital programs, G&A, financing costs and production expenses. We anticipate the planned $600 million reduction of annualized costs will occur by year-end 2021. Approximately 35% of the reduced costs are related to our capital programs and the remainder relate to our operating expenses, including G&A, interest expense and production expenses.
Restructuring and Transaction Related Costs – The majority of the Merger-related restructuring and transaction cost cash outflows were paid in the first nine months of 2021 and the remaining costs will be paid mostly over the remaining three months of 2021. These payments relate to workforce reductions and the associated employee severance benefits, costs to modify or abandon vendor contracts and the acceleration of certain employee benefits triggered by the Merger.
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 partners 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 collateral postings.
Assumption and Repayment of WPX Debt
In conjunction with the Merger closing on January 7, 2021, we assumed a principal value of $3.3 billion of WPX debt. Subsequent to the Merger closing, we have reduced our debt by approximately $1.2 billion in the first half of 2021. We expect these redemptions to lower our annual cash net financing costs by approximately $70 million.
Credit Availability
As of September 30, 2021, 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 September 30, 2021, 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 positive outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Ba1 with a positive 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
Following the closing of the Merger, we initiated a new “fixed plus variable” dividend strategy. The fixed dividend is currently paid quarterly at a rate of $0.11 per share, and 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 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, COVID-19 impacts and other factors deemed relevant by the Board.
In November 2021, Devon announced a cash dividend in the amount of $0.84 per share payable in the fourth quarter of 2021. The dividend consists of a fixed quarterly dividend in the amount of approximately $74 million (or $0.11 per share) and a variable quarterly dividend in the amount of approximately $494 million (or $0.73 per share).
Capital Expenditures
Our 2021 exploration and development budget for the fourth quarter of 2021 is expected to range from approximately $440 million to $490 million.
Share Repurchases
In November 2021, our Board of Directors authorized a $1.0 billion share repurchase program, which expires December 31, 2022.
Critical Accounting Estimates
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. Due primarily to significant cumulative losses, we recorded a full valuation allowance against U.S. deferred tax assets in 2020 and remain in a partial valuation allowance position at September 30, 2021. Subject to any additional objective negative evidence or the addition of subjective evidence such as forecasted income, Devon may continue to adjust the valuation allowance on its deferred tax assets in future periods.
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 2021 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 three years.
Purchase Accounting
Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Merger with WPX. In connection with the Merger, as the accounting acquirer, we allocated the $5.4 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the date of the Merger. The preliminary purchase price assessment remains an ongoing process and is subject to change for up to one year subsequent to the closing date of the Merger.
We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the Merger. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. Since sufficient market data was not available regarding the fair values of proved and unproved oil and gas properties, we prepared estimates and engaged third party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of reserve quantities, estimates of future commodity prices, drilling plans, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflects the risk of the underlying cash flow estimates.
Estimated fair values ascribed to assets acquired can have a significant impact on future results of operations presented in Devon’s financial statements. A higher fair value ascribed to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserve quantities, development costs and operating costs. In the event that future commodity prices or reserve quantities are lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable.
In addition to the fair value of proved and unproved oil and gas properties, other significant fair value assessments for the assets acquired and liabilities assumed in the Merger relate to debt, the equity method investment in Catalyst and out-of-market contract assets and liabilities. The fair value of the assumed WPX publicly traded debt was based on available third party quoted prices. We prepared estimates and engaged third party valuation experts to assist in the valuation of the equity method investment in Catalyst. Significant judgments and assumptions inherent in this estimate included projected Catalyst cash flows, comparable companies cash flow multiples and an estimate of an applicable market participant discount rate. The fair value of assumed out-of-market contract assets and liabilities associated with longer-term marketing, gathering, processing and transportation contracts included significant judgments and assumptions related to determining the market rates, estimates of future reserves and production associated with the respective contracts and applying an applicable market participant discount rate.
For additional information regarding our critical accounting policies and estimates, see our 2020 Annual Report on Form 10-K.
Non-GAAP Measures
We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2021 Results” 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 (loss) 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, changes in tax legislation, 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 6.
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 September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Before Tax | After Tax | After Noncontrolling Interests | Per Diluted Share | Before Tax | After Tax | After Noncontrolling Interests | Per Diluted Share | ||||||||||||||||||||||||
| 2021 | |||||||||||||||||||||||||||||||
| Total | |||||||||||||||||||||||||||||||
| Earnings attributable to Devon (GAAP) | $ | 964 | $ | 844 | $ | 838 | $ | 1.24 | $ | 1,236 | $ | 1,321 | $ | 1,307 | $ | 1.95 | |||||||||||||||
| Adjustments: | |||||||||||||||||||||||||||||||
| Asset dispositions | — | — | — | — | (119 | ) | (91 | ) | (91 | ) | (0.13 | ) | |||||||||||||||||||
| Asset and exploration impairments | 1 | 1 | 1 | 0.00 | 3 | 2 | 2 | 0.00 | |||||||||||||||||||||||
| Deferred tax asset valuation allowance | — | (101 | ) | (101 | ) | (0.15 | ) | — | (479 | ) | (479 | ) | (0.71 | ) | |||||||||||||||||
| Change in tax legislation | — | — | — | — | — | 62 | 62 | 0.09 | |||||||||||||||||||||||
| Fair value changes in financial instruments and foreign currency | (31 | ) | (23 | ) | (23 | ) | (0.04 | ) | 597 | 460 | 460 | 0.68 | |||||||||||||||||||
| Restructuring and transaction costs | 18 | 18 | 18 | 0.03 | 230 | 201 | 201 | 0.29 | |||||||||||||||||||||||
| Early retirement of debt | — | — | — | — | (30 | ) | (23 | ) | (23 | ) | (0.03 | ) | |||||||||||||||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 952 | $ | 739 | $ | 733 | $ | 1.08 | $ | 1,917 | $ | 1,453 | $ | 1,439 | $ | 2.14 | |||||||||||||||
| 2020 | |||||||||||||||||||||||||||||||
| Continuing Operations | |||||||||||||||||||||||||||||||
| Loss attributable to Devon (GAAP) | $ | (193 | ) | $ | (103 | ) | $ | (105 | ) | $ | (0.29 | ) | $ | (2,980 | ) | $ | (2,470 | ) | $ | (2,475 | ) | $ | (6.58 | ) | |||||||
| Adjustments: | |||||||||||||||||||||||||||||||
| Asset and exploration impairments | 36 | 29 | 29 | 0.08 | 2,816 | 2,178 | 2,178 | 5.80 | |||||||||||||||||||||||
| Deferred tax asset valuation allowance | — | (5 | ) | (5 | ) | (0.01 | ) | — | 252 | 252 | 0.65 | ||||||||||||||||||||
| Fair value changes in financial instruments | 97 | 74 | 74 | 0.19 | 71 | 55 | 55 | 0.14 | |||||||||||||||||||||||
| Change in tax legislation | — | (43 | ) | (43 | ) | (0.11 | ) | — | (105 | ) | (105 | ) | (0.27 | ) | |||||||||||||||||
| Restructuring and transaction costs | 32 | 25 | 25 | 0.07 | 32 | 25 | 25 | 0.06 | |||||||||||||||||||||||
| Core loss attributable to Devon (Non-GAAP) | $ | (28 | ) | $ | (23 | ) | $ | (25 | ) | $ | (0.07 | ) | $ | (61 | ) | $ | (65 | ) | $ | (70 | ) | $ | (0.20 | ) | |||||||
| Discontinued Operations | |||||||||||||||||||||||||||||||
| Earnings (loss) attributable to Devon (GAAP) | $ | (2 | ) | $ | 13 | $ | 13 | $ | 0.04 | $ | (150 | ) | $ | (103 | ) | $ | (103 | ) | $ | (0.27 | ) | ||||||||||
| Adjustments: | |||||||||||||||||||||||||||||||
| Asset dispositions | — | — | — | — | (2 | ) | (1 | ) | (1 | ) | (0.00 | ) | |||||||||||||||||||
| Asset impairments | 3 | 3 | 3 | 0.00 | 182 | 143 | 143 | 0.37 | |||||||||||||||||||||||
| Fair value changes in foreign currency and other | (2 | ) | (3 | ) | (3 | ) | (0.01 | ) | 4 | 2 | 2 | 0.01 | |||||||||||||||||||
| Core earnings (loss) attributable to Devon (Non-GAAP) | $ | (1 | ) | $ | 13 | $ | 13 | $ | 0.03 | $ | 34 | $ | 41 | $ | 41 | $ | 0.11 | ||||||||||||||
| Total | |||||||||||||||||||||||||||||||
| Loss attributable to Devon (GAAP) | $ | (195 | ) | $ | (90 | ) | $ | (92 | ) | $ | (0.25 | ) | $ | (3,130 | ) | $ | (2,573 | ) | $ | (2,578 | ) | $ | (6.85 | ) | |||||||
| Adjustments: | |||||||||||||||||||||||||||||||
| Continuing Operations | 165 | 80 | 80 | 0.22 | 2,919 | 2,405 | 2,405 | 6.38 | |||||||||||||||||||||||
| Discontinued Operations | 1 | — | — | (0.01 | ) | 184 | 144 | 144 | 0.38 | ||||||||||||||||||||||
| Core loss attributable to Devon (Non-GAAP) | $ | (29 | ) | $ | (10 | ) | $ | (12 | ) | $ | (0.04 | ) | $ | (27 | ) | $ | (24 | ) | $ | (29 | ) | $ | (0.09 | ) |
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 from continuing operations 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 continuing operations.
Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | 2021 | 2020 | ||||||||||||
| Net earnings (loss) (GAAP) | $ | 844 | $ | (90 | ) | $ | 1,321 | $ | (2,573 | ) | |||||
| Net (earnings) loss from discontinued operations, net of tax | — | (13 | ) | — | 103 | ||||||||||
| Financing costs, net | 86 | 66 | 243 | 200 | |||||||||||
| Income tax expense (benefit) | 120 | (90 | ) | (85 | ) | (510 | ) | ||||||||
| Exploration expenses | 3 | 39 | 9 | 163 | |||||||||||
| Depreciation, depletion and amortization | 578 | 299 | 1,581 | 999 | |||||||||||
| Asset impairments | — | — | — | 2,666 | |||||||||||
| Asset dispositions | — | — | (119 | ) | — | ||||||||||
| Share-based compensation | 18 | 19 | 58 | 58 | |||||||||||
| Derivative and financial instrument non-cash valuation changes | (35 | ) | 97 | 597 | 71 | ||||||||||
| Restructuring and transaction costs | 18 | 32 | 230 | 32 | |||||||||||
| Accretion on discounted liabilities and other | 2 | — | (41 | ) | (35 | ) | |||||||||
| EBITDAX (Non-GAAP) | 1,634 | 359 | 3,794 | 1,174 | |||||||||||
| Marketing and midstream revenues and expenses, net | (1 | ) | 2 | 19 | 28 | ||||||||||
| Commodity derivative cash settlements | 370 | (10 | ) | 969 | (343 | ) | |||||||||
| General and administrative expenses, cash-based | 77 | 56 | 238 | 198 | |||||||||||
| Field-level cash margin (Non-GAAP) | $ | 2,080 | $ | 407 | $ | 5,020 | $ | 1,057 |
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