# Devon Energy Corp: Form 10-Q for the period ended Jun 30, 2021

- Company: [Devon Energy Corp](/companies/dvn.md) (CIK 1090012)
- Form: 10-Q
- Filed: 2021-08-04
- Accepted by EDGAR: Aug 4, 2021, 12:02 ET
- Period: 2021-06-30
- Accession: 0001564590-21-040600
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1090012/000156459021040600/dvn-10q_20210630.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1090012/000156459021040600/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2021-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2021-04-01 to 2021-06-30 | $3.12bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 6 months, 2021-01-01 to 2021-06-30 | $5.70bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Income tax | 3 months, 2021-04-01 to 2021-06-30 | $43.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2021-01-01 to 2021-06-30 | −$205.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2021-04-01 to 2021-06-30 | $256.0m | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2021-01-01 to 2021-06-30 | $469.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2021-04-01 to 2021-06-30 | $0.38 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2021-01-01 to 2021-06-30 | $0.70 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2021-04-01 to 2021-06-30 | $0.38 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2021-01-01 to 2021-06-30 | $0.70 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2021-04-01 to 2021-06-30 | 673,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2021-01-01 to 2021-06-30 | 662,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Capital expenditure | 3 months, 2021-04-01 to 2021-06-30 | $504.0m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Capital expenditure | 6 months, 2021-01-01 to 2021-06-30 | $1.00bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 3 months, 2021-04-01 to 2021-06-30 | $229.0m | us-gaap:PaymentsOfDividends |
| Dividends paid | 6 months, 2021-01-01 to 2021-06-30 | $432.0m | us-gaap:PaymentsOfDividends |
| Cash and equivalents | at 2021-06-30 | $1.35bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2021-06-30 | $3.08bn | us-gaap:AssetsCurrent |
| Total assets | at 2021-06-30 | $20.07bn | us-gaap:Assets |
| Current liabilities | at 2021-06-30 | $3.07bn | us-gaap:LiabilitiesCurrent |
| Long-term debt | at 2021-06-30 | $6.50bn | us-gaap:LongTermDebtNoncurrent |
| Shareholders' equity | at 2021-06-30 | $8.40bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 54,493 characters.

The following discussion and analysis addresses material changes in our results of operations for the three-month and six-month periods ended June 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 March 31, 2021, information regarding our first quarter 2021 financial results can be found in our First 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.”

### WPX Merger and Operating Results

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:

- Efficiency gains drove second quarter capital expenditures 9% below our plan.
- Second quarter Boe production totaled 567 MBoe/d, exceeding our plan by 3%.
- On pace to achieve approximately $600 million in annual cost savings by the end of 2021.
- Redeemed approximately $1.2 billion of senior notes in 2021.
- Exited the second quarter with $4.5 billion of liquidity, including $1.5 billion of cash, with no debt maturities until 2023.
- Including variable dividends, paid dividends of approximately $432 million in the first six months of 2021 and have declared $331 million of dividends to be paid in the third quarter of 2021.

### Overview of 2021 Results

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 environmental, social and governance 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, tailoring our capital investment to market conditions, improving our cash cost structure and preserving operational continuity.

After a significant downturn in economic activity in 2020 resulting from the unprecedented COVID-19 pandemic, economic activity has begun to recover, and commodity prices have continued to increase in 2021. However, we expect commodity prices to remain volatile with the emergence of COVID-19 variants and pending OPEC+ curtailment decisions. We will continue to evaluate the global impacts of COVID-19 as they evolve and will adapt accordingly as a company.

Trends of our quarterly earnings, operating cash flow, EBITDAX and capital expenditures are shown below. The quarterly earnings chart presents amounts pertaining to both Devon’s continuing and discontinued operations. The quarterly cash flow chart presents amounts pertaining to Devon’s continuing operations. Activity related to discontinued operations is only applicable for 2020 periods. “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 net earnings in recent quarters have been significantly impacted by divestiture transactions, asset impairments and temporary, 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.

Despite our portfolio enhancements, aggressive cost reductions and operational advancements, our financial results have been challenged by commodity prices and deterioration of the macro-economic environment resulting from the aforementioned COVID-19 pandemic; however, prices have begun to recover and increase significantly in 2021. Our earnings increased from the first quarter of 2021 to the second quarter of 2021 primarily due to an increase in overall commodity prices as well as higher sold volumes. Led by a 14% increase in WTI from the first quarter of 2021 to the second quarter of 2021, our unhedged combined realized price rose 7%. Volumes increased due to new well activity and restored production operations following winter storms in the first quarter.

Like earnings, our operating cash flow is sensitive to volatile commodity prices. EBITDAX, which excludes financial amounts related to discontinued operations, and operating cash flows have been impacted by the COVID-19 pandemic and its impact on commodity prices. Our cash flow increased during the first and second quarters of 2021 primarily due to higher commodity prices and an increase in sold volumes.

We exited the second quarter of 2021 with $4.5 billion of liquidity, comprised of $1.5 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 60% of our remaining 2021 oil and gas production hedged, respectively, and 20% and 25% 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.

### 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.

### Q2 2021 vs. Q1 2021

Our second quarter 2021 net earnings were $261 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 2021 to the second quarter of 2021. The material changes are further discussed by category on the following pages.

### Production Volumes

| Oil (MBbls/d) | Q2 2021 | % of Total | Q1 2021 | Change |
| --- | ---: | ---: | ---: | --- |
| Delaware Basin | 191 | 66% | 172 | +11% |
| Anadarko Basin | 17 | 6% | 13 | +29% |
| Williston Basin | 46 | 16% | 44 | +3% |
| Eagle Ford | 18 | 6% | 16 | +14% |
| Powder River Basin | 16 | 5% | 17 | - 4% |
| Other | 3 | 1% | 6 | - 45% |
| Total | 291 | 100% | 268 | +9% |

| Gas (MMcf/d) | Q2 2021 | % of Total | Q1 2021 | Change |
| --- | ---: | ---: | ---: | --- |
| Delaware Basin | 513 | 58% | 471 | +9% |
| Anadarko Basin | 225 | 26% | 200 | +13% |
| Williston Basin | 61 | 7% | 49 | +24% |
| Eagle Ford | 59 | 7% | 47 | +25% |
| Powder River Basin | 21 | 2% | 21 | +3% |
| Other | 2 | 0% | 3 | - 25% |
| Total | 881 | 100% | 791 | +11% |

| NGLs (MBbls/d) | Q2 2021 | % of Total | Q1 2021 | Change |
| --- | ---: | ---: | ---: | --- |
| Delaware Basin | 82 | 64% | 60 | +36% |
| Anadarko Basin | 26 | 20% | 21 | +21% |
| Williston Basin | 9 | 7% | 8 | +21% |
| Eagle Ford | 9 | 7% | 6 | +39% |
| Powder River Basin | 3 | 2% | 3 | - 4% |
| Other | — | 0% | 1 | - 100% |
| Total | 129 | 100% | 99 | +30% |

| Combined (MBoe/d) | Q2 2021 | % of Total | Q1 2021 | Change |
| --- | ---: | ---: | ---: | --- |
| Delaware Basin | 358 | 63% | 310 | +16% |
| Anadarko Basin | 80 | 14% | 68 | +18% |
| Williston Basin | 66 | 12% | 61 | +8% |
| Eagle Ford | 37 | 6% | 30 | +21% |
| Powder River Basin | 22 | 4% | 23 | - 3% |
| Other | 4 | 1% | 7 | - 43% |
| Total | 567 | 100% | 499 | +14% |

From the first quarter of 2021 to the second quarter of 2021, the change in volumes contributed to a $229 million increase in earnings. The increase in volumes was primarily due to downtime in the first quarter related to the February winter storm and new well activity in the second quarter in the Delaware Basin. Volumes in the third quarter are expected to range from approximately 566 to 594 MBoe/d.

### Realized Prices

| Oil (per Bbl) | Q2 2021 | Realization | Q1 2021 | Change |
| --- | ---: | ---: | ---: | --- |
| WTI index | $66.04 |  | $57.87 | +14% |
| Realized price, unhedged | $63.63 | 96% | $55.28 | +15% |
| Cash settlements | $(13.29) |  | $(9.13) |  |
| Realized price, with hedges | $50.34 | 76% | $46.15 | +9% |

| Gas (per Mcf) | Q2 2021 | Realization | Q1 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| Henry Hub index | $2.83 |  | $2.71 | +4% |
| Realized price, unhedged | $2.35 | 83% | $2.84 | - 17% |
| Cash settlements | $(0.15) |  | $(0.15) |  |
| Realized price, with hedges | $2.20 | 78% | $2.69 | - 18% |

| NGLs (per Bbl) | Q2 2021 | Realization | Q1 2021 | Change |
| --- | ---: | ---: | ---: | ---: |
| WTI index | $66.04 |  | $57.87 | +14% |
| Realized price, unhedged | $23.89 | 36% | $25.01 | - 4% |
| Cash settlements | $(0.25) |  | $(0.20) |  |
| Realized price, with hedges | $23.64 | 36% | $24.81 | - 5% |

| Combined (per Boe) | Q2 2021 | Q1 2021 | Change |
| --- | ---: | ---: | --- |
| Realized price, unhedged | $41.75 | $39.14 | +7% |
| Cash settlements | $(7.11) | $(5.17) |  |
| Realized price, with hedges | $34.64 | $33.97 | +2% |

From the first quarter of 2021 to the second quarter of 2021, field prices contributed to a $168 million increase in earnings. Unhedged realized oil prices increased primarily due to higher WTI index prices. This was partially offset by lower unhedged realized gas and NGL prices which was primarily due to higher first quarter pricing contracts resulting from the winter storm and increased ethane rejection, respectively. The increase in WTI was also partially offset by an increase in hedge cash settlement payments.

We currently have approximately 45% of our remaining 2021 oil production hedged with an average floor price of $40/Bbl and approximately 60% of our remaining 2021 gas production hedged with an average floor price of $2.57/Mcf. We currently have approximately 20% of our 2022 oil production hedged with an average floor price of $45/Bbl and approximately 25% of our 2022 gas production hedged with an average floor price of $2.64/Mcf.

### Hedge Settlements

|  | Q2 2021 Q | Q1 2021 | Change |
| --- | ---: | ---: | ---: |
| Oil | $(352) | $(220) | - 60% |
| Natural gas | (12) | (10) | - 20% |
| NGL | (3) | (2) | - 50% |
| Total cash settlements (1) | $(367) | $(232) | - 58% |

(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

|  | Q2 2021 | Q1 2021 | Change |
| --- | ---: | ---: | --- |
| LOE | $210 | $199 | +6% |
| Gathering, processing & transportation | 147 | 129 | +14% |
| Production taxes | 143 | 117 | +22% |
| Property taxes | 13 | 13 | +0% |
| Total | $513 | $458 | +12% |
| Per Boe: |  |  |  |
| LOE | $4.06 | $4.44 | - 9% |
| Gathering, processing & transportation | $2.85 | $2.87 | - 1% |
| Percent of oil, gas and NGL sales: |  |  |  |
| Production taxes | 6.7% | 6.6% | +1% |

Production expenses increased from the first quarter of 2021 to the second quarter of 2021 primarily due to the activity impacts from the February 2021 winter storm and new well activity in the second quarter. 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.

| Field-level cash margin (Non-GAAP) | Q2 2021 | $ per BOE | Q1 2021 | $ per BOE |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | $1,102 | $33.79 | $895 | $32.07 |
| Anadarko Basin | 145 | $19.86 | 85 | $14.01 |
| Williston Basin | 197 | $32.98 | 161 | $29.70 |
| Eagle Ford | 106 | $31.88 | 72 | $26.57 |
| Powder River Basin | 74 | $36.78 | 67 | $31.99 |
| Other | 17 | $42.85 | 19 | $28.21 |
| Total | $1,641 | $31.79 | $1,299 | $28.95 |

### DD&A and Asset Impairments

|  | Q2 2021 | Q1 2021 | Change |
| --- | ---: | ---: | --- |
| Oil and gas per Boe | $9.88 | $9.78 | +1% |
| Oil and gas | $510 | $439 | +16% |
| Other property and equipment | $26 | 28 | - 7% |
| Total | $536 | $467 | +15% |

DD&A increased in the second quarter of 2021 primarily due to higher volumes.

### General and Administrative Expense

|  | Q2 2021 | Q1 2021 | Change |
| --- | ---: | ---: | ---: |
| G&A per Boe | $1.81 | $2.40 | - 25% |
| Labor and benefits | $60 | $72 | - 17% |
| Non-labor | 34 | 35 | - 3% |
| Total | $94 | $107 | - 12% |

G&A decreased primarily as a result of lower employee costs and benefits.

### Other Items

|  | Q2 2021 | Q1 2021 | Change in earnings |
| --- | ---: | ---: | ---: |
| Commodity hedge valuation changes (1) | $(336) | $(296) | $(40) |
| Marketing and midstream operations | 1 | (21) | 22 |
| Exploration expenses | 3 | 3 | — |
| Asset dispositions | (87) | (32) | 55 |
| Net financing costs | 80 | 77 | (3) |
| Restructuring and transaction costs | 23 | 189 | 166 |
| Other, net | (14) | (29) | (15) |
|  |  |  | $185 |

(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 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.

Restructuring and transaction costs reflect workforce reductions in conjunction with the Merger, as well as various transaction costs related to the Merger. The majority of these costs were recorded in the first quarter of 2021. For additional information, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

### Income Taxes

|  | Q2 2021 | Q1 2021 |
| --- | ---: | ---: |
| Current expense (benefit) | $19 | $(5) |
| Deferred expense (benefit) | 24 | (243) |
| Total expense (benefit) | $43 | $(248) |
| Effective income tax rate | 14% | 763% |

For discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

### June 30, YTD 2021 vs. June 30, YTD 2020

Our six months ended June 30, 2021 net earnings were $477 million, compared to a net loss of $2.4 billion (excludes discontinued operations) for the six months ended June 30, 2020. The graph below shows the change in the net earnings (loss) from the six months ended June 30, 2020 to the six months ended June 30, 2021. The material changes are further discussed by category on the following pages.

### Production Volumes

| Oil (MBbls/d) | Six Months Ended June 30, 2021 | % of Total | 2020 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 181 | 65% | 81 | +123% |
| Anadarko Basin | 15 | 5% | 22 | - 34% |
| Williston Basin | 45 | 16% | — | N/M |
| Eagle Ford | 17 | 6% | 27 | - 37% |
| Powder River Basin | 16 | 6% | 20 | - 17% |
| Other | 5 | 2% | 8 | - 40% |
| Total | 279 | 100% | 158 | +77% |

| Gas (MMcf/d) | Six Months Ended June 30, 2021 | % of Total | 2020 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 492 | 59% | 242 | +103% |
| Anadarko Basin | 213 | 25% | 267 | - 20% |
| Williston Basin | 55 | 7% | — | N/M |
| Eagle Ford | 53 | 6% | 87 | - 39% |
| Powder River Basin | 21 | 3% | 24 | - 13% |
| Other | 2 | 0% | 4 | - 39% |
| Total | 836 | 100% | 624 | +34% |

| NGLs (MBbls/d) | Six Months Ended June 30, 2021 | % of Total | 2020 | Change |
| --- | ---: | ---: | ---: | --- |
| Delaware Basin | 71 | 62% | 33 | +114% |
| Anadarko Basin | 23 | 21% | 28 | - 15% |
| Williston Basin | 9 | 8% | — | N/M |
| Eagle Ford | 8 | 7% | 10 | - 26% |
| Powder River Basin | 3 | 2% | 3 | +7% |
| Other | — | 0% | 1 | - 100% |
| Total | 114 | 100% | 75 | +53% |

| Combined (MBoe/d) | Six Months Ended June 30, 2021 | % of Total | 2020 | Change |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | 334 | 63% | 155 | +116% |
| Anadarko Basin | 74 | 14% | 94 | - 22% |
| Williston Basin | 63 | 12% | — | N/M |
| Eagle Ford | 33 | 6% | 52 | - 35% |
| Powder River Basin | 23 | 4% | 27 | - 14% |
| Other | 6 | 1% | 9 | - 38% |
| Total | 533 | 100% | 337 | +58% |

From the six months ended 2020 to the six months ended 2021, the change in volumes contributed to an $841 million 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 219 MBoe/d for the six months ended 2021. Continued development of Devon legacy assets in the Delaware Basin also increased volumes. These increases were partially offset by impacts of the February 2021 winter storm and reduced activity across Devon’s remaining assets.

### Realized Prices

| Oil (per Bbl) | Six Months Ended June 30, 2021 | Realization | 2020 | Change |
| --- | ---: | ---: | ---: | --- |
| WTI index | $61.95 |  | $37.43 | +66% |
| Realized price, unhedged | $59.65 | 96% | $33.27 | +79% |
| Cash settlements | $(11.30) |  | $10.04 |  |
| Realized price, with hedges | $48.35 | 78% | $43.31 | +12% |

| Gas (per Mcf) | Six Months Ended June 30, 2021 | Realization | 2020 | Change |
| --- | ---: | ---: | ---: | --- |
| Henry Hub index | $2.77 |  | $1.83 | +51% |
| Realized price, unhedged | $2.58 | 93% | $1.25 | +106% |
| Cash settlements | $(0.15) |  | $0.32 |  |
| Realized price, with hedges | $2.43 | 88% | $1.57 | +55% |

| NGLs (per Bbl) | Six Months Ended June 30, 2021 | Realization | 2020 | Change |
| --- | ---: | ---: | ---: | --- |
| WTI index | $61.95 |  | $37.43 | +66% |
| Realized price, unhedged | $24.37 | 39% | $9.70 | +151% |
| Cash settlements | $(0.23) |  | $0.56 |  |
| Realized price, with hedges | $24.14 | 39% | $10.26 | +135% |

| Combined (per Boe) | Six Months Ended June 30, 2021 | 2020 | Change |
| --- | ---: | ---: | --- |
| Realized price, unhedged | $40.54 | $20.09 | +102% |
| Cash settlements | $(6.21) | $5.43 |  |
| Realized price, with hedges | $34.33 | $25.52 | +35% |

From the six months ended 2020 to the six months ended 2021, field prices contributed to a $1.8 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 a decrease in hedge cash settlements related to all products.

### Hedge Settlements

|  | Six Months Ended June 30, 2021 | 2020 | Change |
| --- | ---: | ---: | ---: |
| Oil | $(572) | $289 | - 298% |
| Natural gas | (22) | 36 | - 161% |
| NGL | (5) | 8 | - 163% |
| Total cash settlements (1) | $(599) | $333 | - 280% |

(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

|  | Six Months Ended June 30, 2021 | 2020 | Change |
| --- | ---: | ---: | --- |
| LOE | $409 | $234 | +75% |
| Gathering, processing & transportation | 276 | 253 | +9% |
| Production taxes | 260 | 81 | +221% |
| Property taxes | 26 | 13 | +100% |
| Total | $971 | $581 | +67% |
| Per Boe: |  |  |  |
| LOE | $4.24 | $3.83 | +11% |
| Gathering, processing & transportation | $2.86 | $4.13 | - 31% |
| Percent of oil, gas and NGL sales: |  |  |  |
| Production taxes | 6.7% | 6.6% | +2% |

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 $23 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.

| Field-level cash margin (Non-GAAP) | Six Months Ended June 30, 2021 | $ per BOE | 2020 | $ per BOE |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | $1,997 | $33.00 | $366 | $12.97 |
| Anadarko Basin | 230 | $17.20 | 87 | $5.09 |
| Williston Basin | 358 | $31.42 | — | N/M |
| Eagle Ford | 178 | $29.50 | 109 | $11.58 |
| Powder River Basin | 141 | $34.36 | 74 | $15.31 |
| Other | 36 | $33.43 | 14 | $8.16 |
| Total | $2,940 | $30.48 | $650 | $10.60 |

### DD&A and Asset Impairments

|  | Six Months Ended June 30, 2021 | 2020 | Change |
| --- | ---: | ---: | --- |
| Oil and gas per Boe | $9.83 | $10.66 | - 8% |
| Oil and gas | $949 | $653 | +45% |
| Other property and equipment | 54 | 47 | +17% |
| Total | $1,003 | $700 | +43% |
| 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 six months ended 2020 due to significant decreases in commodity prices resulting primarily from the COVID-19 pandemic. These impairments resulted in lower DD&A rates in 2021 compared to 2020. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

### General and Administrative Expense

|  | Six Months Ended June 30, 2021 | 2020 | Change |
| --- | ---: | ---: | ---: |
| G&A per Boe | $2.08 | $2.96 | - 30% |
| Labor and benefits | $132 | $111 | +19% |
| Non-labor | 69 | 70 | - 1% |
| Total | $201 | $181 | +11% |

Labor and benefits increased primarily due to the Merger closing on January 7, 2021. However, Devon’s G&A per Boe rate decreased 30% primarily due to synergies created by the Merger.

### Other Items

|  | Six Months Ended June 30, 2021 | 2020 | Change in earnings |
| --- | ---: | ---: | ---: |
| Commodity hedge valuation changes (1) | $(632) | $26 | $(658) |
| Marketing and midstream operations | (20) | (26) | 6 |
| Exploration expenses | 6 | 124 | 118 |
| Asset dispositions | (119) | — | 119 |
| Net financing costs | 157 | 134 | (23) |
| Restructuring and transaction costs | 212 | — | (212) |
| Other, net | (43) | (35) | 8 |
|  |  |  | $(642) |

(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 $113 million in the first six 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. 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 six 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 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

|  | Six Months Ended June 30, 2021 | 2020 |
| --- | ---: | ---: |
| Current expense (benefit) | $14 | $(109) |
| Deferred benefit | (219) | (311) |
| Total benefit | $(205) | $(420) |
| Effective income tax rate | (75%) | 15% |

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 six months ended June 30, 2021 and 2020.

|  | Three Months Ended June 30, 2021 | 2020 | Six Months Ended June 30, 2021 | 2020 |
| --- | ---: | ---: | ---: | ---: |
| Operating cash flow from continuing operations | $1,093 | $150 | $1,685 | $679 |
| WPX acquired cash | — | — | 344 | — |
| Divestitures of property and equipment | 49 | 3 | 64 | 28 |
| Capital expenditures | (504) | (307) | (1,003) | (732) |
| Debt activity, net | (742) | — | (1,302) | — |
| Repurchases of common stock | — | — | — | (38) |
| Common stock dividends | (229) | (42) | (432) | (76) |
| Noncontrolling interest activity, net | (2) | 3 | (30) | 5 |
| Other | (4) | (1) | (24) | (22) |
| Net change in cash, cash equivalents and restricted cash from discontinued operations | — | 136 | — | (19) |
| Net change in cash, cash equivalents and restricted cash | $(339) | $(58) | $(698) | $(175) |
| Cash, cash equivalents and restricted cash at end of period | $1,539 | $1,669 | $1,539 | $1,669 |

#### 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 grew approximately 150% during the six months ended June 30, 2021 compared to the six months ended June 30, 2020. The increase was due to the Merger and prices significantly increasing in the first half of 2021. 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 six months of 2021, we sold non-core assets for approximately $64 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 June 30, 2021 | 2020 | Six Months Ended June 30, 2021 | 2020 |
| --- | ---: | ---: | ---: | ---: |
| Delaware Basin | $378 | $192 | $775 | $413 |
| Anadarko Basin | 9 | 10 | 18 | 18 |
| Williston Basin | 18 | — | 46 | — |
| Eagle Ford | 29 | 42 | 43 | 136 |
| Powder River Basin | 7 | 46 | 40 | 131 |
| Other | — | 3 | — | 6 |
| Total oil and gas | 441 | 293 | 922 | 704 |
| Midstream | 43 | 11 | 48 | 19 |
| Other | 20 | 3 | 33 | 9 |
| Total capital expenditures | $504 | $307 | $1,003 | $732 |

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 or near operating cash flow. This is evidenced by our operating cash flow funding all of our capital expenditures for the six months ended June 30, 2021. Our capital investment program is driven by a disciplined allocation process focused on returns. Our capital expenditures are expected to range between $1.7 billion to $2.0 billion for the full year 2021.

#### Debt Activity

Subsequent to the Merger closing, we redeemed $1.2 billion of senior notes in the first half 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 second quarter and total for the first six 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 the first and second quarters of 2021.

| 2021: | Fixed | Variable | Total | Rate Per Share |
| --- | ---: | ---: | ---: | ---: |
| First quarter | $76 | $127 | $203 | $0.30 |
| Second quarter | 75 | 154 | 229 | $0.34 |
| Total year-to-date | $151 | $281 | $432 |  |
| 2020: |  |  |  |  |
| First quarter | $34 | $— | $34 | $0.09 |
| Second quarter | 42 | — | 42 | $0.11 |
| Total year-to-date | $76 | $— | $76 |  |

We repurchased 2.2 million shares of common stock for $38 million in the first six months of 2020. For additional information, see Note 17 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

#### Noncontrolling Interest Activity, net

During the first six months of 2021, we received $3 million of contributions from our noncontrolling interests in CDM and distributed $9 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 six months of 2020, we received $11 million in contributions from our noncontrolling interests in CDM and distributed $6 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 are accelerating 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 is expected to enhance Devon’s free cash flow, credit profile and decrease 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 second quarter of 2021, we held approximately $1.5 billion of cash, inclusive of $191 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 June 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.

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 six months of 2021 and the remaining costs will be paid mostly over the remaining six 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 June 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 June 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 stable outlook. Our credit rating from Fitch is BBB with a positive 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 percent 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 August 2021, Devon announced a cash dividend in the amount of $0.49 per share payable in the third 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 $257 million (or $0.38 per share).

#### Capital Expenditures

Our 2021 exploration and development budget for the remainder of 2021 is expected to range from approximately $700 million to $900 million.

### 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 full valuation allowance position at June 30, 2021. However, absent any additional objective negative evidence, and with the addition of subjective evidence such as forecasted taxable income, we may adjust the valuation allowance 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. No 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.

| 2021 Total | Three Months Ended June 30, Before Tax | After Tax | After Noncontrolling Interests | Per Diluted Share | Six Months Ended June 30, Before Tax | After Tax | After Noncontrolling Interests | Per Diluted Share |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Earnings attributable to Devon (GAAP) | $304 | $261 | $256 | $0.38 | $272 | $477 | $469 | $0.70 |
| Adjustments: |  |  |  |  |  |  |  |  |
| Asset dispositions | (87) | (67) | (67) | (0.10) | (119) | (91) | (91) | (0.13) |
| Asset and exploration impairments | 1 | 1 | 1 | 0.00 | 2 | 1 | 1 | 0.00 |
| Deferred tax asset valuation allowance | — | (115) | (115) | (0.17) | — | (378) | (378) | (0.57) |
| Change in tax legislation | — | 62 | 62 | 0.09 | — | 62 | 62 | 0.09 |
| Fair value changes in financial instruments and foreign currency | 334 | 258 | 258 | 0.38 | 628 | 483 | 483 | 0.72 |
| Restructuring and transaction costs | 23 | 21 | 21 | 0.03 | 212 | 183 | 183 | 0.28 |
| Early retirement of debt | (10) | (8) | (8) | (0.01) | (30) | (23) | (23) | (0.03) |
| Core earnings attributable to Devon (Non-GAAP) | $565 | $413 | $408 | $0.60 | $965 | $714 | $706 | $1.06 |
| **2020** |  |  |  |  |  |  |  |  |
| **Continuing Operations** |  |  |  |  |  |  |  |  |
| Loss attributable to Devon (GAAP) | $(680) | $(677) | $(679) | $(1.80) | $(2,787) | $(2,367) | $(2,370) | $(6.29) |
| Adjustments: |  |  |  |  |  |  |  |  |
| Asset and exploration impairments | 4 | 3 | 3 | 0.01 | 2,780 | 2,149 | 2,149 | 5.71 |
| Deferred tax asset valuation allowance | — | 149 | 149 | 0.39 | — | 257 | 257 | 0.67 |
| Fair value changes in financial instruments | 593 | 459 | 459 | 1.22 | (26) | (20) | (20) | (0.05) |
| Change in tax legislation | — | — | — | — | — | (62) | (62) | (0.16) |
| Core loss attributable to Devon (Non-GAAP) | $(83) | $(66) | $(68) | $(0.18) | $(33) | $(43) | $(46) | $(0.12) |
| **Discontinued Operations** |  |  |  |  |  |  |  |  |
| Earnings (loss) attributable to Devon (GAAP) | $9 | $9 | $9 | $0.02 | $(148) | $(116) | $(116) | $(0.31) |
| Adjustments: |  |  |  |  |  |  |  |  |
| Asset dispositions | (2) | (1) | (1) | (0.00) | (2) | (1) | (1) | (0.00) |
| Asset impairments | — | — | — | — | 179 | 141 | 141 | 0.37 |
| Fair value changes in foreign currency and other | (5) | (6) | (6) | (0.02) | 5 | 4 | 4 | 0.01 |
| Core earnings attributable to Devon (Non-GAAP) | $2 | $2 | $2 | $0.00 | $34 | $28 | $28 | $0.07 |
| **Total** |  |  |  |  |  |  |  |  |
| Loss attributable to Devon (GAAP) | $(671) | $(668) | $(670) | $(1.78) | $(2,935) | $(2,483) | $(2,486) | $(6.60) |
| Adjustments: |  |  |  |  |  |  |  |  |
| Continuing Operations | 597 | 611 | 611 | 1.62 | 2,754 | 2,324 | 2,324 | 6.17 |
| Discontinued Operations | (7) | (7) | (7) | (0.02) | 182 | 144 | 144 | 0.38 |
| Core earnings (loss) attributable to Devon (Non-GAAP) | $(81) | $(64) | $(66) | $(0.18) | $1 | $(15) | $(18) | $(0.05) |

### 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 June 30, 2021 | 2020 | Six Months Ended June 30, 2021 | 2020 |
| --- | ---: | ---: | ---: | ---: |
| **Net earnings (loss) (GAAP)** | $261 | $(668) | $477 | $(2,483) |
| Net (earnings) loss from discontinued operations, net of tax | — | (9) | — | 116 |
| Financing costs, net | 80 | 69 | 157 | 134 |
| Income tax expense (benefit) | 43 | (3) | (205) | (420) |
| Exploration expenses | 3 | 12 | 6 | 124 |
| Depreciation, depletion and amortization | 536 | 299 | 1,003 | 700 |
| Asset impairments | — | — | — | 2,666 |
| Asset dispositions | (87) | — | (119) | — |
| Share-based compensation | 20 | 19 | 40 | 39 |
| Derivative and financial instrument non-cash valuation changes | 336 | 593 | 632 | (26) |
| Restructuring and transaction costs | 23 | — | 212 | — |
| Accretion on discounted liabilities and other | (14) | 13 | (43) | (35) |
| **EBITDAX (Non-GAAP)** | 1,201 | 325 | 2,160 | 815 |
| Marketing and midstream revenues and expenses, net | (1) | 8 | 20 | 26 |
| Commodity derivative cash settlements | 367 | (232) | 599 | (333) |
| General and administrative expenses, cash-based | 74 | 60 | 161 | 142 |
| **Field-level cash margin (Non-GAAP)** | $1,641 | $161 | $2,940 | $650 |

42

## Market risk

As filed, 904 characters.

### Commodity Price Risk

As of June 30, 2021, we have commodity derivatives that pertain to a portion of our estimated production for the last six months of 2021, as well as for 2022, 2023 and 2024. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At June 30, 2021, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by approximately $335 million.

### Interest Rate Risk

As of June 30, 2021, we had total debt of $6.5 billion. All of our debt is based on fixed interest rates averaging 5.7%.

### Foreign Currency Risk

We had no material foreign currency risk at June 30, 2021.

## Controls and procedures

As filed, 1,566 characters.

### Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of June 30, 2021 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

### Changes in Internal Control Over Financial Reporting

In conjunction with the Merger closing, we have integrated WPX’s operations into our overall system of internal controls over financial reporting and they are now included in our assessment of the effectiveness of our internal controls over financial reporting. For additional information regarding the Merger, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

There were no other changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 130 characters.

There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2020 Annual Report on Form 10-K.

Filed Aug 4, 2021.
Source: SEC EDGAR, the filing index for accession 0001564590-21-040600. Last ingested by Listed: Nov 5, 2026, 18:03 ET. No prices; not investment advice.