filings.toolsItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.
Overview of 2018 Results
2018 was a pivotal year for Devon as we took several significant steps toward achieving our long-term strategic goals. Operationally, we successfully transitioned our U.S. oil business into full-field development, which resulted in high-return, light-oil production advancing 14 percent in 2018. In addition to this strong operating performance, we made substantial progress high-grading our asset portfolio, building per-share value through our share-repurchase program and reducing our financial leverage by more than 40 percent.
| • | Increased STACK and Delaware Basin production 27% in 2018 compared to 2017. |
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| • | Maintained our 2018 capital expenditure forecast. |
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| • | Substantially achieved $5.0 billion in asset sales, including the monetization of EnLink and the General Partner. |
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| • | Repurchased $3.0 billion of common stock, representing a 14% share count reduction since December 31, 2017. |
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| • | Reduced long-term debt by $922 million, which is expected to reduce annualized financing costs by $66 million. |
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| • | Completed workforce reduction and cost reduction initiatives expected to generate $150 million of annualized savings. |
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| • | Increased our quarterly common stock dividend 33% to $0.08 per share beginning in the second quarter of 2018. |
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| • | Exited 2018 with $2.4 billion of cash and $2.9 billion of available credit under our Senior Credit Facility and have no significant debt maturities until 2021. |
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 | As presented in the graph at the left, our operating achievements are subject to the volatility of commodity prices. Over the last four years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from an average high of $64.79 per Bbl and $3.11 per MMBtu, respectively, to an average low of $43.36 per Bbl and $2.46 per MMBtu, respectively. Widening Western Canadian Select differentials negatively impacted the prices we realized on our heavy oil production in the fourth quarter of 2018. In the first two months of 2019, Western Canadian Select differentials have improved significantly. | |
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| Key measures of our financial performance in 2018 are summarized in the following table. Increased oil and natural gas liquids prices as well as continued focus cost management improved our 2018 financial performance as compared to 2017, as seen in the table below. Additionally, we recognized a gain of approximately $2.6 billion ($2.2 billion after-tax) related to the sale of EnLink and the General Partner during 2018. More details for these metrics are found within the “Results of Operations – 2018 vs. 2017” below. |
| 2018 | Change | 2017 | Change | 2016 | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Total: | ||||||||||||||||||||
| Net earnings (loss) attributable to Devon | $ | 3,064 | +241 | % | $ | 898 | +185 | % | $ | (1,056 | ) | |||||||||
| Net earnings (loss) per diluted share attributable to Devon | $ | 6.10 | +259 | % | $ | 1.70 | +181 | % | $ | (2.09 | ) | |||||||||
| Core earnings (loss) attributable to Devon (1) | $ | 655 | +53 | % | $ | 427 | +216 | % | $ | (367 | ) | |||||||||
| Core earnings (loss) attributable to Devon per diluted share (1) | $ | 1.30 | +60 | % | $ | 0.81 | +212 | % | $ | (0.73 | ) | |||||||||
| Continuing Operations: | ||||||||||||||||||||
| Net earnings (loss) | $ | 764 | +1 | % | $ | 758 | +232 | % | $ | (574 | ) | |||||||||
| Net earnings (loss) per diluted share | $ | 1.52 | +6 | % | $ | 1.43 | +225 | % | $ | (1.14 | ) | |||||||||
| Core earnings (loss) (1) | $ | 587 | +48 | % | $ | 397 | +207 | % | $ | (371 | ) | |||||||||
| Core earnings (loss) per diluted share (1) | $ | 1.17 | +57 | % | $ | 0.75 | +202 | % | $ | (0.73 | ) | |||||||||
| Discontinued Operations: | ||||||||||||||||||||
| Net earnings (loss) attributable to Devon | $ | 2,300 | +1543 | % | $ | 140 | +129 | % | $ | (481 | ) | |||||||||
| Net earnings (loss) per diluted share attributable to Devon | $ | 4.58 | +1596 | % | $ | 0.27 | +128 | % | $ | (0.95 | ) | |||||||||
| Core earnings attributable to Devon (1) | $ | 68 | +127 | % | $ | 30 | +580 | % | $ | 4 | ||||||||||
| Core earnings attributable to Devon per diluted share (1) | $ | 0.13 | +120 | % | $ | 0.06 | +1628 | % | $ | 0.00 | ||||||||||
| Other Metrics: | ||||||||||||||||||||
| Retained production (MBoe/d) | 500 | +4 | % | 481 | - 3 | % | 497 | |||||||||||||
| Total production (MBoe/d) | 535 | - 2 | % | 543 | - 11 | % | 611 | |||||||||||||
| Realized price per Boe (2) | $ | 29.08 | +12 | % | $ | 25.96 | +39 | % | $ | 18.72 | ||||||||||
| Operating cash flow from continuing operations | $ | 2,228 | +1 | % | $ | 2,209 | +165 | % | $ | 834 | ||||||||||
| Capitalized expenditures, including acquisitions | $ | 2,576 | +19 | % | $ | 2,169 | - 23 | % | $ | 2,826 | ||||||||||
| Cash and cash equivalents | $ | 2,414 | - 9 | % | $ | 2,642 | +36 | % | $ | 1,947 | ||||||||||
| Total debt | $ | 5,947 | - 13 | % | $ | 6,864 | +0 | % | $ | 6,859 | ||||||||||
| Reserves (MMBoe) | 1,927 | - 10 | % | 2,152 | +5 | % | 2,058 |
| (1) | Core earnings and core earnings per share attributable to Devon are financial measures not prepared in accordance with GAAP. For a description of core earnings and core earnings per share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7. |
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| (2) | Excludes any impact of oil, gas and NGL derivatives. |
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Business and Industry Outlook
Market prices for crude oil and natural gas are inherently volatile. Therefore, we cannot predict with certainty the future prices for the commodities we produce and sell. In 2018, WTI oil prices averaged approximately $67/Bbl through October, supported by stronger-than-expected oil demand, market management by both OPEC and non-OPEC partners and unplanned supply outages. However, oil prices markedly declined in November and December, averaging approximately $53/Bbl and reaching as low as $42.53/Bbl in December. The deterioration of WTI was driven by OPEC and non-OPEC partners unwinding their production cut agreement, compounded by rising supply and concerns over slowing global economic growth. Western Canadian Select basis differentials were challenged in the fourth quarter of 2018 due to robust production outpacing local demand, pipeline capacity and rail capacity out of the region. Looking ahead, current market fundamentals indicate that 2019 crude pricing is expected to improve from its fourth quarter 2018 levels. Additionally, Western Canadian Select differentials are also projected to improve, driven by provincially mandated production cuts combined with takeaway capacity additions expected in late 2019. Changes in OPEC production strategies, the macro-economic environment, geopolitical risks and other factors could impact our current forecasts.
In 2018, Devon marked its 30th year as a public company and 47th anniversary in the oil and gas business, so we are experienced in dealing with the volatile nature of commodity prices. To mitigate our exposure to commodity market volatility and ensure our financial strength, we use a disciplined, risk-management hedging program. Our hedging program incorporates both systematic hedges added on a regular basis and discretionary hedges layered in on an opportunistic basis to take advantage of favorable market conditions. We have approximately 50% of our anticipated 2019 oil and gas volumes hedged, and we are currently adding hedges for 2020 as well. Further insulating our cash flow, we are proactively locking in hedges on the Western Canadian Select basis differential to WTI and currently have approximately 50% of our 2019 Canadian heavy oil production hedged.
Despite the uncertainties pertaining to commodity prices, we remain focused on our strategic priorities of having a premier portfolio of assets, delivering superior execution as we drill and operate oil and natural gas wells, and maintaining our financial strength and flexibility. 2019 will be an important year for Devon as we plan to separate our Canadian and Barnett Shale assets and complete our multi-year transition to a U.S. oil company with operations focused on four core areas in the Delaware Basin, STACK, Eagle Ford and Rockies. With a focused portfolio of U.S. oil assets, we also intend to optimize our cost structure by reducing our annual capital costs, G&A costs, interest expense and production expenses by $780 million in the aggregate by 2021. We expect to deliver 70% of these annualized cost savings in 2019, as the Canadian and Barnett Shale assets are separated, and we align our workforce with the retained business and reduce outstanding debt.
Importantly, the portfolio changes and optimized cost performance are expected to enhance our competitive positioning as oil production growth, price realizations, field-level margins and corporate rates-of-return should all improve. With these improved expected outcomes, we remained focused on our 2019 capital allocation priorities of funding our core operations, protecting our investment-grade credit ratings and paying our shareholder dividend. Further, when considering the current commodity price environment and our current hedge position, we can achieve all our capital allocation priorities at $46/Bbl WTI and $3.00/Mcf Henry Hub. Should WTI drop closer to $40/Bbl for an extended period, we would shift our focus to preserving our financial strength and operational continuity. However, as WTI rises above $46/Bbl, our free cash flow will accelerate, providing additional capital allocation opportunities.
Results of Operations – 2018 vs. 2017
The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Specifically, the graph below shows the change in net earnings from 2017 to 2018. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.
| (1) | Other in the table above includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses. |
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The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph.
| (2) | As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” in this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $254 million during 2018 with no impact to net earnings. |
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| Upstream Operations |
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Oil, Gas and NGL Production
| 2018 | % of Total | 2017 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil and bitumen (MBbls/d) | ||||||||||||||||
| Delaware Basin | 42 | 17 | % | 29 | +42 | % | ||||||||||
| STACK | 32 | 13 | % | 25 | +28 | % | ||||||||||
| Rockies Oil | 14 | 6 | % | 10 | +37 | % | ||||||||||
| Heavy Oil | 18 | 7 | % | 18 | +1 | % | ||||||||||
| Eagle Ford | 28 | 12 | % | 34 | - 17 | % | ||||||||||
| Barnett Shale | 1 | 0 | % | 1 | - 7 | % | ||||||||||
| Other | 5 | 2 | % | 5 | - 3 | % | ||||||||||
| Retained assets | 140 | 57 | % | 122 | +14 | % | ||||||||||
| U.S. divested assets | 9 | 4 | % | 12 | - 23 | % | ||||||||||
| Total Oil | 149 | 61 | % | 134 | +11 | % | ||||||||||
| Bitumen | 97 | 39 | % | 110 | - 12 | % | ||||||||||
| Total Oil and bitumen | 246 | 100 | % | 244 | +1 | % |
| 2018 | % of Total | 2017 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gas (MMcf/d) | ||||||||||||||||
| Delaware Basin | 105 | 10 | % | 86 | +22 | % | ||||||||||
| STACK | 334 | 30 | % | 294 | +13 | % | ||||||||||
| Rockies Oil | 16 | 1 | % | 8 | +85 | % | ||||||||||
| Heavy Oil | 10 | 1 | % | 17 | - 39 | % | ||||||||||
| Eagle Ford | 79 | 7 | % | 95 | - 17 | % | ||||||||||
| Barnett Shale | 447 | 41 | % | 475 | - 6 | % | ||||||||||
| Other | 1 | 0 | % | 1 | +6 | % | ||||||||||
| Retained assets | 992 | 90 | % | 976 | +2 | % | ||||||||||
| U.S. divested assets | 108 | 10 | % | 227 | - 52 | % | ||||||||||
| Total | 1,100 | 100 | % | 1,203 | - 9 | % |
| 2018 | % of Total | 2017 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| NGLs (MBbls/d) | ||||||||||||||||
| Delaware Basin | 16 | 15 | % | 10 | +53 | % | ||||||||||
| STACK | 37 | 35 | % | 30 | +24 | % | ||||||||||
| Rockies Oil | 1 | 2 | % | 1 | +75 | % | ||||||||||
| Eagle Ford | 13 | 12 | % | 13 | +2 | % | ||||||||||
| Barnett Shale | 30 | 28 | % | 31 | - 4 | % | ||||||||||
| Other | 1 | 1 | % | 1 | - 5 | % | ||||||||||
| Retained assets | 98 | 93 | % | 86 | +14 | % | ||||||||||
| U.S. divested assets | 8 | 7 | % | 13 | - 40 | % | ||||||||||
| Total | 106 | 100 | % | 99 | +7 | % |
| 2018 | % of Total | 2017 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Combined (MBoe/d) | ||||||||||||||||
| Delaware Basin | 75 | 14 | % | 54 | +39 | % | ||||||||||
| STACK | 125 | 24 | % | 104 | +20 | % | ||||||||||
| Rockies Oil | 17 | 3 | % | 12 | +43 | % | ||||||||||
| Heavy Oil | 117 | 22 | % | 131 | - 11 | % | ||||||||||
| Eagle Ford | 54 | 10 | % | 62 | - 13 | % | ||||||||||
| Barnett Shale | 105 | 20 | % | 111 | - 5 | % | ||||||||||
| Other | 7 | 1 | % | 7 | - 3 | % | ||||||||||
| Retained assets | 500 | 94 | % | 481 | +4 | % | ||||||||||
| U.S. divested assets | 35 | 6 | % | 62 | - 44 | % | ||||||||||
| Total | 535 | 100 | % | 543 | - 2 | % |
Focused development activities in the Delaware Basin, STACK and Rockies resulted in an approximate 28% increase in production from those areas compared to 2017. These increases also drove a 17% increase in our U.S. retained oil production. This strong performance led to the overall growth in our retained assets during 2018. Production increases from our capital focused assets were partially offset by the effects of facility repairs and other maintenance work at the Jackfish facilities, as well as by lower production resulting from our U.S. non-core divestitures.
Oil, Gas and NGL Prices
| 2018 | Realization | 2017 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil and bitumen (per Bbl) | ||||||||||||||||
| WTI index | $ | 64.79 | $ | 50.99 | +27 | % | ||||||||||
| Access Western Blend index | $ | 34.75 | $ | 36.90 | - 6 | % | ||||||||||
| U.S. | $ | 61.97 | 96% | $ | 49.41 | +25 | % | |||||||||
| Canada | $ | 19.37 | 30% | $ | 29.99 | - 35 | % | |||||||||
| Realized price, unhedged | $ | 42.04 | 65% | $ | 39.23 | +7 | % | |||||||||
| Cash settlements | $ | (0.49 | ) | $ | 0.23 | |||||||||||
| Realized price, with hedges | $ | 41.55 | 64% | $ | 39.46 | +5 | % |
| 2018 | Realization | 2017 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gas (per Mcf) | ||||||||||||||||
| Henry Hub index | $ | 3.09 | $ | 3.11 | - 1 | % | ||||||||||
| Realized price, unhedged | $ | 2.37 | 77% | $ | 2.48 | - 5 | % | |||||||||
| Cash settlements | $ | 0.01 | $ | 0.08 | ||||||||||||
| Realized price, with hedges | $ | 2.38 | 77% | $ | 2.56 | - 7 | % |
| 2018 | Realization | 2017 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| NGLs (per Bbl) | ||||||||||||||||
| Mont Belvieu blended index (1) | $ | 28.31 | $ | 24.77 | +14 | % | ||||||||||
| Realized price, unhedged | $ | 24.74 | 87% | $ | 15.66 | +58 | % | |||||||||
| Cash settlements | $ | (1.17 | ) | $ | (0.10 | ) | ||||||||||
| Realized price, with hedges | $ | 23.57 | 83% | $ | 15.56 | +51 | % |
| (1) | Based upon composition of our NGL barrel. |
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| 2018 | 2017 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Combined (per Boe) | ||||||||||||
| U.S. | $ | 31.86 | $ | 24.88 | +28 | % | ||||||
| Canada | $ | 19.12 | $ | 29.39 | - 35 | % | ||||||
| Realized price, unhedged | $ | 29.08 | $ | 25.96 | +12 | % | ||||||
| Cash settlements | $ | (0.43 | ) | $ | 0.27 | |||||||
| Realized price, with hedges | $ | 28.65 | $ | 26.23 | +9 | % |
Upstream revenues increased as a result of higher unhedged, realized prices for our U.S. oil and NGLs.
The increase in oil sales primarily resulted from higher average WTI crude index prices, which were 27% higher in 2018, resulting in an increase of approximately $568 million.
NGL sales increased $351 million as a result of 14% higher NGL prices at the Mont Belvieu, Texas hub, as well as improved realizations in our NGL price.
These increases were partially offset by widening differentials to the WTI index for bitumen sales, which negatively impacted our upstream revenues by $406 million. In the fourth quarter of 2018, market forces widened Canadian heavy oil differentials beyond historical norms and negatively impacted the price we realized on our Canadian production. We had basis swaps for approximately half of our fourth quarter production to mitigate the effect of the lower market price. To further mitigate the effects of the lower price, we reduced our Jackfish production in November 2018 which impacted our fourth quarter production by approximately 8 MBbls/d. Our Canadian heavy oil unhedged realized price for the fourth quarter was near zero. To date in 2019, heavy oil differentials have significantly improved driven by provincially mandated production cuts combined with takeaway capacity additions expected in 2019.
As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by approximately $254 million with no impact to net earnings.
Commodity Derivatives
| 2018 | 2017 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Q | ||||||||||||
| Oil | $ | (44 | ) | $ | 21 | - 310 | % | |||||
| Natural gas | 5 | 35 | - 86 | % | ||||||||
| NGL | (45 | ) | (3 | ) | - 1400 | % | ||||||
| Total cash settlements | (84 | ) | 53 | - 258 | % | |||||||
| Valuation changes | 692 | 104 | +565 | % | ||||||||
| Total | $ | 608 | $ | 157 | +287 | % |
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
In addition to cash settlements, we also 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.
Production Expenses
| 2018 | 2017 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| LOE | $ | 995 | $ | 927 | +7 | % | ||||||
| Gathering, processing & transportation | 891 | 647 | +38 | % | ||||||||
| Production taxes | 278 | 194 | +43 | % | ||||||||
| Property taxes | 61 | 55 | +11 | % | ||||||||
| Total | $ | 2,225 | $ | 1,823 | +22 | % | ||||||
| Per Boe: | ||||||||||||
| LOE | $ | 5.10 | $ | 4.67 | +9 | % | ||||||
| Gathering, processing & transportation | $ | 4.56 | $ | 3.26 | +40 | % | ||||||
| Percent of oil, gas and NGL sales: | ||||||||||||
| Production taxes | 4.9 | % | 3.8 | % | +27 | % |
LOE increased $68 million primarily due to continued focus on growing our liquids-rich assets within the STACK and Delaware Basin and higher maintenance costs at our Jackfish facilities, partially offset by our U.S. non-core divestitures.
As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by approximately $254 million with no impact to net earnings.
Production taxes increased on an absolute dollar basis primarily due to the increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed. Additionally, the increase in Oklahoma severance tax rates that became effective during the third quarter of 2018 also contributed to the increase on an absolute dollar basis and as a percentage of oil, gas and NGL sales.
Property taxes increased as a result of higher property value assessments, primarily on our Texas properties, partially offset by our U.S. non-core divestitures.
| Marketing Operations |
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| 2018 | 2017 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Marketing revenues | $ | 4,449 | $ | 3,571 | +25 | % | ||||||
| Marketing expenses | (4,363 | ) | (3,619 | ) | - 21 | % | ||||||
| Margin | $ | 86 | $ | (48 | ) | +279 | % |
The overall increase in marketing operating margin was primarily due to improved commodity prices, which were partially offset by the impact of our downstream marketing commitments.
| Exploration Expenses |
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| 2018 | 2017 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Unproved impairments | $ | 95 | $ | 217 | - 56 | % | ||||||
| Geological and geophysical | 21 | 110 | - 81 | % | ||||||||
| Exploration overhead and other | 61 | 53 | +15 | % | ||||||||
| Total | $ | 177 | $ | 380 | - 53 | % |
Unproved impairments in both periods primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs decreased primarily in the STACK and Delaware Basin.
| Depreciation, Depletion and Amortization |
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| 2018 | 2017 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil and gas per Boe | $ | 7.98 | $ | 7.15 | +12 | % | ||||||
| Oil and gas | $ | 1,559 | $ | 1,419 | +10 | % | ||||||
| Other property and equipment | 99 | 110 | - 10 | % | ||||||||
| Total | $ | 1,658 | $ | 1,529 | +8 | % |
Our oil and gas DD&A increased primarily due to continued development in the STACK, Delaware Basin and Rockies properties. The increases were slightly offset by reduced production volumes at the Jackfish facilities and from our 2018 U.S. non-core asset divestitures.
| General and Administrative Expenses |
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| 2018 | 2017 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Labor and benefits | $ | 494 | $ | 582 | - 15 | % | ||||||
| Non-labor | 236 | 228 | +4 | % | ||||||||
| Reimbursed G&A | (80 | ) | (73 | ) | - 10 | % | ||||||
| Total Devon | $ | 650 | $ | 737 | - 12 | % |
Labor and benefits decreased primarily as a result of the workforce reduction that occurred during 2018 as discussed in Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report. Non-labor costs were higher due to an increase in costs related to automation and process improvements.
| Financing Costs, net |
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Financing costs, net increased $277 million as a result of a $312 million loss on early retirement of debt. For further discussion of early retirement premiums and reduced interest expense resulting from our lower debt balances, see Note 15 in
“Item 8. Financial Statements and Supplementary Data” of this report.
| Other |
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| 2018 | 2017 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Asset impairments | $ | 156 | $ | — | N/M | |||||||
| Asset dispositions | (263 | ) | (217 | ) | - 21 | % | ||||||
| Restructuring | 114 | — | N/M | |||||||||
| Other | 140 | (83 | ) | +269 | % | |||||||
| Total | $ | 147 | $ | (300 | ) | +149 | % |
Additional information regarding the impairments is discussed in Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.
We recognized gains in conjunction with certain of our U.S. asset dispositions in 2017 and 2018. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2018, we recognized restructuring and transaction costs of $114 million primarily as a result of our workforce reduction. See Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
The remaining change in other expense was driven primarily by changes on foreign currency exchange instruments as further discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
| Income Taxes |
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| 2018 | 2017 | |||||||
|---|---|---|---|---|---|---|---|---|
| Current expense (benefit) | $ | (70 | ) | $ | 112 | |||
| Deferred expense (benefit) | 226 | (97 | ) | |||||
| Total expense | $ | 156 | $ | 15 | ||||
| Effective income tax rate | 17 | % | 2 | % |
For discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.
| Discontinued Operations |
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Discontinued operations net earnings increased primarily due to the gain on the sale of our aggregate ownership interests in EnLink and the General Partner of $2.6 billion ($2.2 billion after-tax). For discussion on discontinued operations, see Note 19 in “Item 8. Financial Statements and Supplementary Data” of this report” of this report.
Results of Operations – 2017 vs. 2016
The graph below shows the change in net earnings from 2016 to 2017. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.
| (1) | Other in the table above includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses. |
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The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph.
| Upstream Operations |
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Oil, Gas and NGL Production
| 2017 | % of Total | 2016 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil and bitumen (MBbls/d) | ||||||||||||||||
| Delaware Basin | 29 | 12 | % | 32 | - 7 | % | ||||||||||
| STACK | 25 | 11 | % | 18 | +39 | % | ||||||||||
| Rockies Oil | 10 | 4 | % | 9 | +9 | % | ||||||||||
| Heavy Oil | 18 | 7 | % | 22 | - 19 | % | ||||||||||
| Eagle Ford | 34 | 14 | % | 39 | - 14 | % | ||||||||||
| Barnett Shale | 1 | 0 | % | 1 | - 25 | % | ||||||||||
| Other | 5 | 2 | % | 6 | - 13 | % | ||||||||||
| Retained assets | 122 | 50 | % | 127 | - 4 | % | ||||||||||
| U.S. divested assets | 12 | 5 | % | 24 | - 51 | % | ||||||||||
| Total Oil | 134 | 55 | % | 151 | - 11 | % | ||||||||||
| Bitumen | 110 | 45 | % | 109 | +1 | % | ||||||||||
| Total Oil and bitumen | 244 | 100 | % | 260 | - 6 | % |
| 2017 | % of Total | 2016 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gas (MMcf/d) | ||||||||||||||||
| Delaware Basin | 86 | 7 | % | 86 | +1 | % | ||||||||||
| STACK | 294 | 24 | % | 282 | +4 | % | ||||||||||
| Rockies Oil | 8 | 1 | % | 16 | - 48 | % | ||||||||||
| Heavy Oil | 17 | 2 | % | 20 | - 14 | % | ||||||||||
| Eagle Ford | 95 | 8 | % | 101 | - 6 | % | ||||||||||
| Barnett Shale | 475 | 39 | % | 530 | - 10 | % | ||||||||||
| Other | 1 | 0 | % | 1 | - 10 | % | ||||||||||
| Retained assets | 976 | 81 | % | 1,036 | - 6 | % | ||||||||||
| U.S. divested assets | 227 | 19 | % | 377 | - 40 | % | ||||||||||
| Total | 1,203 | 100 | % | 1,413 | - 15 | % |
| 2017 | % of Total | 2016 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| NGLs (MBbls/d) | ||||||||||||||||
| Delaware Basin | 10 | 10 | % | 11 | - 10 | % | ||||||||||
| STACK | 30 | 30 | % | 25 | +19 | % | ||||||||||
| Rockies Oil | 1 | 1 | % | 1 | +23 | % | ||||||||||
| Eagle Ford | 13 | 13 | % | 16 | - 19 | % | ||||||||||
| Barnett Shale | 31 | 32 | % | 34 | - 9 | % | ||||||||||
| Other | 1 | 1 | % | 1 | - 4 | % | ||||||||||
| Retained assets | 86 | 87 | % | 88 | - 3 | % | ||||||||||
| U.S. divested assets | 13 | 13 | % | 28 | - 53 | % | ||||||||||
| Total | 99 | 100 | % | 116 | - 15 | % |
| 2017 | % of Total | 2016 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Combined (MBoe/d) | ||||||||||||||||
| Delaware Basin | 54 | 10 | % | 57 | - 6 | % | ||||||||||
| STACK | 104 | 19 | % | 90 | +15 | % | ||||||||||
| Rockies Oil | 12 | 2 | % | 13 | - 3 | % | ||||||||||
| Heavy Oil | 131 | 24 | % | 134 | - 2 | % | ||||||||||
| Eagle Ford | 62 | 11 | % | 72 | - 13 | % | ||||||||||
| Barnett Shale | 111 | 21 | % | 123 | - 10 | % | ||||||||||
| Other | 7 | 1 | % | 8 | - 6 | % | ||||||||||
| Retained assets | 481 | 88 | % | 497 | - 3 | % | ||||||||||
| U.S. divested assets | 62 | 12 | % | 114 | - 45 | % | ||||||||||
| Total | 543 | 100 | % | 611 | - 11 | % |
Production declines reduced our upstream revenues by $427 million primarily as a result of our U.S. divested assets. Retained production volumes decreased due to reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale. These decreases were partially offset by expanded drilling and performance in the STACK.
Oil, Gas and NGL Prices
| 2017 | Realization | 2016 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil and bitumen (per Bbl) | ||||||||||||||||
| WTI index | $ | 50.99 | $ | 43.36 | +18 | % | ||||||||||
| Access Western Blend index | $ | 36.90 | $ | 26.96 | +37 | % | ||||||||||
| U.S. | $ | 49.41 | 97% | $ | 38.92 | +27 | % | |||||||||
| Canada | $ | 29.99 | 59% | $ | 20.53 | +46 | % | |||||||||
| Realized price, unhedged | $ | 39.23 | 77% | $ | 29.65 | +32 | % | |||||||||
| Cash settlements | $ | 0.23 | $ | (0.43 | ) | |||||||||||
| Realized price, with hedges | $ | 39.46 | 77% | $ | 29.22 | +35 | % |
| 2017 | Realization | 2016 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gas (per Mcf) | ||||||||||||||||
| Henry Hub index | $ | 3.11 | $ | 2.46 | +26 | % | ||||||||||
| Realized price, unhedged | $ | 2.48 | 80% | $ | 1.84 | +35 | % | |||||||||
| Cash settlements | $ | 0.08 | $ | 0.07 | ||||||||||||
| Realized price, with hedges | $ | 2.56 | 82% | $ | 1.91 | +34 | % |
| 2017 | Realization | 2016 | Change | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| NGLs (per Bbl) | ||||||||||||||||
| Mont Belvieu blended index (1) | $ | 24.77 | $ | 17.20 | +44 | % | ||||||||||
| Realized price, unhedged | $ | 15.66 | 63% | $ | 9.81 | +60 | % | |||||||||
| Cash settlements | $ | (0.10 | ) | $ | (0.11 | ) | ||||||||||
| Realized price, with hedges | $ | 15.56 | 63% | $ | 9.70 | +60 | % |
| (1) | Based upon composition of average Devon NGL barrel. |
|---|
| 2017 | 2016 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Combined (per Boe) | ||||||||||||
| U.S. | $ | 24.88 | $ | 18.34 | +36 | % | ||||||
| Canada | $ | 29.39 | $ | 20.07 | +46 | % | ||||||
| Realized price, unhedged | $ | 25.96 | $ | 18.72 | +39 | % | ||||||
| Cash settlements | $ | 0.27 | $ | (0.05 | ) | |||||||
| Realized price, with hedges | $ | 26.23 | $ | 18.67 | +40 | % |
Upstream revenues increased $1.4 billion as a result of higher unhedged, realized prices across our entire portfolio. The increase in oil and bitumen sales primarily resulted from higher average WTI crude index prices, which were 18% higher in 2017. Additionally, our oil and bitumen sales benefited from tighter differentials to the WTI index. The increase in gas sales was driven by higher North American regional index prices upon which our gas sales are based and higher NGL prices at the Mont Belvieu, Texas hub.
Commodity Derivatives
| 2017 | 2016 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Q | ||||||||||||
| Oil | $ | 21 | $ | (41 | ) | +151 | % | |||||
| Natural gas | 35 | 35 | +0 | % | ||||||||
| NGL | (3 | ) | (5 | ) | +40 | % | ||||||
| Total cash settlements | 53 | (11 | ) | N/M | ||||||||
| Valuation changes | 104 | (190 | ) | +155 | % | |||||||
| Total | $ | 157 | $ | (201 | ) | +178 | % |
Production Expenses
| 2017 | 2016 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| LOE | $ | 927 | $ | 1,027 | - 10 | % | ||||||
| Gathering, processing & transportation | 647 | 555 | +17 | % | ||||||||
| Production taxes | 194 | 149 | +30 | % | ||||||||
| Property taxes | 55 | 74 | - 26 | % | ||||||||
| Total | $ | 1,823 | $ | 1,805 | +1 | % | ||||||
| Per Boe: | ||||||||||||
| LOE | $ | 4.67 | $ | 4.59 | +2 | % | ||||||
| Gathering, processing & transportation | $ | 3.26 | $ | 2.48 | +31 | % | ||||||
| Percent of oil, gas and NGL sales: | ||||||||||||
| Production taxes | 3.8 | % | 3.5 | % | +7 | % |
LOE decreased $100 million primarily due to our U.S. property divestitures in 2016. Well optimization and cost reduction initiatives across our portfolio offset industry inflation. These initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers.
Gathering and transportation expense increased $92 million primarily due to a full year of the Access Pipeline transportation tolls, which commenced in the fourth quarter of 2016 subsequent to the sale of our interest in the pipeline. Our Access transportation agreement contains a base transportation commitment, which for the initial five years averages $110 million annually.
Production taxes increased on an absolute dollar basis primarily due to the increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed.
Property taxes decreased as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our U.S. asset divestitures.
| Exploration Expenses |
|---|
| 2017 | 2016 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Unproved impairments | $ | 217 | $ | 77 | +182 | % | ||||||
| Geological and geophysical | 110 | 65 | +70 | % | ||||||||
| Exploration overhead and other | 53 | 73 | - 27 | % | ||||||||
| Total | $ | 380 | $ | 215 | +77 | % |
Unproved impairments primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs increased primarily in the STACK and Delaware Basin.
| Depreciation, Depletion and Amortization |
|---|
| 2017 | 2016 | Change | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil and gas per Boe | $ | 7.15 | $ | 6.47 | +11 | % | |||||||
| Oil and gas | $ | 1,419 | $ | 1,446 | - 2 | % | |||||||
| Other property and equipment | 110 | 146 | - 25 | % | |||||||||
| Total | $ | 1,529 | $ | 1,592 | - 4 | % |
Our oil and gas DD&A remained relatively flat as compared to the prior year. Increases in oil and gas DD&A rates due to continued development in the STACK and Delaware Basin were offset by reduced production volumes resulting from the 2016 U.S. asset divestitures. DD&A from our other property and equipment decreased due to the divestiture of the Access Pipeline in the fourth quarter of 2016.
| Financing Costs, net |
|---|
Financing costs, net decreased $400 million primarily as a result of our $2.1 billion early debt retirement in 2016. For further discussion of early retirement premiums and reduced interest expense resulting from our lower debt balances, see Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report.
| Other |
|---|
| 2017 | 2016 | Change | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Asset impairments | $ | — | $ | 437 | - 100 | % | ||||||
| Asset dispositions | (217 | ) | (1,496 | ) | +85 | % | ||||||
| Restructuring | — | 261 | - 100 | % | ||||||||
| Other | (83 | ) | 101 | - 183 | % | |||||||
| Total | $ | (300 | ) | $ | (697 | ) | +57 | % |
In 2016, we recognized proved asset impairments on a portion of our U.S. assets. See Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report for additional information.
We recognized gains in conjunction with certain of our asset dispositions in both 2016 and 2017 and the divestiture of our 50% interest in the Access Pipeline in 2016. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2016, we recognized restructuring and transaction costs of $261 million primarily as a result of our workforce reduction. For discussion of our reorganization programs and the associated restructuring costs, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.
The remaining change in other expense was driven primarily by changes on foreign currency exchange instruments, as further discussed in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.
| Income Taxes |
|---|
| 2017 | 2016 | |||||||
|---|---|---|---|---|---|---|---|---|
| Current expense | $ | 112 | $ | 98 | ||||
| Deferred expense (benefit) | (97 | ) | 43 | |||||
| Total expense | $ | 15 | $ | 141 | ||||
| Effective income tax rate | 2 | % | (33 | %) |
For discussion on income taxes, see Note 8 in “Item 8. Financial Statements and Supplementary Data” of this report.
| Discontinued Operations |
|---|
For discussion on discontinued operations, see Note 19 in “Item 8. Financial Statements and Supplementary Data” of 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 time periods presented below.
| Year ended December 31, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2018 | 2017 | 2016 | ||||||||||
| Operating cash flow from continuing operations | $ | 2,228 | $ | 2,209 | $ | 834 | ||||||
| Divestitures of property and equipment | 1,013 | 426 | 3,020 | |||||||||
| Capital expenditures | (2,451 | ) | (1,968 | ) | (1,384 | ) | ||||||
| Acquisitions of property and equipment | (55 | ) | (46 | ) | (849 | ) | ||||||
| Debt activity, net | (1,226 | ) | — | (3,383 | ) | |||||||
| Repurchases of common stock | (2,956 | ) | — | — | ||||||||
| Common stock dividends | (149 | ) | (127 | ) | (221 | ) | ||||||
| Issuance of common stock | — | — | 1,469 | |||||||||
| Effect of exchange rate and other | 151 | (53 | ) | (96 | ) | |||||||
| Net change in cash, cash equivalents and restricted cash from discontinued operations | 3,207 | 284 | 259 | |||||||||
| Net change in cash, cash equivalents and restricted cash | $ | (238 | ) | $ | 725 | $ | (351 | ) | ||||
| Cash, cash equivalents and restricted cash at end of period | $ | 2,446 | $ | 2,684 | $ | 1,959 |
Operating Cash Flow – Continuing Operations
Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2018. Our operating cash flow was relatively flat compared to 2017. In 2018, our operating cash flow funded approximately 86% of our capital expenditure program and dividends. We utilized available cash balances and divestiture proceeds to supplement our operating cash flows. Operating cash flow for 2018 included a realized foreign exchange loss of $241 million relating to foreign currency denominated intercompany loan activity as described in Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report. There was an offset in the effect of exchange rate and other line in the above table, resulting in no impact to the net change in cash, cash equivalents and restricted cash.
Our operating cash flow increased $1.4 billion, or 165%, from 2016 to 2017. In 2017, our operating cash flow fully funded our capital expenditures program as well as our dividends. In 2016, our operating cash flow did not fully fund our capital requirements and dividends; as a result, we utilized available cash balances and divestiture proceeds to supplement our operating cash flows.
Divestitures of Property and Investments
During 2018, as part of our announced divestiture program, we sold non-core U.S. upstream assets for approximately $1.0 billion. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2017, as part of our announced divestiture program, we sold non-core U.S. upstream assets for approximately $420 million. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2016, we divested certain non-core upstream assets in the U.S. and our 50% interest in the Access Pipeline in Canada for approximately $3.0 billion, net of purchase price adjustments. Proceeds from these divestitures were used primarily for debt repayment and to support capital investment in our core resource plays. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.
We did not have significant current cash income taxes resulting from the divestitures in 2018, 2017 and 2016.
Capital Expenditures
The following table summarizes our capital expenditures and property acquisitions.
| Year ended December 31, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2018 | 2017 | 2016 | ||||||||||
| Oil and gas | $ | 2,395 | $ | 1,879 | $ | 1,341 | ||||||
| Corporate and other | 56 | 89 | 43 | |||||||||
| Total capital expenditures | $ | 2,451 | $ | 1,968 | $ | 1,384 | ||||||
| Acquisitions | $ | 55 | $ | 46 | $ | 849 |
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. Our capital program is designed to operate within or near operating cash flow and may fluctuate with changes to commodity prices and other factors impacting cash flow. This is evidenced by our operating cash flow funding approximately 91% of capital expenditures in 2018 and fully funding capital expenditures in 2017.
Acquisition costs in 2016 primarily consisted of Devon’s bolt-on acquisition of assets in the STACK play for $1.5 billion. Approximately $849 million was paid in cash at closing with the remainder of the purchase price funded with equity consideration. See Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report for more information.
Debt Activity, Net
During 2018, our debt decreased $922 million due to completed tender offers of certain long-term debt as well as the maturity of certain senior notes. In conjunction with the tender offers, we recognized a $312 million loss on the early retirement of debt, including $304 million of cash retirement costs and fees. For additional information, see Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report.
During 2016, our debt decreased $3.1 billion due to completed tender offers to purchase and redeem $2.1 billion of debt securities prior to their maturity and a $1 billion reduction in short-term borrowings. In conjunction with the tender offers, we recognized a $269 million loss on the early retirement of debt, including $265 million of cash retirement costs and fees. For additional information, see Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report.
Repurchases of Common Stock and Shareholder Distributions
In June 2018, in conjunction with the announcement of the divestiture of our investment in EnLink and the General Partner, our Board of Directors authorized a $4.0 billion share repurchase program of our common stock. The share repurchase program expires December 31, 2019. As discussed further in Note 18 in “Item 8. Financial Statements and Supplementary Data” in this report, we repurchased 78.1 million shares of common stock for $3.0 billion, or $38.11 per share, under the ASR agreement and through open-market share repurchases through December 31, 2018.
Devon paid common stock dividends of $149 million, $127 million and $221 million during 2018, 2017 and 2016, respectively. During the second quarter of 2018, we increased our quarterly dividend 33% to $0.08 per share as part of our initiative to return cash to shareholders. Our prior quarterly dividend was $0.06 per share subsequent to a reduction from $0.24 per share in the second quarter of 2016 due to the depressed commodity price environment. For additional information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.
Issuance of Common Stock
In February 2016, we issued 79 million shares of our common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.
Cash Flows from Discontinued Operations
All cash flows in the following table relate to activities of EnLink and the General Partner.
| Year ended December 31, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2018 | 2017 | 2016 | ||||||||||
| Cash flows from discontinued operations: | ||||||||||||
| Operating activities | $ | 476 | $ | 700 | $ | 666 | ||||||
| Capital expenditures and other | (556 | ) | (801 | ) | (1,381 | ) | ||||||
| Divestitures of investments | 3,104 | 190 | — | |||||||||
| Investing activities | 2,548 | (611 | ) | (1,381 | ) | |||||||
| Debt activity, net | 347 | 2 | 228 | |||||||||
| Issuance of subsidiary units | 1 | 501 | 892 | |||||||||
| Distributions to noncontrolling interests | (217 | ) | (354 | ) | (304 | ) | ||||||
| Other | 52 | 46 | 158 | |||||||||
| Financing activities | 183 | 195 | 974 | |||||||||
| Net change in cash, cash equivalents and restricted cash of discontinued operations | $ | 3,207 | $ | 284 | $ | 259 |
Operating cash flow in 2018 decreased $224 million and $190 million from 2017 and 2016, respectively, as a result of the divestiture of our aggregate ownership interests in EnLink and the General Partner in July 2018.
Cash flows from investing activities for 2018 includes $3.125 billion received from the divestiture of our aggregate ownership interests in EnLink and the General Partner, partially offset by capital expenditures and other items. Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. During 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets for $1.5 billion. Approximately $792 million was paid in cash at closing with the remainder of the purchase price funded with equity consideration and debt.
Cash flows from financing activities includes common and preferred units EnLink issued and sold during 2017 and 2016 generating net proceeds of approximately $501 million and $892 million, respectively. Distributions to noncontrolling interests in the table above exclude the distributions EnLink and the General Partner paid to Devon, which have been eliminated in consolidation. Distributions Enlink and the General Partner paid to Devon were $134 million, $265 million and $265 million during 2018, 2017 and 2016, respectively.
Liquidity
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.
Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. If needed, we can also issue debt and equity securities pursuant to our shelf registration statement filed with the SEC. In February 2019, we also announced plans to separate our Canadian and Barnett Shale assets and operations. We expect to complete these asset separations in 2019. We plan to use the proceeds from these transactions for debt repayments and common share repurchases. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements as discussed in this section.
Operating Cash Flow
Key inputs into determining our planned capital investment is 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 2018, we held approximately $2.4 billion of cash. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as these variables differ from our expectations.
Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, bitumen, gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control. For illustration, our operating cash flow slightly increased in 2018 largely due to 16% growth from our retained U.S. liquids portfolio, as well as 32% higher realized pricing related to these assets. These increases were mostly offset by a significant decrease in our realized price for our bitumen production in 2018. Western Canadian Select basis differentials widened significantly above historical norms due to robust production outpacing local demand, pipeline capacity and rail capacity out of the region. The market fundamentals led our fourth quarter unhedged realized price for bitumen to be near $0 per Bbl. In the first two months of 2019, government-mandated production curtailments and current market fundamentals have led to a significant improvement in the Western Canadian Select basis differential.
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 target hedging approximately 50% of 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. We currently have approximately 50% of our anticipated 2019 oil and gas volumes hedged, and we are adding hedges for 2020 as well. Further insulating our cash flow, we are proactively locking in hedges on the Western Canada Select basis differential to WTI and currently have approximately 50% of our 2019 Canadian heavy oil production hedged. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2018 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.
Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities at $46/Bbl WTI and $3.00/Mcf Henry Hub. Should WTI drop closer to $40/Bbl for an extended period, we would shift our focus to preserving our financial strength and operational continuity. However, as WTI/Bbl rises above $46, our free cash flow will accelerate, providing additional capital allocation opportunities.
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.
For 2019, we expect to aggressively optimize our cost structure in conjunction with our planned Canadian and Barnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with the retained business and reduce outstanding debt. We anticipate the planned $780 million reduction of annualized costs will occur over three years, with roughly 70% of the savings delivered by the end of 2019. Approximately 40% of the reduced costs relate to our capital programs and the remainder relates to our operating expenses, including G&A, interest expense and production expenses.
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.
Divestitures of Property and Equipment
In the first quarter of 2019, we sold non-core assets for approximately $300 million. We also anticipate separating our Canadian and Barnett Shale businesses from our Company in 2019.
Credit Availability
Our 2018 Senior Credit Facility, under which we have $2.9 billion of available borrowing capacity at December 31, 2018, matures on October 5, 2023, with the option to extend the maturity date by two additional one-year periods subject to lender consent. The 2018 Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2018, there were no borrowings under our commercial paper program. See Note 15 in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion.
The 2018 Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. As of December 31, 2018, we were in compliance with this covenant with a 21.0% debt-to-capitalization ratio.
Our access to funds from the 2018 Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments or the enforceability of material terms of the credit agreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.
As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.
In January 2019, we repaid the $162 million of 6.30% senior notes at maturity with cash on hand.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is 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.
Share Repurchase Program
In February 2019, our Board of Directors increased our share repurchase program by an additional $1 billion. The $5 billion share repurchase program expires December 31, 2019. Through February 15, 2019, we have executed $3.4 billion of the authorized program.
Capital Expenditures
Our 2019 exploration and development budget is expected to be approximately $2.0 billion to $2.25 billion, including capital associated with our Canadian and Barnett Shale upstream assets.
Contractual Obligations
The following table presents a summary of our contractual obligations as of December 31, 2018.
| Payments Due by Period | ||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years | ||||||||||||||||
| Devon obligations: | ||||||||||||||||||||
| Debt (1) | $ | 6,011 | $ | 162 | $ | 500 | $ | 1,000 | $ | 4,349 | ||||||||||
| Interest expense (2) | 4,951 | 317 | 623 | 535 | 3,476 | |||||||||||||||
| Purchase obligations (3) | 1,248 | 541 | 707 | — | — | |||||||||||||||
| Operational agreements (4) | 5,626 | 587 | 892 | 773 | 3,374 | |||||||||||||||
| Asset retirement obligations (5) | 1,057 | 27 | 76 | 79 | 875 | |||||||||||||||
| Drilling and facility obligations (6) | 445 | 274 | 133 | 22 | 16 | |||||||||||||||
| Lease obligations (7) | 500 | 64 | 74 | 51 | 311 | |||||||||||||||
| Other (8) | 295 | 32 | 78 | 27 | 158 | |||||||||||||||
| Total obligations | $ | 20,133 | $ | 2,004 | $ | 3,083 | $ | 2,487 | $ | 12,559 |
| (1) | Debt amounts represent scheduled maturities of debt obligations at December 31, 2018, excluding net discounts and debt issue costs included in the carrying value of debt. |
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| (2) | Interest expense represents the scheduled cash payments on long-term fixed-rate debt (including current portion of long term debt). |
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| (3) | Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices. |
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| (4) | Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets. Approximately $1.9 billion relates to the transportation agreement we entered in 2016 in which we dedicated our thermal-oil acreage to the Access Pipeline for an initial term of 25 years following the divestment of our 50% interest in the Access Pipeline. For additional information, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report. |
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| (5) | Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2018 balance sheet. |
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| (6) | Drilling and facility obligations represent gross contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. |
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| (7) | Lease obligations consist primarily of non-cancelable leases for office space and equipment. |
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| (8) | Other obligations primarily relate to various tax obligations. |
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Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 20 in “Item 8. Financial Statements and Supplementary Data” of this report.
Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the
following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.
Oil and Gas Assets Accounting, Classification, Reserves & Valuation
Successful Efforts Method of Accounting and Classification
We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management’s assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.
Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. At the end of each quarter, management reviews the status of all suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, management considers current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program. If management determines future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the Consolidated Comprehensive Statement of Earnings. Otherwise, the costs of exploratory wells remain capitalized. At December 31, 2018, Devon had approximately $200 million of well costs suspended for more than one year, which largely pertain to its Pike Heavy Oil project. Stratigraphic testing has demonstrated reserves can be produced economically at Pike. However, this capital intensive, long-duration project remains unsanctioned by Devon and its 50% partner, which is the primary reason reserves have not been designated as proven at Pike. With no lease expiration at Pike in the near future, management continues to keep the Pike exploratory costs capitalized.
Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2018, Devon had $1.2 billion of undeveloped leasehold and capitalized interest, which includes approximately $750 million related to Pike. Consistent with the evaluation above on suspended well costs, the costs for Pike continue to remain capitalized. Of the remaining undeveloped leasehold costs at December 31, 2018, approximately $10 million is scheduled to expire in 2019. The leasehold expiring in 2019 relates to areas in which Devon is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.
Reserves
Our estimates of proved and proved developed reserves are a major component of DD&A calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by third-party petroleum consulting firms. In 2018, 89% of our reserves were subjected to such audits.
The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than 5% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
Valuation of Long-Lived Assets
Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual
assets based on a judgmental assessment of the lowest level (“common operating field”) for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of common operating fields is largely based on geological structural features or stratigraphic condition, which requires judgment. Management also considers the nature of production, common infrastructure, common sales points, common processing plants, common regulation and management oversight to make common operating field determinations. These determinations impact the amount of DD&A recognized each period and could impact the determination and measurement of a potential asset impairment.
Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. Besides the estimates of reserves and future production volumes, future commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we generally utilize the forward strip prices for the first five years and apply internally generated price forecasts for subsequent years. We estimate and escalate or de-escalate future capital and operating costs by using a method that correlates cost movements to price movements similar to recent history. Changes to any of these assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Due to suppressed commodity prices in 2016, we recognized significant asset impairments. With generally higher pricing in 2017 and 2018, we did not recognize material asset impairments.
Goodwill
We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. As of December 31, 2018, the U.S. reporting unit had goodwill totaling $841 million.
We perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If our qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. As part of our qualitative assessment, we considered the general macroeconomic, industry and market conditions, changes in cost factors, actual and expected financial performance, significant changes in management, strategy or customers, and stock performance. If the qualitative assessment determines that a quantitative goodwill impairment test is required, then the fair value of each reporting unit is compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available for our reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions.
Based on our qualitative assessment as of October 31, 2018, it is not more likely than not that the fair value of the U.S. reporting unit is less than its carrying amount. Since our annual test for goodwill impairment on October 31, 2018 was performed, our stock price decreased 30% from October 31 to December 31. As such, we performed an updated assessment as of December 31, 2018 to determine if it is more likely than not that the fair value of our reporting unit is less than its carrying amount. Based on our qualitative assessment as of December 31, 2018, it is not more likely than not that the fair value of the U.S. reporting unit is less than its carrying value.
Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual future results are not consistent with these assumptions and estimates, or the assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which we would determine that the carrying value exceeds fair value. We would expect that a prolonged or sustained period of lower commodity prices would adversely affect the estimate of future operating results, which could result in future goodwill impairments for our U.S. reporting unit due to the potential impact on the cash flows of our operations.
The impairment of goodwill has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.
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. At the end of 2017, we recorded a 100% valuation allowance against our U.S. deferred tax assets. Upon closing the EnLink divestiture in the third quarter of 2018, Devon reassessed its position and determined that its U.S. segment is no longer in a full valuation allowance position, maintaining only valuation allowances against certain deferred tax assets, including certain tax credits and state net operating losses. Devon also has recorded a partial valuation allowance against certain Canadian deferred tax assets that were generated by a 2017 Canadian legal entity restructuring.
The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.
We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the U.S. and existing U.S. income tax laws. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested.
For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax calculation on the indefinitely reinvested earnings would require the following additional activities:
| • | relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings; |
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| • | determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and |
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| • | further analysis of a variety of other inputs such as the earnings and profits, U.S./foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations. |
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Because of the administrative burden required to perform these additional activities, it is impractical to calculate a hypothetical tax on the foreign earnings associated with this separate and more complicated chain of companies.
Non-GAAP Measures
Core Earnings
We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2018 Results” in this Item 7 that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other items that are typically excluded by securities analysts in their published estimates of our financial results. Additionally, we’ve presented our discontinued operations associated with the sale of our aggregate ownership interests in EnLink and the General Partner separately to show our results on a go-forward basis. For more information on the results of operations for EnLink and the General Partner, see Note 19 in “Item 8. Financial Statements and Supplementary Data” in this report. Our non-GAAP measures are typically used as a performance measure. Amounts excluded for 2018 relate to asset dispositions, the gain on the sale of Devon’s aggregate ownership interests in EnLink and the General Partner, noncash asset impairments including noncash unproved asset impairments, deferred tax asset valuation allowance, costs associated with early retirement of debt, fair value changes in derivative financial instruments and foreign currency, restructuring and transaction costs associated with the 2018 workforce reduction and settlements relating to minimum volume contract commitments.
Amounts excluded for 2017 relate to asset dispositions, noncash asset impairments including noncash unproved asset impairments, U.S. tax reform changes, deferred tax asset valuation allowance, derivatives and financial instrument fair value changes, legal entity restructuring and costs associated with early retirement of debt.
Amounts excluded for 2016 relate to asset dispositions, noncash asset impairments (including an impairment of EnLink goodwill) including noncash unproved asset impairments and dry hole costs relating to exploration expenses, rig stacking costs, deferred tax asset valuation allowance, restructuring and transaction costs associated with the 2016 workforce reduction, derivatives and financial instrument fair value changes and costs associated with early retirement of debt.
We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts, which typically make similar adjustments in their estimates of our financial results. 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 our core earnings and earnings per share to their comparable GAAP measures.
| Before tax | After tax | After Noncontrolling Interests | Per Diluted Share | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2018 | |||||||||||||||
| Continuing Operations | |||||||||||||||
| Earnings attributable to Devon (GAAP) | $ | 920 | $ | 764 | $ | 764 | $ | 1.52 | |||||||
| Adjustments: | |||||||||||||||
| Asset dispositions | (263 | ) | (202 | ) | (202 | ) | (0.41 | ) | |||||||
| Asset and exploration impairments | 257 | 198 | 198 | 0.40 | |||||||||||
| Deferred tax asset valuation allowance | — | (42 | ) | (42 | ) | (0.08 | ) | ||||||||
| Early retirement of debt | 312 | 240 | 240 | 0.48 | |||||||||||
| Fair value changes in financial instruments and foreign currency | (614 | ) | (458 | ) | (458 | ) | (0.92 | ) | |||||||
| Restructuring and transaction costs | 114 | 87 | 87 | 0.18 | |||||||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 726 | $ | 587 | $ | 587 | $ | 1.17 | |||||||
| Discontinued Operations | |||||||||||||||
| Earnings attributable to Devon (GAAP) | $ | 2,863 | $ | 2,460 | $ | 2,300 | $ | 4.58 | |||||||
| Adjustments: | |||||||||||||||
| Gain on sale of EnLink and the General Partner | (2,607 | ) | (2,222 | ) | (2,222 | ) | (4.43 | ) | |||||||
| Fair value changes, and minimum volume commitment settlement | (34 | ) | (28 | ) | (10 | ) | (0.02 | ) | |||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 222 | $ | 210 | $ | 68 | $ | 0.13 | |||||||
| Total | |||||||||||||||
| Earnings attributable to Devon (GAAP) | $ | 3,783 | $ | 3,224 | $ | 3,064 | $ | 6.10 | |||||||
| Adjustments: | |||||||||||||||
| Continuing Operations | (194 | ) | (177 | ) | (177 | ) | (0.35 | ) | |||||||
| Discontinued Operations | (2,641 | ) | (2,250 | ) | (2,232 | ) | (4.45 | ) | |||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 948 | $ | 797 | $ | 655 | $ | 1.30 | |||||||
| 2017 | |||||||||||||||
| Continuing Operations | |||||||||||||||
| Earnings attributable to Devon (GAAP) | $ | 773 | $ | 758 | $ | 758 | $ | 1.43 | |||||||
| Adjustments: | |||||||||||||||
| Asset dispositions | (217 | ) | (138 | ) | (138 | ) | (0.26 | ) | |||||||
| Asset and exploration impairments | 217 | 138 | 138 | 0.25 | |||||||||||
| Deferred tax asset valuation allowance | — | (76 | ) | (76 | ) | (0.14 | ) | ||||||||
| Fair value changes in financial instruments and foreign currency | (214 | ) | (199 | ) | (199 | ) | (0.37 | ) | |||||||
| Legal entity restructuring | — | (86 | ) | (86 | ) | (0.16 | ) | ||||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 559 | $ | 397 | $ | 397 | $ | 0.75 | |||||||
| Discontinued Operations | |||||||||||||||
| Earnings attributable to Devon (GAAP) | $ | 123 | $ | 320 | $ | 140 | $ | 0.27 | |||||||
| Adjustments: | |||||||||||||||
| U.S. tax reform | — | (211 | ) | (112 | ) | (0.21 | ) | ||||||||
| Asset dispositions, impairments, fair value changes and early retirement of debt | 4 | 4 | 2 | 0.00 | |||||||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 127 | $ | 113 | $ | 30 | $ | 0.06 | |||||||
| Total | |||||||||||||||
| Earnings attributable to Devon (GAAP) | $ | 896 | $ | 1,078 | $ | 898 | $ | 1.70 | |||||||
| Adjustments: | |||||||||||||||
| Continuing Operations | (214 | ) | (361 | ) | (361 | ) | (0.68 | ) | |||||||
| Discontinued Operations | 4 | (207 | ) | (110 | ) | (0.21 | ) | ||||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 686 | $ | 510 | $ | 427 | $ | 0.81 |
| Before tax | After tax | After Noncontrolling Interests | Per Diluted Share | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2016 | |||||||||||||||
| Continuing Operations | |||||||||||||||
| Loss attributable to Devon (GAAP) | $ | (433 | ) | $ | (574 | ) | $ | (575 | ) | $ | (1.14 | ) | |||
| Adjustments: | |||||||||||||||
| Asset dispositions | (1,496 | ) | (1,001 | ) | (1,001 | ) | (1.97 | ) | |||||||
| Asset and exploration impairments | 537 | 340 | 340 | 0.69 | |||||||||||
| Rig stacking costs | 10 | 6 | 6 | 0.01 | |||||||||||
| Deferred tax asset valuation allowance | — | 385 | 385 | 0.76 | |||||||||||
| Restructuring and transaction costs | 261 | 168 | 168 | 0.33 | |||||||||||
| Fair value changes in financial instruments and foreign currency | 248 | 135 | 135 | 0.26 | |||||||||||
| Early retirement of debt | 269 | 171 | 171 | 0.33 | |||||||||||
| Core loss attributable to Devon (Non-GAAP) | $ | (604 | ) | $ | (370 | ) | $ | (371 | ) | $ | (0.73 | ) | |||
| Discontinued Operations | |||||||||||||||
| Loss attributable to Devon (GAAP) | $ | (884 | ) | $ | (884 | ) | $ | (481 | ) | $ | (0.95 | ) | |||
| Adjustments: | |||||||||||||||
| Asset impairments | 893 | 890 | 467 | 0.91 | |||||||||||
| Asset dispositions, restructuring and transaction costs and fair value changes | 41 | 35 | 18 | 0.04 | |||||||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 50 | $ | 41 | $ | 4 | $ | 0.00 | |||||||
| Total | |||||||||||||||
| Loss attributable to Devon (GAAP) | $ | (1,317 | ) | $ | (1,458 | ) | $ | (1,056 | ) | $ | (2.09 | ) | |||
| Adjustments: | |||||||||||||||
| Continuing Operations | (171 | ) | 204 | 204 | 0.41 | ||||||||||
| Discontinued Operations | 934 | 925 | 485 | 0.95 | |||||||||||
| Core loss attributable to Devon (Non-GAAP) | $ | (554 | ) | $ | (329 | ) | $ | (367 | ) | $ | (0.73 | ) |
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; depreciation, depletion and amortization; 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 revenues 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 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 from continuing operations to EBITDAX and a further reconciliation to Field-Level Cash Margin. Because we have sold upstream assets in the periods presented and have plans to dispose our Canadian and Barnett Shale businesses, which represent approximately 40% of our 2018 production volumes, we have also excluded the EBITDAX and Field-Level Cash Margin for our divested assets, Canada and the Barnett Shale to compute Adjusted EBITDAX and Adjusted Field-Level Cash Margin. We use Adjusted EBITDAX and Adjusted Field-Level Cash Margin to assess the performance of our portfolio of upstream assets on a “same-store” basis across periods.
| Year Ended December 31, | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| 2018 | 2017 | 2016 | |||||||||
| Net earnings from continuing operations (GAAP) | $ | 764 | $ | 758 | $ | (574 | ) | ||||
| Financing costs, net | 594 | 317 | 717 | ||||||||
| Income tax expense | 156 | 15 | 141 | ||||||||
| Exploration expenses | 177 | 380 | 215 | ||||||||
| Depreciation, depletion and amortization | 1,658 | 1,529 | 1,592 | ||||||||
| Asset impairments | 156 | — | 437 | ||||||||
| Asset disposition gains | (263 | ) | (217 | ) | (1,496 | ) | |||||
| Share-based compensation | 122 | 141 | 124 | ||||||||
| Derivative and financial instrument non-cash valuation changes | (614 | ) | (214 | ) | 248 | ||||||
| Restructuring and transaction costs | 114 | — | 261 | ||||||||
| Accretion on discounted liabilities and other | 61 | 29 | 44 | ||||||||
| EBITDAX (non-GAAP) | 2,925 | 2,738 | 1,709 | ||||||||
| Marketing revenues and expenses, net | (86 | ) | 48 | 49 | |||||||
| Commodity derivative cash settlements | 84 | (53 | ) | 11 | |||||||
| General and administration expenses, cash-based | 529 | 596 | 609 | ||||||||
| Field-level cash margin (non-GAAP) | $ | 3,452 | $ | 3,329 | $ | 2,378 | |||||
| EBITDAX (non-GAAP) | $ | 2,925 | $ | 2,738 | $ | 1,709 | |||||
| EBITDAX, Divested assets | (184 | ) | (267 | ) | (346 | ) | |||||
| EBITDAX, Canada | (593 | ) | (748 | ) | (491 | ) | |||||
| EBITDAX, Barnett Shale | (248 | ) | (262 | ) | (148 | ) | |||||
| Adjusted EBITDAX (non-GAAP) | $ | 1,900 | $ | 1,461 | $ | 724 | |||||
| Field-level cash margin (non-GAAP) | $ | 3,452 | $ | 3,329 | $ | 2,378 | |||||
| Field-level cash margin, divested assets | (184 | ) | (267 | ) | (346 | ) | |||||
| Field-level cash margin, Canada | (210 | ) | (812 | ) | (490 | ) | |||||
| Field-level cash margin, Barnett Shale | (248 | ) | (262 | ) | (148 | ) | |||||
| Adjusted field-level cash margin (non-GAAP) | $ | 2,810 | $ | 1,988 | $ | 1,394 |
Previous: Item 6. Selected Financial Data · Next: Item 7A. Quantitative and Qualitative Disclosures about Market Risk