![](https://files.docoh.com/10-K/0001564590-19-003382/gllsi02ldj4j000004.jpg)
| | | | ![](https://files.docoh.com/10-K/0001193125-16-466687/g109858g72c24.jpg)
| | In spite of these and other operating achievements, weak commodity prices made 2015 a challenging year for the upstream energy sector, including us. As presented in the graph at the left, our operating achievements are subject to the significant decline in crudevolatility of commodity prices. Over the last four years, NYMEX WTI oil and NYMEX Henry Hub prices that beganranged 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 thirdfourth quarter of 2014 continued throughout 2015 and weakened further during2018. In the first two months of 2016. The 2015 WTI crude2019, Western Canadian Select differentials have improved significantly.
| | Key measures of our financial performance in 2018 are summarized in the following table. Increased oil index was approximately 50% lower than the 2014 average. The downward pressure on oil prices has largely resulted from increased global supply, from both OPEC and non-OPEC countries, and a global economic slowdown that has decreased demand for oil. Similarly, the Henry Hub 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 OPIS Mont Belvieu, Texas indices decreased significantly since the endGeneral Partner during 2018. More details for these metrics are found within the “Results of 2014 as a result of an imbalance between supply and demand across North America.Operations – 2018 vs. 2017” below. |
25
As a resultTable of these large commodity price declines and in spite of our operating achievements, we recognized $21 billion of noncash asset impairments throughout 2015 that have negatively impacted our financial earnings and retained earnings. Additionally, our core earnings, core earnings per share and operating cash flow for 2015 decreased significantly compared to 2014. Key measures of our financial performance in 2015 are summarized in the following table:Contents
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | Change | | | 2014 | | | Change | | | 2013 | | | | (Millions, except per share and per Boe amounts) | | Net earnings (loss) attributable to Devon | | $ | (14,454 | ) | | | N/M | | | $ | 1,607 | | | | N/M | | | $ | (20 | ) | Core earnings attributable to Devon (1) | | $ | 1,044 | | | | -48 | % | | $ | 2,017 | | | | +16 | % | | $ | 1,734 | | Earnings (loss) per share attributable to Devon | | $ | (35.55 | ) | | | N/M | | | $ | 3.91 | | | | N/M | | | $ | (0.06 | ) | Core earnings per share attributable to Devon (1) | | $ | 2.52 | | | | -49 | % | | $ | 4.91 | | | | +15 | % | | $ | 4.26 | | Core production (MBoe/d) (2) | | | 560 | | | | +15 | % | | | 489 | | | | +16 | % | | | 423 | | Total production (MBoe/d) | | | 680 | | | | +1 | % | | | 673 | | | | -3 | % | | | 693 | | Realized price per Boe(3) | | $ | 21.68 | | | | -46 | % | | $ | 40.33 | | | | +20 | % | | $ | 33.70 | | Operating cash flow | | $ | 5,383 | | | | -10 | % | | $ | 5,981 | | | | +10 | % | | $ | 5,436 | | Capitalized costs, including acquisitions | | $ | 6,233 | | | | -54 | % | | $ | 13,559 | | | | +104 | % | | $ | 6,643 | | Shareholder and noncontrolling interests distributions | | $ | 650 | | | | +5 | % | | $ | 621 | | | | +78 | % | | $ | 348 | | Reserves (MMBoe) | | | 2,182 | | | | -21 | % | | | 2,754 | | | | -7 | % | | | 2,963 | |
Index to Financial Statements | | 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 accounting principles generally accepted in the U.S. (“GAAP”).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. |
(2) | Core production is comprised of production in our key operating areas as outlined and discussed in “Items 1 and 2. Business and Properties” of this report. |
(3) | Excludes any impact of oil, gas and NGL derivatives. |
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 prices forthat 2019 crude oil and natural gas will continuepricing is expected to be depressed for much of 2016. Although changesimprove 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 forecasts,environment, geopolitical risks orand other factors could impact our current forecasts, we anticipate weak oil and natural gas prices throughout the majority of 2016.forecasts. In 2015,2018, Devon marked its 44th30th year as a public company and 47th anniversary in the oil and gas business, and its 27th year as a public company. As an established companyso we are experienced in dealing with a strong leadership team, we have experience operating in periodsthe volatile nature of weak commodity prices. WithTo mitigate our focused strategy and portfolio of quality assets, we are preparedexposure to successfully navigate the current pricing challengescommodity market volatility and ensure our long-term financial strength.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. Specifically, after completing26
Table of Contents Index to Financial Statements Despite the STACK acquisition,uncertainties pertaining to commodity prices, we began 2016 with approximately $3.9 billionremain focused on our strategic priorities of liquidity, consisting of cash and borrowing capacity under our credit facility. We expect to bolster this liquidity in 2016 by monetizing our interest in Access Pipeline and other non-core upstream assets for targeted total proceeds of $2 billion to $3 billion. While we will continue to operate and develop ourhaving 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 committedseparated, 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 balance sheetinvestment-grade credit ratings and managingpaying our capital programs to be within our cash inflows, including Access Pipeline proceeds. As a result, we are significantly reducing our capital investment in response to lower commodity prices. We plan to invest $900 million to $1.1 billion in our upstream programs, a decrease of roughly 75% compared to our 2015 capital. We are also committed to reducing our G&A and field-level operating costs commensurate with our reduced, but focused, activity level. In the first quarter of 2016, we announced plans to significantly reduce our
workforce and other G&A costs to better align with the activity level of our core business inshareholder dividend. Further, when considering the current commodity price environment. 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 reductionsfollowing graphs, discussion and analysis are expectedintended to decrease gross G&A costsprovide 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 approximately $400 millioncategory on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to $500 million onnoncontrolling interests. ![](https://files.docoh.com/10-K/0001564590-19-003382/gllsi02ldj4j000005.jpg)
| (1) | Other in the table above includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses. |
27
Table of Contents Index to Financial Statements The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph. ![](https://files.docoh.com/10-K/0001564590-19-003382/gllsi02ldj4j000006.jpg)
| (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. |
28
Table of Contents Index to Financial Statements 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 annualized basis, excluding associated employee severanceapproximate 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 restructuring costs. Following a numbermaintenance 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. |
29
Table of cost-reduction initiatives culminating with our February 2016 workforce reduction, we are expecting a $700 millionContents Index to $900 million reduction in operating and G&A costs on an annualized basis.Financial Statements We estimate we will incur approximately $225 million to $275 million of restructuring costs
| | 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 the workforce reduction. We expect to recognize the majority of these restructuring costs in the first quarter of 2016higher unhedged, realized prices for our U.S. oil and will recognize the remaining costs throughout 2016 until our planned divestiture transactions have closed and further workforce reductions occur. Also, in February 2016, we reduced our quarterly common stock dividend 75% to $0.06 per share.
Results of Operations
Oil, Gas and NGL Production
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | Change | | | 2014 | | | Change | | | 2013 | | Oil (MBbls/d) | | | | | | | | | | | | | | | | | | | | | Delaware Basin | | | 39 | | | | +48 | % | | | 26 | | | | +33 | % | | | 20 | | STACK | | | 6 | | | | +6 | % | | | 6 | | | | +23 | % | | | 5 | | Eagle Ford | | | 66 | | | | +66 | % | | | 39 | | | | N/M | | | | — | | Rockies Oil | | | 15 | | | | +39 | % | | | 10 | | | | -1 | % | | | 11 | | Heavy Oil | | | 27 | | | | +3 | % | | | 26 | | | | -7 | % | | | 28 | | Barnett Shale | | | 1 | | | | -38 | % | | | 2 | | | | -2 | % | | | 2 | | | | | | | | | | | | | | | | | | | | | | | Core assets | | | 154 | | | | +42 | % | | | 109 | | �� | | +66 | % | | | 66 | | Other(1) | | | 37 | | | | -25 | % | | | 49 | | | | -5 | % | | | 51 | | | | | | | | | | | | | | | | | | | | | | | Total | | | 191 | | | | +20 | % | | | 158 | | | | +36 | % | | | 117 | | | | | | | | | | | | | | | | | | | | | | | Bitumen (MBbls/d) | | | | | | | | | | | | | | | | | | | | | Heavy Oil | | | 84 | | | | +51 | % | | | 56 | | | | +8 | % | | | 51 | | Gas (MMcf/d) | | | | | | | | | | | | | | | | | | | | | Delaware Basin | | | 73 | | | | +9 | % | | | 67 | | | | +16 | % | | | 57 | | STACK | | | 226 | | | | -3 | % | | | 234 | | | | +14 | % | | | 205 | | Eagle Ford | | | 148 | | | | +70 | % | | | 87 | | | | N/M | | | | — | | Rockies Oil | | | 40 | | | | -17 | % | | | 47 | | | | -22 | % | | | 61 | | Heavy Oil | | | 22 | | | | -5 | % | | | 23 | | | | -19 | % | | | 28 | | Barnett Shale | | | 797 | | | | -12 | % | | | 909 | | | | -11 | % | | | 1,025 | | | | | | | | | | | | | | | | | | | | | | | Core assets | | | 1,306 | | | | -4 | % | | | 1,367 | | | | -1 | % | | | 1,376 | | Other(1) | | | 304 | | | | -45 | % | | | 553 | | | | -46 | % | | | 1,017 | | | | | | | | | | | | | | | | | | | | | | | Total | | | 1,610 | | | | -16 | % | | | 1,920 | | | | -20 | % | | | 2,393 | | | | | | | | | | | | | | | | | | | | | | | NGLs (MBbls/d) | | | | | | | | | | | | | | | | | | | | | Delaware Basin | | | 9 | | | | +24 | % | | | 8 | | | | +24 | % | | | 6 | | STACK | | | 21 | | | | -8 | % | | | 22 | | | | +33 | % | | | 17 | | Eagle Ford | | | 25 | | | | +115 | % | | | 11 | | | | N/M | | | | — | | Rockies Oil | | | 1 | | | | +33 | % | | | 1 | | | | +27 | % | | | 1 | | Barnett Shale | | | 48 | | | | -12 | % | | | 55 | | | | -1 | % | | | 55 | | | | | | | | | | | | | | | | | | | | | | | Core assets | | | 104 | | | | +7 | % | | | 97 | | | | +23 | % | | | 79 | | Other(1) | | | 32 | | | | -25 | % | | | 42 | | | | -11 | % | | | 47 | | | | | | | | | | | | | | | | | | | | | | | Total | | | 136 | | | | -2 | % | | | 139 | | | | +10 | % | | | 126 | | | | | | | | | | | | | | | | | | | | | | | Combined (MBoe/d) | | | | | | | | | | | | | | | | | | | | | Delaware Basin | | | 61 | | | | +35 | % | | | 45 | | | | +27 | % | | | 36 | | STACK | | | 64 | | | | -4 | % | | | 67 | | | | +21 | % | | | 56 | | Eagle Ford | | | 115 | | | | +75 | % | | | 65 | | | | N/M | | | | — | | Rockies Oil | | | 23 | | | | +29 | % | | | 18 | | | | -6 | % | | | 19 | | Heavy Oil | | | 115 | | | | +34 | % | | | 86 | | | | +2 | % | | | 85 | | Barnett Shale | | | 182 | | | | -13 | % | | | 208 | | | | -9 | % | | | 228 | | | | | | | | | | | | | | | | | | | | | | | Core assets | | | 560 | | | | +14 | % | | | 489 | | | | +15 | % | | | 424 | | Other(1) | | | 120 | | | | -35 | % | | | 184 | | | | -32 | % | | | 269 | | | | | | | | | | | | | | | | | | | | | | | Total | | | 680 | | | | +1 | % | | | 673 | | | | -3 | % | | | 693 | | | | | | | | | | | | | | | | | | | | | | |
(1) | Other assets are located primarily in the Midland Basin, east Texas, Granite Wash and Mississippian-Lime areas. Substantially all of these properties have been identified for divestiture in 2016. |
Oil, Gas and NGL Pricing
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 (1) | | | Change | | | 2014(1) | | | Change | | | 2013(1) | | Oil (per Bbl) | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 44.01 | | | | -49 | % | | $ | 85.64 | | | | -9 | % | | $ | 94.52 | | Canada | | $ | 30.58 | | | | -55 | % | | $ | 68.14 | | | | -1 | % | | $ | 69.18 | | Total | | $ | 42.12 | | | | -49 | % | | $ | 82.47 | | | | -4 | % | | $ | 86.02 | | Bitumen (per Bbl) | | | | | | | | | | | | | | | | | | | | | Canada | | $ | 23.41 | | | | -58 | % | | $ | 55.88 | | | | +16 | % | | $ | 48.04 | | Gas (per Mcf) | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 2.17 | | | | -45 | % | | $ | 3.92 | | | | +27 | % | | $ | 3.10 | | Canada(2) | | $ | 0.67 | | | | -82 | % | | $ | 3.64 | | | | +19 | % | | $ | 3.05 | | Total | | $ | 2.14 | | | | -45 | % | | $ | 3.90 | | | | +26 | % | | $ | 3.09 | | NGLs (per Bbl) | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 9.32 | | | | -62 | % | | $ | 24.46 | | | | -5 | % | | $ | 25.75 | | Canada | | $ | — | | | | N/M | | | $ | 50.52 | | | | +9 | % | | $ | 46.17 | | Total | | $ | 9.32 | | | | -63 | % | | $ | 24.89 | | | | -9 | % | | $ | 27.33 | | Combined (per Boe) | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 21.12 | | | | -44 | % | | $ | 37.96 | | | | +20 | % | | $ | 31.59 | | Canada | | $ | 24.46 | | | | -54 | % | | $ | 53.11 | | | | +33 | % | | $ | 39.91 | | Total | | $ | 21.68 | | | | -46 | % | | $ | 40.33 | | | | +20 | % | | $ | 33.70 | |
(1) | Prices presented exclude any effects of oil, gas and NGL derivatives. |
(2) | The reported Canadian gas volumes include 12, 21 and 25 MMcf per day for the years ended 2015, 2014 and 2013, respectively, that are produced from certain of our leases and then transported to our Jackfish operations where the gas is used as fuel. However, the revenues and expenses related to this consumed gas are eliminated in our consolidated financial results. With the sale of the vast majority of the Canadian gas business in the second quarter of 2014, the eliminated gas revenues subsequently impacted our gas price more significantly. |
Commodity SalesNGLs.
The volume and price changesincrease in the tables above caused the following changes to our oil gas and NGL sales.sales primarily resulted from higher average WTI crude index prices, which were 27% higher in 2018, resulting in an increase of approximately $568 million. | | | | | | | | | | | | | | | | | | | | | | | Oil | | | Bitumen | | | Gas | | | NGLs | | | Total | | | | (Millions) | | 2013 sales | | $ | 3,668 | | | $ | 902 | | | $ | 2,698 | | | $ | 1,254 | | | $ | 8,522 | | Change due to volumes | | | 1,311 | | | | 76 | | | | (533 | ) | | | 131 | | | | 985 | | Change due to prices | | | (206 | ) | | | 160 | | | | 572 | | | | (123 | ) | | | 403 | | | | | | | | | | | | | | | | | | | | | | | 2014 sales | | $ | 4,773 | | | $ | 1,138 | | | $ | 2,737 | | | $ | 1,262 | | | $ | 9,910 | | Change due to volumes | | | 976 | | | | 584 | | | | (443 | ) | | | (23 | ) | | | 1,094 | | Change due to prices | | | (2,813 | ) | | | (1,000 | ) | | | (1,034 | ) | | | (775 | ) | | | (5,622 | ) | | | | | | | | | | | | | | | | | | | | | | 2015 sales | | $ | 2,936 | | | $ | 722 | | | $ | 1,260 | | | $ | 464 | | | $ | 5,382 | | | | | | | | | | | | | | | | | | | | | | |
Volumes 2015 vs. 2014 Oil, gas and NGL sales increased due to volumes in 2015 because of strong production growth from our U.S. oil properties. The growth was primarily driven by the continued development of our Eagle Ford, Delaware Basin and Rockies Oil properties. Additionally, our bitumen production increased primarily due to Jackfish 3 coming on-line late in the third quarter of 2014 and reaching nameplate capacity in the third quarter of 2015. Lower royalties resulting from the significant price decrease also increased our heavy
oil production. The increases were partially offset by a decrease in our gas production, which resulted primarily from asset divestitures in 2014 and natural reservoir declines.
Volumes 2014 vs. 2013 Oil, gas and NGL sales increased due to volumes primarily because of a 66% increase in our core assets oil production. Such growth resulted from our Eagle Ford properties and the continued development of our properties in the Delaware Basin. In addition, we continued to grow our NGL production from the Delaware Basin and STACK, which resulted in $131$351 million of additional sales. Bitumen sales increased due to development of our Jackfish thermal heavy oil projects in Canada, including Jackfish 3 which had first sales in 2014. These increases were partially offset by a 20% decrease in our 2014 gas production, which was impacted by our asset divestitures and natural declines.
Prices 2015 vs. 2014 Oil, gas and NGL sales decreased in 2015 as a result of significantly lower prices for all commodities. The decrease in oil and bitumen sales primarily resulted from significantly lower average WTI crude oil index prices, which were approximately 50% lower in 2015 as compared to 2014. The decreases in gas and NGL sales were driven by lower North American regional index prices upon which our gas sales are based and lower14% higher NGL prices at the Mont Belvieu, Texas hub.
Prices 2014 vs. 2013 Oil, gas and NGL sales increased primarily because of a 20% increasehub, as well as improved realizations in our realized prices without hedges. Our gas sales were the most significantly impacted. The change in our realized gas price was largely due to higher North American regional index prices upon which our gas sales are based. Additionally, our bitumen sales increased as a result of a 16% increase in our realized price, as a result of tighter bitumen and heavy oil differentials. NGL price.
These increases were partially offset by lowerwidening 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 NGLnegatively impacted the price we realized prices resulting from lower WTI crude oil index prices and lower NGL prices at the Mont Belvieu, Texas hub. Oil, Gas and NGL Derivatives
The following tables provide financial information associated withon our oil, gas and NGL hedges. The first table presents the cash settlements and fair value gains and losses recognized as componentsCanadian production. We had basis swaps for approximately half of our revenues. The subsequent tables present our oil, gas and NGL prices with and withoutfourth quarter production to mitigate the effect of the lower market price. To further mitigate the effects of the cash settlements. The prices do not includelower 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 effects of fair value gains and losses.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.
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | Cash settlements: | | | | | | | | | | | | | Oil derivatives | | $ | 2,083 | | | $ | 90 | | | $ | 55 | | Gas derivatives | | | 333 | | | | (36 | ) | | | 139 | | NGL derivatives | | | — | | | | 1 | | | | 1 | | | | | | | | | | | | | | | Total cash settlements | | | 2,416 | | | | 55 | | | | 195 | | | | | | | | | | | | | | | Gains (losses) on fair value changes: | | | | | | | | | | | | | Oil derivatives | | | (1,687 | ) | | | 1,721 | | | | (243 | ) | Gas derivatives | | | (226 | ) | | | 213 | | | | (139 | ) | NGL derivatives | | | — | | | | — | | | | (4 | ) | | | | | | | | | | | | | | Total gains (losses) on fair value changes | | | (1,913 | ) | | | 1,934 | | | | (386 | ) | | | | | | | | | | | | | | Oil, gas and NGL derivatives | | $ | 503 | | | $ | 1,989 | | | $ | (191 | ) | | | | | | | | | | | | | |
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. | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2015 | | | | Oil (Per Bbl) | | | Bitumen (Per Bbl) | | | Gas (Per Mcf) | | | NGLs (Per Bbl) | | | Boe (Per Boe) | | Realized price without hedges | | $ | 42.12 | | | $ | 23.41 | | | $ | 2.14 | | | $ | 9.32 | | | $ | 21.68 | | Cash settlements of hedges | | | 29.88 | | | | — | | | | 0.57 | | | | — | | | | 9.74 | | | | | | | | | | | | | | | | | | | | | | | Realized price, including cash settlements | | $ | 72.00 | | | $ | 23.41 | | | $ | 2.71 | | | $ | 9.32 | | | $ | 31.42 | | | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2014 | | | | Oil (Per Bbl) | | | Bitumen (Per Bbl) | | | Gas (Per Mcf) | | | NGLs (Per Bbl) | | | Boe (Per Boe) | | Realized price without hedges | | $ | 82.47 | | | $ | 55.88 | | | $ | 3.90 | | | $ | 24.89 | | | $ | 40.33 | | Cash settlements of hedges | | | 1.56 | | | | — | | | | (0.05 | ) | | | 0.02 | | | | 0.22 | | | | | | | | | | | | | | | | | | | | | | | Realized price, including cash settlements | | $ | 84.03 | | | $ | 55.88 | | | $ | 3.85 | | | $ | 24.91 | | | $ | 40.55 | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | % |
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2013 | | | | Oil (Per Bbl) | | | Bitumen (Per Bbl) | | | Gas (Per Mcf) | | | NGLs (Per Bbl) | | | Boe (Per Boe) | | Realized price without hedges | | $ | 86.02 | | | $ | 48.04 | | | $ | 3.09 | | | $ | 27.33 | | | $ | 33.70 | | Cash settlements of hedges | | | 1.30 | | | | — | | | | 0.16 | | | | 0.01 | | | | 0.77 | | | | | | | | | | | | | | | | | | | | | | | Realized price, including cash settlements | | $ | 87.32 | | | $ | 48.04 | | | $ | 3.25 | | | $ | 27.34 | | | $ | 34.47 | | | | | | | | | | | | | | | | | | | | | | |
Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments. A summary of our open commodity derivative positions is includedthe instruments described in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. Our oil, gas and NGL derivatives include price swaps, costless collars, basis swaps and call options. To facilitate a portion of our price swaps, we sold gas and oil call options for 2015 through 2016. The call options give counterparties the right to purchase production at a predetermined price. 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 relationshipsrelationship between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated net gains in 2015 and 2014 and incurred a net loss in 2013. Marketing and Midstream Revenues and Operating Expenses
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | Change | | | 2014 | | | Change | | | 2013 | | | | (Millions) | | Operating revenues | | $ | 7,260 | | | | -5 | % | | $ | 7,667 | | | | +271 | % | | $ | 2,066 | | Product purchases | | | (6,028 | ) | | | -8 | % | | | (6,540 | ) | | | +382 | % | | | (1,356 | ) | Operations and maintenance expenses | | | (392 | ) | | | +43 | % | | | (275 | ) | | | +40 | % | | | (197 | ) | | | | | | | | | | | | | | | | | | | | | | Operating profit | | $ | 840 | | | | -1 | % | | $ | 852 | | | | +66 | % | | $ | 513 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Devon profit | | $ | 14 | | | | -84 | % | | $ | 88 | | | | -5 | % | | $ | 93 | | EnLink profit | | | 826 | | | | +8 | % | | | 764 | | | | +82 | % | | | 420 | | | | | | | | | | | | | | | | | | | | | | | Total profit | | $ | 840 | | | | -1 | % | | $ | 852 | | | | +66 | % | | $ | 513 | | | | | | | | | | | | | | | | | | | | | | |
2015 vs. 2014 Marketing and midstream operating profit changes were largely driven by a full year of EnLink’s legacy asset operations compared to prior year and facility expansions coming online in late 2014, along with assets acquired during 2015. The change was offset by a decrease in Devon’s marketing activitiesProduction 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 a decrease in commodity prices. 2014 vs. 2013 Marketingcontinued focus on growing our liquids-rich assets within the STACK and midstream operating profit largely increased as a result ofDelaware Basin and higher prices and volumes,maintenance costs at our Jackfish facilities, partially offset by higher operationsour U.S. non-core divestitures.
As further discussed in Note 1 in “Item 8. Financial Statements and maintenance expenses. OfSupplementary Data” of this report, in 2018 the $339 millionpresentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase $344 million was attributed to EnLink’s operations. Higher profits from EnLink’s Texas segment, which includes the Bridgeport facility, and Louisiana segment were the largest drivers of the increase. The Louisiana segment operating profit increased because of acquisitions and completions of additional pipelines. Devon’s marketing activities were the primary driver of the increases in both operatingour upstream revenues and product purchases. The higher marketing revenues and product purchases areproduction expenses by approximately $254 million with no impact to net earnings.
Production taxes increased on an absolute dollar basis primarily due to commitments we entered into to secure capacity on downstream oil pipelines. Marketing activities of EnLink also contributed to these increases. Lease Operating Expenses
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | Change | | | 2014 | | | Change | | | 2013 | | | | (Millions, except per Boe amounts) | | LOE: | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 1,551 | | | | -0 | % | | $ | 1,559 | | | | +24 | % | | $ | 1,257 | | Canada | | | 553 | | | | -28 | % | | | 773 | | | | -24 | % | | | 1,011 | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 2,104 | | | | -10 | % | | $ | 2,332 | | | | +3 | % | | $ | 2,268 | | | | | | | | | | | | | | | | | | | | | | | LOE per Boe: | | | | | | | | | | | | | | | | | | | | | U.S. | | $ | 7.52 | | | | +0 | % | | $ | 7.52 | | | | +13 | % | | $ | 6.65 | | Canada | | $ | 13.18 | | | | -34 | % | | $ | 20.10 | | | | +27 | % | | $ | 15.78 | | Total | | $ | 8.48 | | | | -11 | % | | $ | 9.49 | | | | +6 | % | | $ | 8.97 | |
2015 vs. 2014 LOE per Boe decreased during 2015 primarily as a result of higher Jackfish 3 volumes, our well optimization and cost reduction initiatives, lower royalties and changes in the Canadian to U.S. foreign exchange rate. As Canadian royalties decrease, our net production volumes increase, causing improvements to our per-unit operating costs. The flat U.S. rate is primarily related to our 2014 non-core natural gas asset divestitures and our oil production growth, where projects generate higher margins but generally require a higher cost to produce per unit than our retained and divested gas projects.
2014 vs. 2013 Our absolute LOE changed largely as a result of our portfolio transformation initiatives, including our February 2014 purchase of Eagle Ford assets and our 2014 divestitures of non-core gas properties in the U.S. and Canada. Higher volumes from development of our Eagle Ford assets, as well as our Delaware Basin assets, caused U.S. LOE to increase. This increase was partially offset by the decrease resulting from the U.S. divestitures. The Canadian divestitures were the primary cause of the decrease in Canadian LOE.
Total LOE increased $0.52 per Boe primarily because of higher unit costs related to our Canadian operations. The higher Canadian unit costs largely resulted from the divestiture of the conventional natural gas assets in the second quarter of 2014 which resulted in lower total volumes while retaining the relatively higher-cost thermal heavy oil operations. Additionally, higher Jackfish royalties paid in 2014 also contributed to higher Canadian unit costs. The higher unit cost in the U.S. was primarily related to our liquids production growth, particularly in the Delaware Basin and Mississippian-Woodford Trend, where projects generate higher revenues but generally require a higher cost to produce per unit than our gas projects. Additionally, we experienced inflationary pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.
General and Administrative Expenses
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | Change | | | 2014 | | | Change | | | 2013 | | | | (Millions, except per Boe amounts) | | Gross G&A | | $ | 1,347 | | | | -2 | % | | $ | 1,369 | | | | +21 | % | | $ | 1,128 | | Capitalized G&A | | | (372 | ) | | | -1 | % | | | (376 | ) | | | +2 | % | | | (368 | ) | Reimbursed G&A | | | (120 | ) | | | -18 | % | | | (146 | ) | | | +2 | % | | | (143 | ) | | | | | | | | | | | | | | | | | | | | | | Net G&A | | $ | 855 | | | | +1 | % | | $ | 847 | | | | +37 | % | | $ | 617 | | | | | | | | | | | | | | | | | | | | | | | Net G&A per Boe | | $ | 3.45 | | | | +0 | % | | $ | 3.45 | | | | +41 | % | | $ | 2.44 | | | | | | | | | | | | | | | | | | | | | | |
2015 vs. 2014 Gross G&A decreased during 2015 largely because of a lower employee performance bonus pool and our cost reduction initiatives. Furthermore, $22 million in one-time costs related to the EnLink and GeoSouthern transactions contributed to higher costs in the first quarter of 2014. These decreases were offset by an increase in EnLink G&A of approximately $40 million primarily resulting from a workforce increase associated with EnLink’s 2015 acquisitions. Reimbursed G&A decreased subsequent to our 2014 asset divestitures.
2014 vs. 2013 Net G&A and net G&A per Boe increased largely due to higher employee compensation and benefits and $22 million of 2014 costs related to the EnLink and GeoSouthern transactions. The higher employee compensation and benefits costs were primarily related to share-based awards, which cause our G&A to be higher in the period in which our annual share-based grant is made. The grant related to our 2013 compensation cycle was made in the first quarter of 2014. The grant related to our 2012 compensation cycle was made in the fourth quarter of 2012. Additionally, the expansion of our workforce as a part of growing production operations at certain of our key areas also contributed to the increase.
Production and Property Taxes
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | Change | | | 2014 | | | Change | | | 2013 | | | | (Millions) | | Production | | $ | 198 | | | | -45 | % | | $ | 360 | | | | +31 | % | | $ | 275 | | Property and other | | | 190 | | | | +8 | % | | | 175 | | | | -6 | % | | | 186 | | | | | | | | | | | | | | | | | | | | | | | Production and property taxes | | $ | 388 | | | | -28 | % | | $ | 535 | | | | +16 | % | | $ | 461 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Percentage of oil, gas and NGL sales: | | | | | | | | | | | | | | | | | | | | | Production | | | 3.7 | % | | | +1 | % | | | 3.6 | % | | | +13 | % | | | 3.2 | % | Property and other | | | 3.5 | % | | | +100 | % | | | 1.8 | % | | | -19 | % | | | 2.2 | % | | | | | | | | | | | | | | | | | | | | | | Total | | | 7.2 | % | | | +33 | % | | | 5.4 | % | | | -0 | % | | | 5.4 | % | | | | | | | | | | | | | | | | | | | | | |
2015 vs. 2014 Our absolute production taxes decreased during 2015 primarily because of a decrease in our U.S. upstream revenues, on which the majority of our production taxes are assessed. Property taxesAdditionally, 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 salessales.
Property taxes increased during 2015as a result of higher property value assessments, primarily on our Texas properties, partially offset by our U.S. non-core divestitures. | | 2018 | | | 2017 | | | Change | | Marketing revenues | | $ | 4,449 | | | $ | 3,571 | | | | +25 | % | Marketing expenses | | | (4,363 | ) | | | (3,619 | ) | | | - 21 | % | Margin | | $ | 86 | | | $ | (48 | ) | | | +279 | % |
30
Table of Contents Index to Financial Statements The overall increase in marketing operating margin was primarily due to ad valorem and other taxes thatimproved commodity prices, which were partially offset by the impact of our downstream marketing commitments. | | 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 changeintend to pursue further exploration and development. Geological and geophysical costs decreased primarily in direct correlation withthe STACK and Delaware Basin. Depreciation, Depletion and Amortization |
| | 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 NGL sales.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. 2014 vs. 2013 Production
General and Administrative Expenses |
| | 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 property taxes increasedbenefits decreased primarily as a result of an increasethe workforce reduction that occurred during 2018 as discussed in our U.S. revenues. Depreciation, Depletion and Amortization
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | Change | | | 2014 | | | Change | | | 2013 | | | | (Millions, except per Boe amounts) | | DD&A: | | | | | | | | | | | | | | | | | | | | | Oil and gas properties | | $ | 2,580 | | | | -11 | % | | $ | 2,896 | | | | +18 | % | | $ | 2,465 | | Other assets | | | 549 | | | | +30 | % | | | 423 | | | | +34 | % | | | 315 | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 3,129 | | | | -6 | % | | $ | 3,319 | | | | +19 | % | | $ | 2,780 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | DD&A per Boe: | | | | | | | | | | | | | | | | | | | | | Oil and gas properties | | $ | 10.40 | | | | -12 | % | | $ | 11.79 | | | | +21 | % | | $ | 9.75 | | Other assets | | | 2.21 | | | | +28 | % | | | 1.72 | | | | +38 | % | | | 1.24 | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 12.61 | | | | -7 | % | | $ | 13.51 | | | | +23 | % | | $ | 10.99 | | | | | | | | | | | | | | | | | | | | | | |
A description of how DD&A of our oil and gas properties is calculated is included in Note 16 in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, the DD&A rate per unitNon-labor costs were higher due to an increase in costs related to automation and process improvements.
Financing costs, net increased $277 million as a result of production will change inversely. However, when the depletable base changes, the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unita $312 million loss on early retirement of production, generally moves in the same direction as production volumes. 2015 vs. 2014DD&Adebt. For further discussion of early retirement premiums and reduced interest expense resulting from our oillower debt balances, see Note 15 in
“Item 8. Financial Statements and gas properties decreasedSupplementary Data” of this report. | | 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 2015 compared to 2014 largely because of the 2014 divestitures of certain U.S. and Canadian assets and the oil and gas asset impairments recognized in 2015. Other DD&A increased primarily due to EnLink’s acquisitions in 2014 and 2015. 2014 vs. 2013DD&A from our oil and gas properties increased in 2014 largely because of higher DD&A rates. The higher rates resulted from our oil and gas drilling and development activities and the GeoSouthern acquisition, which were partially offset by the asset impairments recognized in 2013 and the 2014 asset divestitures. Other DD&A increased primarily due to the formation of EnLink in 2014.
Asset Impairments
During 2015, 2014 and 2013, we recognized asset impairments of $20.8 billion, $2.0 billion and $2.0 billion, respectively. For discussion on asset impairments, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.
Restructuring Costs
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 2015, 2014 and 2013,2018, we recognized restructuring and transaction costs of $78$114 million $46primarily 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. | | 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 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. 31
Table of Contents Index to Financial Statements 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. ![](https://files.docoh.com/10-K/0001564590-19-003382/gllsi02ldj4j000007.jpg)
| (1) | Other in the table above includes asset impairments, asset dispositions, restructuring and transaction costs and other expenses. |
The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph. ![](https://files.docoh.com/10-K/0001564590-19-003382/gllsi02ldj4j000008.jpg)
32
Table of Contents Index to Financial Statements
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 $54natural 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 | % |
33
Table of Contents Index to Financial Statements
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 respectively.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. | | 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 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. | | 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. 34
Table of Contents Index to Financial Statements 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. GainsThe remaining change in other expense was driven primarily by changes on Asset Sales
In conjunction with the divestiture of certain Canadian properties, we recognized gains of $1.1 billionforeign currency exchange instruments, as further discussed in 2014. For further discussion, see Note 27 in “Item 8. Financial Statements and Supplementary Data” of this report.
Net Financing Costs
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | Change | | | 2014 | | | Change | | | 2013 | | | | (Millions) | | Interest based on debt outstanding | | $ | 565 | | | | +6 | % | | $ | 532 | | | | +14 | % | | $ | 466 | | Early retirement of debt | | | — | | | | N/M | | | | 48 | | | | N/M | | | | — | | Capitalized interest | | | (62 | ) | | | -11 | % | | | (70 | ) | | | +26 | % | | | (56 | ) | Other fees and expenses | | | 20 | | | | -24 | % | | | 26 | | | | -1 | % | | | 27 | | | | | | | | | | | | | | | | | | | | | | | Interest expense | | | 523 | | | | -3 | % | | | 536 | | | | +23 | % | | | 437 | | Interest income | | | (6 | ) | | | -41 | % | | | (10 | ) | | | -49 | % | | | (20 | ) | | | | | | | | | | | | | | | | | | | | | | Net financing costs | | $ | 517 | | | | -2 | % | | $ | 526 | | | | +26 | % | | $ | 417 | | | | | | | | | | | | | | | | | | | | | | |
2015 vs. 2014 Net financing costs decreased during 2015 primarily as a result of the retirement premium and costs related to the early redemption of senior notes in 2014, which is further discussed in
| | 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 138 in “Item 8. Financial Statements and Supplementary Data” of this report. Interest on outstanding borrowings increased during 2015 primarily due to an increase of $51 million in EnLink interest expense as a result of an increase in fixed-rate borrowings, partially offset by a $18 million decrease in Devon interest expense as a result of a decrease in its average fixed-rate borrowings. 2014 vs. 2013 Net financing costs increased primarily because of higher average borrowings resulting from the EnLink and GeoSouthern transactions and the 2014 early retirement premium and costs.
Income Taxes
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | Total income tax expense (benefit) (millions) | | $ | (6,065 | ) | | $ | 2,368 | | | $ | 169 | | | | | | | | | | | | | | | Effective income tax rate | | | (29 | )% | | | 58 | % | | | 113 | % | | | | | | | | | | | | | |
For discussion on income taxes,discontinued operations, see Note 719 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 source and use categories of ourchanges in cash and cash equivalents.equivalents for the time periods presented below. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Devon | | | EnLink | | | Consolidated | | | | 2015 | | | 2014 | | | 2015 | | | 2014 | | | 2015 | | | 2014 | | | 2013(1) | | | | (Millions) | | Operating cash flow | | $ | 4,756 | | | $ | 5,467 | | | $ | 627 | | | $ | 514 | | | $ | 5,383 | | | $ | 5,981 | | | $ | 5,436 | | Sale of subsidiary units | | | 654 | | | | — | | | | — | | | | — | | | | 654 | | | | — | | | | — | | Divestitures of property and equipment | | | 106 | | | | 5,120 | | | | 1 | | | | — | | | | 107 | | | | 5,120 | | | | 419 | | Capital expenditures | | | (4,735 | ) | | | (6,192 | ) | | | (573 | ) | | | (796 | ) | | | (5,308 | ) | | | (6,988 | ) | | | (6,502 | ) | Acquisitions of property, equipment and businesses | | | (583 | ) | | | (6,104 | ) | | | (524 | ) | | | (358 | ) | | | (1,107 | ) | | | (6,462 | ) | | | (256 | ) | Short-term investment activity, net | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2,343 | | Debt activity, net | | | 770 | | | | (2,789 | ) | | | 1,061 | | | | 555 | | | | 1,831 | | | | (2,234 | ) | | | 361 | | Shareholder and noncontrolling interests distributions | | | (396 | ) | | | (486 | ) | | | (254 | ) | | | (135 | ) | | | (650 | ) | | | (621 | ) | | | (348 | ) | EnLink and General Partner distributions | | | 268 | | | | 158 | | | | (268 | ) | | | (158 | ) | | | — | | | | — | | | | — | | EnLink dropdowns | | | 167 | | | | — | | | | (167 | ) | | | — | | | | — | | | | — | | | | — | | Stock option proceeds | | | 4 | | | | 93 | | | | — | | | | — | | | | 4 | | | | 93 | | | | 3 | | Issuance of subsidiary units | | | — | | | | — | | | | 25 | | | | 410 | | | | 25 | | | | 410 | | | | — | | Effect of exchange rate and other | | | (131 | ) | | | 79 | | | | 22 | | | | 36 | | | | (109 | ) | | | 115 | | | | (27 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net change in cash and cash equivalents | | $ | 880 | | | $ | (4,654 | ) | | $ | (50 | ) | | $ | 68 | | | $ | 830 | | | $ | (4,586 | ) | | $ | 1,429 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents at end of period | | $ | 2,292 | | | $ | 1,412 | | | $ | 18 | | | $ | 68 | | | $ | 2,310 | | | $ | 1,480 | | | $ | 6,066 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | |
(1) | 2013 amounts for EnLink consist of legacy Devon midstream assets. |
Operating Cash Flow – Continuing Operations Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2015.2018. Our operating cash flow decreased 10% during 2015 primarily duewas relatively flat compared to lower commodity prices. The effects of lower commodity prices were partially offset by the collection of $425 million of income taxes receivable in the first quarter of 2015 and $2.4 billion of cash settlements associated with2017. In 2018, our commodity derivatives during 2015. Our operating cash flow increased 10% during 2014 primarily because of higher realized prices and liquids production growth, partially offset by higher expenses.
Excluding payments made for acquisitions, our consolidated operating cash flow funded 100% and approximately 86% of our capital expenditures during 2015expenditure program and 2014, respectively. In 2015 and 2014, leveraging our liquidity and other capital resources, we also useddividends. We utilized available cash balances short-term debt, proceeds from EnLink transactions and divestiture proceeds to fundsupplement our acquisitions, dividends and capital requirements.
Saleoperating cash flows. Operating cash flow for 2018 included a realized foreign exchange loss of Subsidiary Units
In early 2015, we conducted an underwritten secondary public offering of 26.2$241 million common units representing limited partner interestsrelating to foreign currency denominated intercompany loan activity as described in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 177 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. 35
Table of Contents Index to Financial Statements Divestitures of Property and EquipmentInvestments During 2014, we completed2018, as part of our Canadian assetannounced 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 received proceedsSupplementary Data” of approximately $2.9 billion. Additionally, we completed the divestment of certainthis 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 received proceedsSupplementary Data” of approximately $2.2 billion.this report. During 2013,2016, we solddivested certain non-core upstream assets in the U.S. and our Thunder Creek operations50% interest in Wyomingthe Access Pipeline in Canada for approximately $148 million$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 Bear Paw Basin assetscore resource plays. For further discussion, see Note 2 in Havre, Montana for approximately $73 million. “Item 8. Financial Statements and Supplementary Data” of this report. We also sold other minor oildid not have significant current cash income taxes resulting from the divestitures in 2018, 2017 and gas assets.2016. Capital Expenditures The following table summarizes our capital expenditures and property acquisitions. | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | Oil and gas | | $ | 4,577 | | | $ | 5,735 | | | $ | 5,710 | | Midstream | | | 56 | | | | 348 | | | | 455 | | Corporate and other | | | 102 | | | | 109 | | | | 93 | | | | | | | | | | | | | | | Devon capital expenditures | | | 4,735 | | | | 6,192 | | | | 6,258 | | EnLink capital expenditures | | | 573 | | | | 796 | | | | 244 | | | | | | | | | | | | | | | Total capital expenditures | | $ | 5,308 | | | $ | 6,988 | | | $ | 6,502 | | | | | | | | | | | | | | | Devon acquisitions | | $ | 583 | | | $ | 6,104 | | | $ | 256 | | EnLink acquisitions | | | 524 | | | | 358 | | | | — | | | | | | | | | | | | | | | Total acquisitions | | $ | 1,107 | | | $ | 6,462 | | | $ | 256 | | | | | | | | | | | | | | |
| | 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 our midstream operations,and other corporate activities and EnLink growth and maintenance activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. In responseOur capital program is designed to loweroperate within or near operating cash flow and may fluctuate with changes to commodity prices Devon’s 2015 capital program was designed to be lower than 2014, particularly compared to the second half of 2014 when oil prices began to significantly decline.and other factors impacting cash flow. This change is evidenced by a 48% decreaseour operating cash flow funding approximately 91% of capital expenditures in exploration2018 and developmentfully funding capital expenditures in 2017. Acquisition costs fromin 2016 primarily consisted of Devon’s bolt-on acquisition of assets in the fourth quarterSTACK play for $1.5 billion. Approximately $849 million was paid in cash at closing with the remainder of 2014the 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 the fourth quartercompleted tender offers of 2015,certain long-term debt as well as the maturity of certain senior notes. In conjunction with the tender offers, we recognized a 24% decrease$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 total“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. 36
Table of Contents Index to Financial Statements 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 from 2014 to 2015, excluding acquisitions. Excluding acquisitions, oil and gas capital spending was flat from 2013 to 2014, primarily due to utilization of the drilling carries in 2014 from our joint venture arrangements. other items. Capital expenditures for Devon’sEnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelinespipelines. During 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. During 2016, EnLink acquired Anadarko Basin gathering and are largely impacted by Devon’s oil and gas drilling activities. Our 2014 and 2013processing midstream capital expenditures largely related toassets for $1.5 billion. Approximately $792 million was paid in cash at closing with the expansion of our Access Pipeline in Canada. The majority of our midstream capital is incurred by EnLink. EnLink’s 2015 capital expenditures decreased compared to 2014 primarily as a result of pipeline construction and expansion projects that went into service in 2014. EnLink’s 2013 capital expenditures primarily related to expansions of plants serving the Barnett Shale and Cana-Woodford Shale. Acquisition capital spend in 2015 primarily consistedremainder of the Powder River Basin asset acquisitionpurchase 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 fourth quarter. The majority oftable above exclude the acquisition capital in 2014 related to the GeoSouthern acquisition in the Eagle Ford. EnLink’s acquisitions in 2015 and 2014 consisted of additional oil and gas pipeline assets, including gathering, transportation and processing facilities. For further discussion on EnLink acquisition activity, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report. Short-Term Investment Activity, Net
During 2013, we purchased approximately $1.1 billion of short-term investments and redeemed approximately $3.4 billion. We consider securities with original contract maturities in excess of three months but less than one year to be short-term investments.
Debt Activity, Net
During 2015, our consolidated net debt borrowings increased $1.8 billion. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announced in the fourth quarter. EnLink’s net debt borrowings increased $1.1 billion primarily from borrowings made to fund acquisitions and dropdowns.
During 2014, we decreased our net debt borrowings by $2.2 billion. The decrease was primarily related to the repayment of debt used to fund the GeoSouthern transaction. This was partially offset by $555 million of net borrowings from EnLink to fund its operations.
During 2013, we increased our debt borrowings by $361 million as a result of issuing $2.25 billion of debt related to the planned Eagle Ford acquisition and repaying approximately $1.9 billion of outstanding short-term debt.
Shareholder and Noncontrolling Interests Distributions
The following table summarizes our common stock dividends. The quarterly cash dividend was $0.20 per share in the first quarter of 2013. We increased the dividend rate to $0.22 per share in the second quarter of 2013 and to $0.24 per share in the second quarter of 2014.
| | | | | | | | | | | | | | | | | | | | | | | | | | | 2015 | | | 2014 | | | 2013 | | | | Amount | | | Per Share | | | Amount | | | Per Share | | | Amount | | | Per Share | | | | (Millions, except per share amounts) | | Dividends | | $ | 396 | | | $ | 0.96 | | | $ | 386 | | | $ | 0.94 | | | $ | 348 | | | $ | 0.86 | |
In conjunction with the formation of EnLink in the first quarter of 2014, we made a payment of $100 million to noncontrolling interests. Furthermore,distributions EnLink and the General Partner distributed $254 and $135 millionpaid to non-Devon unitholders during 2015 and 2014, respectively.
EnLink and General PartnerDevon, which have been eliminated in consolidation. Distributions
Devon received $268 million and $158 million in distributions from EnLink Enlink and the General Partner paid to Devon were $134 million, $265 million and $265 million during 20152018, 2017 and 2014,2016, respectively.
EnLink DropdownsLiquidity
In the second quarterThe business of 2015, Devon received $167 million in cashexploring 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 EnLink in exchange for VEX. For further discussion, see Note 2 in “Item 8.existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.
37
Table of Contents Index to Financial Statements and Supplementary Data” of this report. Stock Option Proceeds
We received $4 million, $93 million and $3 million from stock option proceeds in 2015, 2014 and 2013, respectively.
Issuance of Subsidiary Units
During 2015 and 2014, EnLink issued and sold approximately 1.3 million and 14.8 million common units through general public offerings and its “at the market” equity program, generating net proceeds of approximately $25 million and $410 million, respectively. Furthermore, in October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction with the General Partner, generating approximately $50 million in proceeds.
Liquidity
Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds and cash on hand.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. Other available sources of capital and liquidity include, among other things, If needed, we can also issue debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well asSEC. 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 sale of a portion of ourproceeds from these transactions for debt repayments and common units representing interests in our investment in EnLink and the General Partner.share repurchases. We estimate the combination of theseour sources of capital will continue to be adequate to fund futureour planned capital expenditures, debt repayments and other contractual commitmentsrequirements 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 isforecasts are sensitive to many variables theand include a measure of uncertainty as these variables differ from our expectations. Commodity Prices – The most uncertain and volatile of whichvariables for our operating cash flow are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our consolidated operating cash flow decreased 10% in 2015 as a result of the significant decrease in commodity prices. In spite of this decline, we expect operating cash flow to continue to be a primary source of liquidity as we adjust our capital program in response to lower commodity prices. Additionally, we anticipate utilizing divestiture proceeds and our credit availability to provide additional liquidity as needed. Commodity Prices– 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. We expect lowerFor 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 continue throughout 2016, and currently,protect a portion of our production is largely unhedged. Ifagainst 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 prices remain consistentprice volatility. We supplement the systematic hedging program with 2015discretionary 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 unable to obtain favorable hedge contractsadding hedges for 2020 as well. Further insulating our 2016 production, our 2016 operating cash flow, could materially decline from what it waswe are proactively locking in 2015. 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, 20152018 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. Divestitures of PropertyFor 2019, we expect to aggressively optimize our cost structure in conjunction with our planned Canadian and Equipment – InBarnett Shale asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with the fourth quarter of 2015, we announced our intention to monetize up to 80 MBoe per day of certain non-core upstream assets across our portfolio in 2016. In addition, we also intend to market our Access Pipeline in Canada.retained business and reduce outstanding debt. We anticipate these divestituresthe planned $780 million reduction of annualized costs will generate approximately $2 billionoccur over three years, with roughly 70% of the savings delivered by the end of 2019. Approximately 40% of the reduced costs relate to $3 billion of proceedsour capital programs and the remainder relates to further strengthen our financial position in 2016.operating expenses, including G&A, interest expense and production expenses.
Interest Rates– Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2015, we had total debt of $13.1 billion with an overall weighted-average borrowing rate of 4.9%. Of the $13.1 billion of total debt, $1.4 billion is comprised of floating rate debt instruments that bear interest rates averaging 1.1%.
Credit Losses– Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed toThis includes the credit risk of therelated to customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related toproduction, the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. Additionally, we are exposed to the credit risk ofoperate 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. As recent years indicate, we have a history38
Table of investing more than 100%Contents Index to Financial Statements Divestitures of our operating cash flow into capital development activities to grow our companyProperty and maximize value for our shareholders. Therefore, negative movements in any of the variables discussed above would not only impact our operating cash flow but also would likely impact the amount of capital investment we could or would make. Equipment In the current environment, assuming current pricing expectations,first quarter of 2019, we sold non-core assets for approximately $300 million. We also anticipate separating our 2016 explorationCanadian and development capital budget is expected to be approximately $900 million to $1.1 billion, or roughly 75% less thanBarnett Shale businesses from our 2015 capital program. With our 2016 capital focused primarily on oil development, we anticipate our oil production will remain relatively flat from 2015 to 2016, but our natural gas and NGL production will decline, resultingCompany in a 6% production decline in our core assets.2019. At the end of 2015, we held approximately $2.3 billion of cash. Included in this total was $646 million of cash held by our foreign subsidiaries. If we were to repatriate a portion or all of the cash held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U.S. tax law. The payment of such additional income tax would decrease the amount of cash ultimately available to fund our business.
Credit Availability We have a $3.0 billion Senior Credit Facility. The maturity date for $30 million of theOur 2018 Senior Credit Facility, isunder which we have $2.9 billion of available borrowing capacity at December 31, 2018, matures on October 24, 2017. The5, 2023, with the option to extend the maturity date for $164 million of theby two additional one-year periods subject to lender consent. The 2018 Senior Credit Facility is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of December 31, 2015,2018, there were no borrowings under the Senior Credit Facility.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%. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as full cost ceiling and goodwill impairments. As of December 31, 2015,2018, we were in compliance with this covenant. Ourcovenant with a 21.0% debt-to-capitalization ratio at December 31, 2015, as calculated pursuant to the terms of the agreement, was 23.7%.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. Our Senior Credit Facility supports our $3.0 billion of short-term credit under our commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the commercial paper market. As of December 31, 2015, we had $626 million of borrowings under our commercial paper program.
EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million revolving credit facility. As of December 31, 2015, there were $11 million in outstanding letters of credit and $414 million borrowed under the $1.5 billion credit facility and no outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
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 Devon and EnLink are rated byWe receive debt ratings from the major debt ratings agencies in the U.S. However, the General Partner does not receive debt ratings. In determining thoseour 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 near-term and long-termproduction growth opportunitiesopportunities. Our credit rating from Standard and capital allocation challenges.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 or EnLink’s contractual debt obligations that would accelerate scheduled maturities should our debt ratingsrating fall below a specified level. However, a ratings downgrade could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future. Capital ExpendituresShare Repurchase Program
In January 2016, Devon acquired Anadarko Basin STACK assets for approximately $1.5February 2019, our Board of Directors increased our share repurchase program by an additional $1 billion. The $5 billion in cashshare repurchase program expires December 31, 2019. Through February 15, 2019, we have executed $3.4 billion of the authorized program. 39
Table of Contents Index to Financial Statements Capital Expenditures Our 2019 exploration and equity, subject to certain adjustments. Including this acquisition but excluding EnLink, our 2016 capital expenditures aredevelopment budget is expected to range from $1.2be approximately $2.0 billion to $1.4$2.25 billion, including $900 million to $1.1 billion for our oil and gas capital program. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from our current estimates, we could choose to defer a portion of these planned 2016 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2016 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2016, available cash balances and credit availability and proceeds from our divestiture program, we anticipate having adequate capital resources to fund our 2016 capital expenditures. In connectionassociated with our acquisition of the STACK playCanadian and Powder River Basin assets, we issued 23,470,000 shares of our common stock (the “STACK Acquisition Shares”) and 6,857,488 shares of our common stock (the “PRB Acquisition Shares”), respectively. Pursuant to the terms of these acquisitions, we agreed to register for resale with the SEC the STACK Acquisition Shares and the PRB Acquisition Shares. Following such respective registrations, the STACK Acquisition Shares and the PRB Acquisition Shares can generally be freely sold in the public markets at any time on or after February 21, 2016 and March 16, 2016, respectively.
EnLink Capital Resources and Expenditures
In January 2016, EnLink acquired Tall Oak, a gathering and processing midstream company with assets in central Oklahoma, for approximately $1.5 billion in cash and equity, subject to certain adjustments.
Excluding this acquisition, EnLink’s 2016 capital budget includes approximately $445 million to $570 million of identified growth projects. EnLink’s primary capital projects for 2016 include completing the construction of the Riptide plant in Texas, acquired as part of the Coronado transaction, commencing construction on an NGL pipeline in Louisiana and development of its Tall OakBarnett Shale upstream assets.
EnLink expects to fund the growth capital expenditures from the proceeds of borrowings under its bank credit facility and proceeds from other debt and equity sources. EnLink expects to fund its 2016 maintenance capital expenditures from operating cash flows. In 2016, it is possible that not all of the planned projects will be commenced or completed. EnLink’s ability to pay distributions to its unitholders, fund planned capital expenditures and make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.
Contractual Obligations The following table presents a summary of our contractual obligations as of December 31, 2015.2018. | | | | | | | | | | | | | | | | | | | | | | | Payments Due by Period | | | | Total | | | Less Than 1 Year | | | 1-3 Years | | | 3-5 Years | | | More Than 5 Years | | | | (Millions) | | Devon debt(1) | | $ | 10,051 | | | $ | 976 | | | $ | 875 | | | $ | 700 | | | $ | 7,500 | | EnLink debt(2) | | | 3,077 | | | | — | | | | — | | | | 814 | | | | 2,263 | | Interest expense(3) | | | 9,804 | | | | 630 | | | | 1,252 | | | | 1,115 | | | | 6,807 | | Purchase obligations(4) | | | 3,905 | | | | 557 | | | | 1,494 | | | | 1,648 | | | | 206 | | Operational agreements(5) | | | 4,601 | | | | 994 | | | | 1,908 | | | | 657 | | | | 1,042 | | Asset retirement obligations(6) | | | 1,414 | | | | 44 | | | | 104 | | | | 102 | | | | 1,164 | | Drilling and facility obligations(7) | | | 189 | | | | 69 | | | | 85 | | | | 7 | | | | 28 | | Lease obligations(8) | | | 443 | | | | 70 | | | | 134 | | | | 110 | | | | 129 | | Other(9) | | | 140 | | | | 2 | | | | 92 | | | | 39 | | | | 7 | | | | | | | | | | | | | | | | | | | | | | | Total(10) | | $ | 33,624 | | | $ | 3,342 | | | $ | 5,944 | | | $ | 5,192 | | | $ | 19,146 | | | | | | | | | | | | | | | | | | | | | | |
| | 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 Devon’s debt obligations at December 31, 2015,2018, excluding $28 million of net discounts and debt issue costs included in the carrying value of debt. Debt due less than one year includes $626 million of commercial paper, which can be renewed beyond one year. |
(2) | Debt amounts represent scheduled maturities of EnLink’s debt obligations at December 31, 2015, excluding $13 million of net premiums included in the carrying value of debt. All of EnLink’s debt is non-recourse to Devon. |
(3) | Interest expense represents the scheduled cash payments on long-term fixed-rate debt and an estimate(including current portion of our floating-rate notes. These amounts include $1.8 billion of interest expense related to EnLink.long term debt). |
(4)(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. |
(5)(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. Operational agreements include approximately $1.7Approximately $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 minimum volume commitments between Devon and EnLink. The initial terms25 years following the divestment of the gas volume contracts with EnLink are summarizedour 50% interest in the following table. In addition, DevonAccess Pipeline. For additional information, see Note 2 in “Item 8. Financial Statements and EnLink have a 30 MBbls/d minimum transportation volume commitment for the VEX pipeline. All contracts with EnLink expire in 2019.Supplementary Data” of this report. |
| | | | | | | | | | | | | | | | | | | | | Contract | | Contract Terms (Years) | | | Minimum Gathering Volume Commitment (MMcf/d) | | | Minimum Processing Volume Commitment (MMcf/d) | | | Minimum Volume Commitment Term (Years) | | | Annual Rate Escalators | | Bridgeport gathering and processing contract | | | 10 | | | | 850 | | | | 650 | | | | 5 | | | | CPI | | East Johnson County gathering contract | | | 10 | | | | 125 | | | | — | | | | 5 | | | | CPI | | Cana gathering and processing contract | | | 10 | | | | 330 | | | | 330 | | | | 5 | | | | CPI | |
(6)(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, 20152018 balance sheet. |
(7)(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. |
(8)(7) | Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations.equipment. |
(9)(8) | These amounts include $133 million relatedOther obligations primarily relate to uncertainvarious tax positions.obligations. |
(10) | This table excludes approximately $1.7 billion of cash payments made on January 7, 2016 upon closing the STACK acquisition and EnLink’s acquisition of Tall Oak. The table also excludes the $500 million of future cash installment payments required to be paid by EnLink within 24 months as part of the Tall Oak acquisition. |
Contingencies and Legal Matters For a detailed discussion of contingencies and legal matters, see Note 1820 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 40
Table of Contents Index to Financial Statements 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. Full Cost
Oil and Gas Assets Accounting, Classification, Reserves & Valuation Successful Efforts Method of Accounting and Proved 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 the depletion and full cost ceilingDD&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 2015, 95%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 3%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. While the quantitiesValuation of Long-Lived Assets
Long-lived assets used in operations, including proved reserves require substantial judgment, the associated prices of oil, gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. Applicable rules require future net revenues to be calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Such rules also dictate that a 10% discount factor be used. Therefore, the discounted future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs or our enterprise risk. Because the ceiling calculation dictates the use of prices that are not representative of future prices and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating fair value. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Because of the volatile nature of oil and gas prices, it generally is not possible to predict the timing or magnitude of full cost write-downs. In addition, because of the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling write-down.
Based on prices for the last nine months of 2015 and the short-term pricing outlook for the first quarter of 2016, we expect to recognize additional U.S. and Canadian full cost impairments in the first quarter of 2016. The estimated U.S. impairment would be material to our net earnings, but we believe it will not be as large as the $3.7 billion impairment we recognized in the fourth quarter of 2015. We also expect to recognize an impairment related to our Canadianunproved oil and gas properties, that will approximate theare depreciated and assessed for impairment recognizedannually or whenever changes in the fourth quarter of 2015. While difficult to measure, we estimate that the first quarter 2016 impairments will approximate $3 billionfacts and circumstances indicate a possible significant deterioration in the aggregate. Our full cost impairments have no impact to our cash flow or liquidity.
Derivative Financial Instruments
We periodically enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production to hedge future prices received. Additionally, EnLink periodically enters into derivative financial instruments with respect to its oil, gas and NGL marketing activity. These commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.
The estimates of the fair values of our derivative instruments require substantial judgment. We estimate the fair values of our commodity derivative financial instruments primarily by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX WTI forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we
base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the livesflows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual
41
Table of the contracts are discounted primarily using U.S. Treasury bill rates. These pricing and discounting variables are sensitiveContents Index to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.Financial Statements We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest rate yields. The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rates. These yield and discounting variables are sensitive to the period of the contract and market volatility.
We periodically enter into foreign exchange forward contracts to manage our exposure to fluctuations in exchange rates. Under the terms of our foreign exchange forward contracts, we generally receive U.S. dollars and pay Canadian dollarsassets based on a total notional amount. We estimate the fair values of our foreign exchange forward contracts primarily by using internal discounted cash flow calculations based upon forward exchange rates. The most significant variable to our cash flow calculations is our observation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturityjudgmental assessment of the contractslowest level (“common operating field”) for which there are discounted using Treasury rates. These discounting variablesidentifiable cash flows that are sensitive to the periodlargely independent of the contractcash 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 market volatility.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.
We periodically validate our valuation techniques by comparing our internally generatedManagement 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 estimates with those obtained from contract counterparties.
Counterparty credit risk has not hadvalue. Because there usually is a significant effect on our cash flow calculations and derivative valuations. This is primarily the resultlack of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our oil, gas and NGL commodity derivative contracts are held with thirteen separate counterparties, and our foreign exchange forward contracts are held with six separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below certain credit rating levels.
Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.
Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actualquoted market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding the effects that changes in market prices can have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this report.
Business Combinations
Accounting for the acquisition of a business requires thelong-lived assets, and liabilities of the acquired business to be recorded at fair value. Deferred taxes are recorded for any differences between the fair value and the tax basis of the acquired assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill.
There are various assumptions we make in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, we prepare estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by our engineers and that of outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation.
However, there are factors involved in estimating the fair values of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies a historical 12-month average price to the reserves to arrive at the ceiling amount. By contrast, the fair value of reserves acquired in a business combination must beimpaired assets is typically determined based on ourthe 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 oil, natural gas and NGL prices. Our estimates ofproduction volumes, future commodity prices are based onthe largest driver in the variability of undiscounted pre-tax cash flows. For our own analysis of pricing trends. These estimates are based on current data obtained with regard to regionalimpairment determinations, we generally utilize the forward strip prices for the first five years and worldwide supply and demand dynamics such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.
apply internally generated price forecasts for subsequent years. We estimate and escalate or de-escalate future prices to apply to the estimated reserve quantities acquired,capital and estimate future operating and development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discountedby using a rate determined appropriate at the time of the business combination based upon ourmethod that correlates cost of capital. We also apply these same general principlesmovements to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we considerprice movements similar to be an appropriate risk-weighting factor in each particular instance.
In addition, our acquisitions have involved other entities whose operations included substantial midstream activities. In these transactions, the purchase price is allocatedrecent history. Changes to the fair value of midstream facilities and equipment, generally consisting of processing facilities and pipeline systems. Estimating the fair valueany of these assets requires certain assumptions could result in lower undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Due to be made regarding future quantities of commodities estimated to be processedsuppressed commodity prices in 2016, we recognized significant asset impairments. With generally higher pricing in 2017 and transported through these facilities and pipelines, as well as estimates of future expected prices and operating and capital costs.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. While we use data asAs of OctoberDecember 31, for our test, we typically complete2018, the test in late December or early January as the October 31 market data used in our test becomes available. U.S. reporting unit had goodwill totaling $841 million. We first assess theperform a qualitative factorsassessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test.amount. If we determineour qualitative assessment determines that it is more likely than not that its fair value is less than its carrying amount, then the two-step goodwill impairment test is performed. In the first step of the impairment test, 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 itsthe 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. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment
test is performed for purposes of measuring the impairment. In the second step, the fair value of the reporting unit is allocated to all of the assets and liabilities of the reporting unit to determine an implied goodwill value. This allocation is similar to a purchase price allocation. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of goodwill, an impairment loss is recognized in an amount equal to that excess. 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. Critical assumptions primarily include revenue growth rates driven by future commodity prices and volume expectations, operating margins and capital expenditures.
ForBased on our qualitative assessment as of October 31, 20152018, 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 test, step oneon 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 our impairment analysis showedDecember 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 exceededis less than its carrying value.
Sustained weaknessOur 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 overall energy sector beginningperiod in the fourth quarter of 2014 and continuing into 2015 driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test for EnLink’s reporting units, as well as an update performed as of December 31. Based on the results of the impairment analysis, it was determinedwhich we would determine that the estimated fair value of EnLink’s Crude and Condensate, Louisiana and Texas reporting units were less than their carrying amounts, primarily due to changes in assumptions related to commodity prices and discount rates. Through the analysis, goodwill impairments of $492 million, $787 million and $49 million for EnLink’s Texas, Louisiana and Crude and Condensate reporting units, respectively, were recognized in 2015. Subsequent to the impairments, EnLink had $93 million and $704 million of goodwill allocated to the Crude and Condensate and Texas reporting units, respectively. The Louisiana reporting unit’s goodwill was entirely written off. As of December 31, 2015, the fair value of EnLink’s Texas reporting unit exceeded its carrying value by approximately 7%, and the carrying value exceeds fair value. We would expect that a prolonged or sustained period of EnLink’s Crude and Condensatelower commodity prices would adversely affect the estimate of future operating results, which could result in future goodwill impairments for our U.S. reporting unit approximated its fair value.due to the potential impact on the cash flows of our operations.
42
Table of Contents Index to Financial Statements The impairment of goodwill has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized. Other Intangible Assets
In 2015, the assessment of customer relationships was updated due to the factors described in the aforementioned goodwill section. This assessment resulted in a $223 million impairment of other intangible assets related to EnLink’s Crude and Condensate reporting unit. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment.
The other intangible assets impairment 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 2015, we had deferred tax assets that largely resulted from the full cost impairments recognized in the fourth quarter of 2015. As a result of our recent cumulative losses,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, as of December 31, 2015.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, particularly the laws pertaining to the deductibility of intangible drilling costs and repatriations of foreign earnings.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: separate analysis of a diverse chain of foreign entities;
| • | relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings; |
| • | 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 |
| • | 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. |
relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings;
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
further analysis of a variety of other inputs such as the earnings, 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.
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.
43
Table of Contents Index to Financial Statements 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 20152018 Results” in this Item 7.7 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 or non-recurringand 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 quarterly performance measure. Items may appear to be recurring when comparing on an annual basis. In the table below, restructuring costs were incurred in each of the three year periods; however, these costs relate to different restructuring programs. Amounts excluded for 20152018 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 and repatriation of funds toassociated with the U.S. Amounts excluded for 2014 relate to2016 workforce reduction, derivatives and financial instrument fair value changes asset impairments (including an impairment of goodwill), our divestiture programs and related gains on asset sales and restructuring costs repatriation of proceeds to the U.S., loss onassociated with early retirement of debt and deferred income tax on the formation of the General Partner. Amounts excluded for 2013 relate to derivatives and financial instrument fair value changes, asset impairments, our divestiture programs and related repatriation of proceeds to the U.S. and restructuring costs. For more information on our restructuring programs, see Note 6 in “Item 8. Financial debt.Statements and Supplementary Data” of this report. We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts.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.
44
Table of Contents Index to Financial Statements 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 | |
45
Table of Contents | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions, except per share amounts) | | Net earnings (loss) attributable to Devon (GAAP) | | $ | (14,454 | ) | | $ | 1,607 | | | $ | (20 | ) | Adjustments (net of taxes and noncontrolling interests): | | | | | | | | | | | | | Derivatives and other financial instruments | | | (206 | ) | | | (1,262 | ) | | | 131 | | Cash settlements on derivatives and financial instruments | | | 1,552 | | | | 31 | | | | 139 | | | | | | | | | | | | | | | Noncash effect of derivatives and financial instruments | | | 1,346 | | | | (1,231 | ) | | | 270 | | Asset impairments | | | 13,100 | | | | 1,948 | | | | 1,353 | | Deferred tax asset valuation allowance | | | 967 | | | | — | | | | — | | Gain on asset sales and repatriations | | | 33 | | | | (421 | ) | | | 97 | | Investment in General Partner deferred income tax | | | — | | | | 48 | | | | — | | Restructuring costs | | | 52 | | | | 35 | | | | 34 | | Early retirement of debt | | | — | | | | 31 | | | | — | | | | | | | | | | | | | | | Core earnings attributable to Devon (non-GAAP) | | $ | 1,044 | | | $ | 2,017 | | | $ | 1,734 | | | | | | | | | | | | | | | Earnings (loss) per share attributable to Devon (GAAP) | | $ | (35.55 | ) | | $ | 3.91 | | | $ | (0.06 | ) | Adjustments (net of taxes and noncontrolling interests): | | | | | | | | | | | | | Derivatives and other financial instruments | | | (0.49 | ) | | | (3.07 | ) | | | 0.31 | | Cash settlements on derivatives and financial instruments | | | 3.80 | | | | 0.08 | | | | 0.34 | | | | | | | | | | | | | | | Noncash effect of derivatives and financial instruments | | | 3.31 | | | | (2.99 | ) | | | 0.65 | | Asset impairments | | | 32.18 | | | | 4.74 | | | | 3.35 | | Deferred tax asset valuation allowance | | | 2.37 | | | | — | | | | — | | Gain on asset sales and repatriations | | | 0.08 | | | | (1.02 | ) | | | 0.24 | | Investment in General Partner deferred income tax | | | — | | | | 0.12 | | | | — | | Restructuring costs | | | 0.13 | | | | 0.08 | | | | 0.08 | | Early retirement of debt | | | — | | | | 0.07 | | | | — | | | | | | | | | | | | | | | Core earnings per share attributable to Devon (non-GAAP) | | $ | 2.52 | | | $ | 4.91 | | | $ | 4.26 | | | | | | | | | | | | | | |
Index to Financial Statements | 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 | ) |
46
Table of Contents Index to Financial Statements 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. 47
Table of Contents Index to Financial Statements | 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 | |
48
Table of Contents Index to Financial Statements Item 7A.Quantitative and Qualitative Disclosures about Market Risk The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising from adverse changes in oil, bitumen, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Commodity Price Risk Our major market risk exposure is the pricing applicable to our oil, bitumen, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian gas and NGL production. Pricing for oil and gas production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we periodicallysystematically hedge a portion of our production through various financial transactions. The key terms to all our oil and gas derivative financial instruments as of December 31, 20152018 are presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2015,2018, a 10% change in the forward curves associated with our commodity derivative instruments would not have materially impactedchanged our balance sheet at December 31, 2015.net asset positions by approximately $270 million. Interest Rate Risk At December 31, 2015,2018, we had total debt of $13.1$5.9 billion. Of this amount, $11.7 billion bearsAll of our debt is based on fixed interest rates averaging 5.3%, and $1.4 billion is comprised of floating rate debt with interest rates averaging 1.1%5.4%. Our commercial paper borrowings typically have maturities between 1 and 90 days. As of December 31, 2015,2018, we had one open interest rate swap positionsposition that areis presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report. The fair valuesvalue of our interest rate swaps areswap is largely determined by estimates of the forward curves of the 3three month LIBOR rate. A 10% change in these forward curves would not have materially impacted our balance sheet or liquidity at December 31, 2015.2018. Foreign Currency Risk Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our December 31, 20152018 balance sheet. Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, some of our subsidiaries hold Canadian-dollar cash and engageDevon engages in intercompany loansloan activity between subsidiaries with Canadian subsidiaries that are based in Canadian dollars.different functional currencies. The value of the Canadian-dollar cash andthese foreign currency denominated intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollarsubsidiaries’ functional currency. Additionally, at December 31, 2015, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash and intercompany loans. Based on the amount of the cash and intercompany loans as of December 31, 2015,2018, a 10% change in the foreign currency exchange rates would not have materially impacted our balance sheet.
49
Table of Contents Index to Financial Statements Item 8.Financial Statements and Supplementary Data INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto. 50
Table of Contents Index to Financial Statements Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders Devon Energy Corporation: Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries (the “Company”) as of December 31, 20152018 and 2014, and2017, the related consolidated comprehensive statements of comprehensive earnings, stockholders’ equity, and cash flows and stockholders’ equity for each of the years in the three-year period ended December 31, 2015.2018, and the related notes (collectively, the “consolidated financial statements”). We also have audited Devon Energy Corporation’sthe Company’s internal control over financial reporting as of December 31, 2015,2018, based on criteria established inInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)Commission. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Adoption of New Accounting Standard As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for revenue from contracts with customers in 2018 due to the adoption of Accounting Standards Update 2014-09, Revenue from Contracts with Customers (ASC 606). Devon Energy Corporation’s Basis for Opinion The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting contained in “Item 9A. Controls and Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K.Procedures.” Our responsibility is to express an opinion on thesethe Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the 51
Table of Contents Index to Financial Statements company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established inInternal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ KPMG LLP We have served as the Company’s auditor since 1980. Oklahoma City, Oklahoma February 17, 2016 20, 201952
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions, except per share amounts) | | Oil, gas and NGL sales | | $ | 5,382 | | | $ | 9,910 | | | $ | 8,522 | | Oil, gas and NGL derivatives | | | 503 | | | | 1,989 | | | | (191 | ) | Marketing and midstream revenues | | | 7,260 | | | | 7,667 | | | | 2,066 | | | | | | | | | | | | | | | Total operating revenues | | | 13,145 | | | | 19,566 | | | | 10,397 | | | | | | | | | | | | | | | Lease operating expenses | | | 2,104 | | | | 2,332 | | | | 2,268 | | Marketing and midstream operating expenses | | | 6,420 | | | | 6,815 | | | | 1,553 | | General and administrative expenses | | | 855 | | | | 847 | | | | 617 | | Production and property taxes | | | 388 | | | | 535 | | | | 461 | | Depreciation, depletion and amortization | | | 3,129 | | | | 3,319 | | | | 2,780 | | Asset impairments | | | 20,820 | | | | 1,953 | | | | 1,976 | | Restructuring costs | | | 78 | | | | 46 | | | | 54 | | Gains and losses on asset sales | | | — | | | | (1,072 | ) | | | 9 | | Other operating items | | | 78 | | | | 93 | | | | 112 | | | | | | | | | | | | | | | Total operating expenses | | | 33,872 | | | | 14,868 | | | | 9,830 | | | | | | | | | | | | | | | Operating income (loss) | | | (20,727 | ) | | | 4,698 | | | | 567 | | Net financing costs | | | 517 | | | | 526 | | | | 417 | | Other nonoperating items | | | 24 | | | | 113 | | | | 1 | | | | | | | | | | | | | | | Earnings (loss) before income taxes | | | (21,268 | ) | | | 4,059 | | | | 149 | | Income tax expense (benefit) | | | (6,065 | ) | | | 2,368 | | | | 169 | | | | | | | | | | | | | | | Net earnings (loss) | | | (15,203 | ) | | | 1,691 | | | | (20 | ) | Net earnings (loss) attributable to noncontrolling interests | | | (749 | ) | | | 84 | | | | — | | | | | | | | | | | | | | | Net earnings (loss) attributable to Devon | | $ | (14,454 | ) | | $ | 1,607 | | | $ | (20 | ) | | | | | | | | | | | | | | Net earnings (loss) per share attributable to Devon: | | | | | | | | | | | | | Basic | | $ | (35.55 | ) | | $ | 3.93 | | | $ | (0.06 | ) | Diluted | | $ | (35.55 | ) | | $ | 3.91 | | | $ | (0.06 | ) | | | | | Comprehensive earnings (loss): | | | | | | | | | | | | | Net earnings (loss) | | $ | (15,203 | ) | | $ | 1,691 | | | $ | (20 | ) | Other comprehensive earnings (loss), net of tax: | | | | | | | | | | | | | Foreign currency translation | | | (559 | ) | | | (465 | ) | | | (548 | ) | Pension and postretirement plans | | | 10 | | | | (24 | ) | | | 45 | | | | | | | | | | | | | | | Other comprehensive loss, net of tax | | | (549 | ) | | | (489 | ) | | | (503 | ) | | | | | | | | | | | | | | Comprehensive earnings (loss) | | | (15,752 | ) | | | 1,202 | | | | (523 | ) | Comprehensive earnings (loss) attributable to noncontrolling interests | | | (749 | ) | | | 84 | | | | — | | | | | | | | | | | | | | | Comprehensive earnings (loss) attributable to Devon | | $ | (15,003 | ) | | $ | 1,118 | | | $ | (523 | ) | | | | | | | | | | | | | |
| | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Upstream revenues | | $ | 6,285 | | | $ | 5,307 | | | $ | 3,981 | | Marketing revenues | | | 4,449 | | | | 3,571 | | | | 2,772 | | Total revenues | | | 10,734 | | | | 8,878 | | | | 6,753 | | Production expenses | | | 2,225 | | | | 1,823 | | | | 1,805 | | Exploration expenses | | | 177 | | | | 380 | | | | 215 | | Marketing expenses | | | 4,363 | | | | 3,619 | | | | 2,821 | | Depreciation, depletion and amortization | | | 1,658 | | | | 1,529 | | | | 1,592 | | Asset impairments | | | 156 | | | | — | | | | 437 | | Asset dispositions | | | (263 | ) | | | (217 | ) | | | (1,496 | ) | General and administrative expenses | | | 650 | | | | 737 | | | | 733 | | Financing costs, net | | | 594 | | | | 317 | | | | 717 | | Restructuring and transaction costs | | | 114 | | | | — | | | | 261 | | Other expenses | | | 140 | | | | (83 | ) | | | 101 | | Total expenses | | | 9,814 | | | | 8,105 | | | | 7,186 | | Earnings (loss) from continuing operations before income taxes | | | 920 | | | | 773 | | | | (433 | ) | Income tax expense | | | 156 | | | | 15 | | | | 141 | | Net earnings (loss) from continuing operations | | | 764 | | | | 758 | | | | (574 | ) | Net earnings (loss) from discontinued operations, net of income tax expense | | | 2,460 | | | | 320 | | | | (884 | ) | Net earnings (loss) | | | 3,224 | | | | 1,078 | | | | (1,458 | ) | Net earnings (loss) attributable to noncontrolling interests | | | 160 | | | | 180 | | | | (402 | ) | Net earnings (loss) attributable to Devon | | $ | 3,064 | | | $ | 898 | | | $ | (1,056 | ) | Basic net earnings (loss) per share: | | | | | | | | | | | | | Basic earnings (loss) from continuing operations per share | | $ | 1.53 | | | $ | 1.44 | | | $ | (1.14 | ) | Basic earnings (loss) from discontinued operations per share | | | 4.61 | | | | 0.27 | | | | (0.95 | ) | Basic net earnings (loss) per share | | $ | 6.14 | | | $ | 1.71 | | | $ | (2.09 | ) | Diluted net earnings (loss) per share: | | | | | | | | | | | | | Diluted earnings (loss) from continuing operations per share | | $ | 1.52 | | | $ | 1.43 | | | $ | (1.14 | ) | Diluted earnings (loss) from discontinued operations per share | | | 4.58 | | | | 0.27 | | | | (0.95 | ) | Diluted net earnings (loss) per share | | $ | 6.10 | | | $ | 1.70 | | | $ | (2.09 | ) | Comprehensive earnings (loss): | | | | | | | | | | | | | Net earnings (loss) | | $ | 3,224 | | | $ | 1,078 | | | $ | (1,458 | ) | Other comprehensive earnings (loss), net of tax: | | | | | | | | | | | | | Foreign currency translation | | | (152 | ) | | | 83 | | | | 11 | | Pension and postretirement plans | | | 44 | | | | 29 | | | | 22 | | Other comprehensive earnings (loss), net of tax | | | (108 | ) | | | 112 | | | | 33 | | Comprehensive earnings (loss) | | | 3,116 | | | | 1,190 | | | | (1,425 | ) | Comprehensive earnings (loss) attributable to noncontrolling interests | | | 160 | | | | 180 | | | | (402 | ) | Comprehensive earnings (loss) attributable to Devon | | $ | 2,956 | | | $ | 1,010 | | | $ | (1,023 | ) |
See accompanying notes to consolidated financial statements. 53
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS | | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Cash flows from operating activities: | | | | | | | | | | | | | Net earnings (loss) | | $ | 3,224 | | | $ | 1,078 | | | $ | (1,458 | ) | Adjustments to reconcile net earnings to net cash from operating activities: | | | | | | | | | | | | | Net (earnings) loss from discontinued operations, net of income tax expense | | | (2,460 | ) | | | (320 | ) | | | 884 | | Depreciation, depletion and amortization | | | 1,658 | | | | 1,529 | | | | 1,592 | | Asset impairments | | | 156 | | | | — | | | | 437 | | Leasehold impairments | | | 95 | | | | 219 | | | | 113 | | Accretion on discounted liabilities | | | 61 | | | | 63 | | | | 75 | | Total (gains) losses on commodity derivatives | | | (608 | ) | | | (157 | ) | | | 201 | | Cash settlements on commodity derivatives | | | (84 | ) | | | 53 | | | | 1 | | Gains on asset dispositions | | | (263 | ) | | | (217 | ) | | | (1,496 | ) | Deferred income tax expense (benefit) | | | 226 | | | | (97 | ) | | | 43 | | Share-based compensation | | | 161 | | | | 150 | | | | 203 | | Early retirement of debt | | | 312 | | | | — | | | | 269 | | Total (gains) losses on foreign exchange | | | 139 | | | | (132 | ) | | | (121 | ) | Settlements of intercompany foreign denominated assets/liabilities | | | (241 | ) | | | 9 | | | | 63 | | Other | | | (5 | ) | | | (1 | ) | | | 4 | | Changes in assets and liabilities, net | | | (143 | ) | | | 32 | | | | 24 | | Net cash from operating activities - continuing operations | | | 2,228 | | | | 2,209 | | | | 834 | | Cash flows from investing activities: | | | | | | | | | | | | | Capital expenditures | | | (2,451 | ) | | | (1,968 | ) | | | (1,384 | ) | Acquisitions of property and equipment | | | (55 | ) | | | (46 | ) | | | (849 | ) | Divestitures of property and equipment | | | 1,013 | | | | 426 | | | | 3,020 | | Net cash from investing activities - continuing operations | | | (1,493 | ) | | | (1,588 | ) | | | 787 | | Cash flows from financing activities: | | | | | | | | | | | | | Repayments of long-term debt principal | | | (922 | ) | | | — | | | | (2,492 | ) | Net short-term debt repayments | | | — | | | | — | | | | (626 | ) | Early retirement of debt | | | (304 | ) | | | — | | | | (265 | ) | Issuance of common stock | | | — | | | | — | | | | 1,469 | | Repurchases of common stock | | | (2,956 | ) | | | — | | | | — | | Dividends paid on common stock | | | (149 | ) | | | (127 | ) | | | (221 | ) | Shares exchanged for tax withholdings | | | (48 | ) | | | (59 | ) | | | (35 | ) | Other | | | (7 | ) | | | — | | | | — | | Net cash from financing activities - continuing operations | | | (4,386 | ) | | | (186 | ) | | | (2,170 | ) | Effect of exchange rate changes on cash: | | | | | | | | | | | | | Settlements of intercompany foreign denominated assets/liabilities | | | 241 | | | | (9 | ) | | | (63 | ) | Other | | | (35 | ) | | | 15 | | | | 2 | | Total effect of exchange rate changes on cash - continuing operations | | | 206 | | | | 6 | | | | (61 | ) | Net change in cash, cash equivalents and restricted cash of continuing operations | | | (3,445 | ) | | | 441 | | | | (610 | ) | Cash flows from discontinued operations: | | | | | | | | | | | | | Operating activities | | | 476 | | | | 700 | | | | 666 | | Investing activities | | | 2,548 | | | | (611 | ) | | | (1,381 | ) | Financing activities | | | 183 | | | | 195 | | | | 974 | | Net change in cash, cash equivalents and restricted cash of 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 beginning of period | | | 2,684 | | | | 1,959 | | | | 2,310 | | Cash, cash equivalents and restricted cash at end of period | | $ | 2,446 | | | $ | 2,684 | | | $ | 1,959 | | | | | | | | | | | | | | | Reconciliation of cash, cash equivalents and restricted cash: | | | | | | | | | | | | | Cash and cash equivalents | | $ | 2,414 | | | $ | 2,642 | | | $ | 1,947 | | Restricted cash included in other current assets | | | 32 | | | | 11 | | | | — | | Cash and cash equivalents included in current assets held for sale | | | — | | | | 31 | | | | 12 | | Total cash, cash equivalents and restricted cash | | $ | 2,446 | | | $ | 2,684 | | | $ | 1,959 | |
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | Cash flows from operating activities: | | | | | | | | | | | | | Net earnings (loss) | | $ | (15,203 | ) | | $ | 1,691 | | | $ | (20 | ) | Adjustments to reconcile net earnings (loss) to net cash from operating activities: | | | | | | | | | | | | | Depreciation, depletion and amortization | | | 3,129 | | | | 3,319 | | | | 2,780 | | Asset impairments | | | 20,820 | | | | 1,953 | | | | 1,976 | | Gains and losses on asset sales | | | — | | | | (1,072 | ) | | | 9 | | Deferred income tax expense (benefit) | | | (5,828 | ) | | | 1,891 | | | | 97 | | Derivatives and other financial instruments | | | (738 | ) | | | (2,070 | ) | | | 135 | | Cash settlements on derivatives and financial instruments | | | 2,688 | | | | 104 | | | | 277 | | Other noncash charges | | | 537 | | | | 457 | | | | 309 | | Net change in working capital | | | (301 | ) | | | 50 | | | | (298 | ) | Change in long-term other assets | | | 285 | | | | (421 | ) | | | 10 | | Change in long-term other liabilities | | | (6 | ) | | | 79 | | | | 161 | | | | | | | | | | | | | | | Net cash from operating activities | | | 5,383 | | | | 5,981 | | | | 5,436 | | | | | | | | | | | | | | | Cash flows from investing activities: | | | | | | | | | | | | | Capital expenditures | | | (5,308 | ) | | | (6,988 | ) | | | (6,502 | ) | Acquisitions of property, equipment and businesses | | | (1,107 | ) | | | (6,462 | ) | | | (256 | ) | Divestitures of property and equipment | | | 107 | | | | 5,120 | | | | 419 | | Purchases of short-term investments | | | — | | | | — | | | | (1,076 | ) | Redemptions of short-term investments | | | — | | | | — | | | | 3,419 | | Redemptions of long-term investments | | | — | | | | 57 | | | | — | | Other | | | (16 | ) | | | 89 | | | | (3 | ) | | | | | | | | | | | | | | Net cash from investing activities | | | (6,324 | ) | | | (8,184 | ) | | | (3,999 | ) | | | | | | | | | | | | | | Cash flows from financing activities: | | | | | | | | | | | | | Borrowings of long-term debt, net of issuance costs | | | 4,772 | | | | 5,340 | | | | 2,233 | | Repayments of long-term debt | | | (2,634 | ) | | | (7,189 | ) | | | — | | Net short-term debt repayments | | | (307 | ) | | | (385 | ) | | | (1,872 | ) | Stock option exercises | | | 4 | | | | 93 | | | | 3 | | Sale of subsidiary units | | | 654 | | | | — | | | | — | | Issuance of subsidiary units | | | 25 | | | | 410 | | | | — | | Dividends paid on common stock | | | (396 | ) | | | (386 | ) | | | (348 | ) | Distributions to noncontrolling interests | | | (254 | ) | | | (235 | ) | | | — | | Other | | | (16 | ) | | | (2 | ) | | | 4 | | | | | | | | | | | | | | | Net cash from financing activities | | | 1,848 | | | | (2,354 | ) | | | 20 | | | | | | | | | | | | | | | Effect of exchange rate changes on cash | | | (77 | ) | | | (29 | ) | | | (28 | ) | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | 830 | | | | (4,586 | ) | | | 1,429 | | Cash and cash equivalents at beginning of period | | | 1,480 | | | | 6,066 | | | | 4,637 | | | | | | | | | | | | | | | Cash and cash equivalents at end of period | | $ | 2,310 | | | $ | 1,480 | | | $ | 6,066 | | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements. 54
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS | | | December 31, 2015 | | December 31, 2014 | | | | | (Millions, except share data) | | | December 31, 2018 | | | December 31, 2017 | | ASSETS | | | | | | | | | | | | | Current assets: | | | | | | | | | | | | | Cash and cash equivalents | | $ | 2,310 | | | $ | 1,480 | | | $ | 2,414 | | | $ | 2,642 | | Accounts receivable | | | 1,105 | | | | 1,959 | | | | 885 | | | | 989 | | Derivatives, at fair value | | | 43 | | | | 1,993 | | | Income taxes receivable | | | 147 | | | | 522 | | | Current assets held for sale | | | | 197 | | | | 760 | | Other current assets | | | 421 | | | | 544 | | | | 941 | | | | 400 | | | | | | | | | | Total current assets | | | 4,026 | | | | 6,498 | | | | 4,437 | | | | 4,791 | | | | | | | | | | Property and equipment, at cost: | | | | | | Oil and gas, based on full cost accounting: | | | | | | Subject to amortization | | | 78,190 | | | | 75,738 | | | Not subject to amortization | | | 2,584 | | | | 2,752 | | | | | | | | | | | Total oil and gas | | | 80,774 | | | | 78,490 | | | Midstream and other | | | 10,380 | | | | 9,695 | | | | | | | | | | | Total property and equipment, at cost | | | 91,154 | | | | 88,185 | | | Less accumulated depreciation, depletion and amortization | | | (72,086 | ) | | | (51,889 | ) | | | | | | | | | | Property and equipment, net | | | 19,068 | | | | 36,296 | | | | | | | | | | | Oil and gas property and equipment, based on successful efforts accounting, net | | | | 12,813 | | | | 13,318 | | Other property and equipment, net | | | | 1,122 | | | | 1,266 | | Total property and equipment, net | | | | 13,935 | | | | 14,584 | | Goodwill | | | 5,032 | | | | 6,303 | | | | 841 | | | | 841 | | Other long-term assets | | | 1,406 | | | | 1,540 | | | | 353 | | | | 296 | | | | | | | | | | Long-term assets held for sale | | | | — | | | | 9,729 | | Total assets | | $ | 29,532 | | | $ | 50,637 | | | $ | 19,566 | | | $ | 30,241 | | | | | | | | | | LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | LIABILITIES AND EQUITY | | | | | | | | | | Current liabilities: | | | | | | | | | | | | | Accounts payable | | $ | 906 | | | $ | 1,400 | | | $ | 662 | | | $ | 633 | | Revenues and royalties payable | | | 763 | | | | 1,193 | | | | 898 | | | | 748 | | Short-term debt | | | 976 | | | | 1,432 | | | | 162 | | | | 115 | | Deferred income taxes | | | — | | | | 730 | | | Current liabilities held for sale | | | | 69 | | | | 991 | | Other current liabilities | | | 650 | | | | 1,180 | | | | 435 | | | | 828 | | | | | | | | | | Total current liabilities | | | 3,295 | | | | 5,935 | | | | 2,226 | | | | 3,315 | | | | | | | | | | Long-term debt | | | 12,137 | | | | 9,830 | | | | 5,785 | | | | 6,749 | | Asset retirement obligations | | | 1,370 | | | | 1,339 | | | | 1,030 | | | | 1,099 | | Other long-term liabilities | | | 853 | | | | 948 | | | | 462 | | | | 549 | | Long-term liabilities held for sale | | | | — | | | | 3,936 | | Deferred income taxes | | | 888 | | | | 6,244 | | | | 877 | | | | 489 | | Stockholders’ equity: | | | | | | Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 418 million and 409 million shares in 2015 and 2014, respectively | | | 42 | | | | 41 | | | Equity: | | | | | | | | | | Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 450 million and 525 million shares in 2018 and 2017, respectively | | | | 45 | | | | 53 | | Additional paid-in capital | | | 4,996 | | | | 4,088 | | | | 4,486 | | | | 7,333 | | Retained earnings | | | 1,781 | | | | 16,631 | | | | 3,650 | | | | 702 | | Accumulated other comprehensive earnings | | | 230 | | | | 779 | | | | 1,027 | | | | 1,166 | | | | | | | | | | Treasury stock, at cost, 1.0 million shares in 2018 | | | | (22 | ) | | | — | | Total stockholders’ equity attributable to Devon | | | 7,049 | | | | 21,539 | | | | 9,186 | | | | 9,254 | | Noncontrolling interests | | | 3,940 | | | | 4,802 | | | | — | | | | 4,850 | | | | | | | | | | Total stockholders’ equity | | | 10,989 | | | | 26,341 | | | | | | | | | | | Commitments and contingencies (Note 18) | | | | | | Total liabilities and stockholders’ equity | | $ | 29,532 | | | $ | 50,637 | | | | | | | | | | | Total equity | | | | 9,186 | | | | 14,104 | | Total liabilities and equity | | | $ | 19,566 | | | $ | 30,241 | |
See accompanying notes to consolidated financial statements. 55
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Retained | | | Accumulated | | | | | | | | | | | | | | | | Common Stock | | Additional Paid-In Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Earnings | | | Treasury Stock | | | Noncontrolling Interests | | | Total Stockholders’ Equity | | | | | | | | | | | Additional | | | Earnings | | | Other | | | | | | | | | | | | | | | | Shares | | Amount | | | Common Stock | | | Paid-In | | | (Accumulated | | | Comprehensive | | | Treasury | | | Noncontrolling | | | Total | | | | (Millions) | | | Shares | | | Amount | | | Capital | | | Deficit) | | | Earnings | | | Stock | | | Interests | | | Equity | | Balance as of December 31, 2012 | | | 406 | | | $ | 41 | | | $ | 3,688 | | | $ | 15,778 | | | $ | 1,771 | | | $ | — | | | $ | — | | | $ | 21,278 | | | Balance as of December 31, 2015 | | | | 418 | | | $ | 42 | | | $ | 4,996 | | | $ | 1,112 | | | $ | 1,021 | | | $ | — | | | $ | 3,940 | | | $ | 11,111 | | Net loss | | | — | | | | — | | | | — | | | | (20 | ) | | | — | | | | — | | | | — | | | | (20 | ) | | | — | | | | — | | | | — | | | | (1,056 | ) | | | — | | | | — | | | | (402 | ) | | | (1,458 | ) | Other comprehensive loss, net of tax | | | — | | | | — | | | | — | | | | — | | | | (503 | ) | | | — | | | | — | | | | (503 | ) | | Stock option exercises | | | — | | | | — | | | | 3 | | | | — | | | | — | | | | — | | | | — | | | | 3 | | | Common stock repurchased | | | — | | | | — | | | | — | | | | — | | | | — | | | | (36 | ) | | | — | | | | (36 | ) | | Common stock retired | | | — | | | | — | | | | (36 | ) | | | — | | | | — | | | | 36 | | | | — | | | | — | | | Common stock dividends | | | — | | | | — | | | | — | | | | (348 | ) | | | — | | | | — | | | | — | | | | (348 | ) | | Share-based compensation | | | — | | | | — | | | | 121 | | | | — | | | | — | | | | — | | | | — | | | | 121 | | | Share-based compensation tax benefits | | | — | | | | — | | | | 4 | | | | — | | | | — | | | | — | | | | — | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2013 | | | 406 | | | | 41 | | | | 3,780 | | | | 15,410 | | | | 1,268 | | | | — | | | | — | | | | 20,499 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net earnings | | | — | | | | — | | | | — | | | | 1,607 | | | | — | | | | — | | | | 84 | | | | 1,691 | | | Other comprehensive loss, net of tax | | | — | | | | — | | | | — | | | | — | | | | (489 | ) | | | — | | | | — | | | | (489 | ) | | Stock option exercises | | | 1 | | | | — | | | | 93 | | | | — | | | | — | | | | — | | | | — | | | | 93 | | | Restricted stock grants, net of cancellations | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | Common stock repurchased | | | — | | | | — | | | | — | | | | — | | | | — | | | | (27 | ) | | | — | | | | (27 | ) | | Common stock retired | | | — | | | | — | | | | (27 | ) | | | — | | | | — | | | | 27 | | | | — | | | | — | | | Common stock dividends | | | — | | | | — | | | | — | | | | (386 | ) | | | — | | | | — | | | | — | | | | (386 | ) | | Share-based compensation | | | — | | | | — | | | | 151 | | | | — | | | | — | | | | — | | | | — | | | | 151 | | | Share-based compensation tax expense | | | — | | | | — | | | | (3 | ) | | | — | | | | — | | | | — | | | | — | | | | (3 | ) | | Acquisition of noncontrolling interests | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4,670 | | | | 4,670 | | | Subsidiary equity transactions | | | — | | | | — | | | | 93 | | | | — | | | | — | | | | — | | | | 277 | | | | 370 | | | Distributions to noncontrolling interests | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (235 | ) | | | (235 | ) | | Other | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | — | | | | 6 | | | | 7 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2014 | | | 409 | | | | 41 | | | | 4,088 | | | | 16,631 | | | | 779 | | | | — | | | | 4,802 | | | | 26,341 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net loss | | | — | | | | — | | | | — | | | | (14,454 | ) | | | — | | | | — | | | | (749 | ) | | | (15,203 | ) | | Other comprehensive loss, net of tax | | | — | | | | — | | | | — | | | | — | | | | (549 | ) | | | — | | | | — | | | | (549 | ) | | Stock option exercises | | | — | | | | — | | | | 4 | | | | — | | | | — | | | | — | | | | — | | | | 4 | | | Other comprehensive earnings, net of tax | | | | — | | | | — | | | | — | | | | — | | | | 33 | | | | — | | | | — | | | | 33 | | Restricted stock grants, net of cancellations | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Common stock repurchased | | | — | | | | — | | | | — | | | | — | | | | — | | | | (35 | ) | | | — | | | | (35 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (28 | ) | | | — | | | | (28 | ) | Common stock retired | | | — | | | | — | | | | (35 | ) | | | — | | | | — | | | | 35 | | | | — | | | | — | | | | — | | | | — | | | | (28 | ) | | | — | | | | — | | | | 28 | | | | — | | | | — | | Common stock dividends | | | — | | | | — | | | | — | | | | (396 | ) | | | — | | | | — | | | | — | | | | (396 | ) | | | — | | | | — | | | | (96 | ) | | | (125 | ) | | | — | | | | — | | | | — | | | | (221 | ) | Common stock issued | | | 7 | | | | 1 | | | | 198 | | | | — | | | | — | | | | — | | | | — | | | | 199 | | | | 103 | | | | 10 | | | | 2,117 | | | | — | | | | — | | | | — | | | | — | | | | 2,127 | | Share-based compensation | | | — | | | | — | | | | 165 | | | | — | | | | — | | | | — | | | | — | | | | 165 | | | | — | | | | — | | | | 168 | | | | — | | | | — | | | | — | | | | — | | | | 168 | | Share-based compensation tax expense | | | — | | | | — | | | | (9 | ) | | | — | | | | — | | | | — | | | | — | | | | (9 | ) | | Subsidiary equity transactions | | | — | | | | — | | | | 585 | | | | — | | | | — | | | | — | | | | 141 | | | | 726 | | | | — | | | | — | | | | 80 | | | | — | | | | — | | | | — | | | | 1,214 | | | | 1,294 | | Distributions to noncontrolling interests | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (254 | ) | | | (254 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (304 | ) | | | (304 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2015 | | | 418 | | | $ | 42 | | | $ | 4,996 | | | $ | 1,781 | | | $ | 230 | | | $ | — | | | $ | 3,940 | | | $ | 10,989 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2016 | | | | 523 | | | $ | 52 | | | $ | 7,237 | | | $ | (69 | ) | | $ | 1,054 | | | $ | — | | | $ | 4,448 | | | $ | 12,722 | | Net earnings | | | | — | | | | — | | | | — | | | | 898 | | | | — | | | | — | | | | 180 | | | | 1,078 | | Other comprehensive earnings, net of tax | | | | — | | | | — | | | | — | | | | — | | | | 112 | | | | — | | | | — | | | | 112 | | Restricted stock grants, net of cancellations | | | | 1 | | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | Common stock repurchased | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (44 | ) | | | — | | | | (44 | ) | Common stock retired | | | | — | | | | — | | | | (44 | ) | | | — | | | | — | | | | 44 | | | | — | | | | — | | Common stock dividends | | | | — | | | | — | | | | — | | | | (127 | ) | | | — | | | | — | | | | — | | | | (127 | ) | Share-based compensation | | | | 1 | | | | — | | | | 126 | | | | — | | | | — | | | | — | | | | — | | | | 126 | | Subsidiary equity transactions | | | | — | | | | — | | | | 14 | | | | — | | | | — | | | | — | | | | 576 | | | | 590 | | Distributions to noncontrolling interests | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (354 | ) | | | (354 | ) | Balance as of December 31, 2017 | | | | 525 | | | $ | 53 | | | $ | 7,333 | | | $ | 702 | | | $ | 1,166 | | | $ | — | | | $ | 4,850 | | | $ | 14,104 | | Net earnings | | | | — | | | | — | | | | — | | | | 3,064 | | | | — | | | | — | | | | 160 | | | | 3,224 | | Other comprehensive loss, net of tax | | | | — | | | | — | | | | — | | | | — | | | | (108 | ) | | | — | | | | — | | | | (108 | ) | Restricted stock grants, net of cancellations | | | | 3 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Common stock repurchased | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (3,017 | ) | | | — | | | | (3,017 | ) | Common stock retired | | | | (79 | ) | | | (8 | ) | | | (2,987 | ) | | | — | | | | — | | | | 2,995 | | | | — | | | | — | | Common stock dividends | | | | — | | | | — | | | | — | | | | (149 | ) | | | — | | | | — | | | | — | | | | (149 | ) | Share-based compensation | | | | 1 | | | | — | | | | 140 | | | | — | | | | — | | | | — | | | | — | | | | 140 | | Divestment of subsidiary equity investment | | | | — | | | | — | | | | — | | | | — | | | | 2 | | | | — | | | | (4,863 | ) | | | (4,861 | ) | Subsidiary equity transactions | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 72 | | | | 72 | | Distributions to noncontrolling interests | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (219 | ) | | | (219 | ) | Other | | | | — | | | | — | | | | — | | | | 33 | | | | (33 | ) | | | — | | | | — | | | | — | | Balance as of December 31, 2018 | | | | 450 | | | $ | 45 | | | $ | 4,486 | | | $ | 3,650 | | | $ | 1,027 | | | $ | (22 | ) | | $ | — | | | $ | 9,186 | |
See accompanying notes to consolidated financial statements. 56
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. | Summary of Significant Accounting Policies |
Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. As further discussed in Note 2, Devon also owns natural gas pipelines, plants and treatment facilities throughsold its ownershipinterests in EnLink and the General Partner.Partner on July 18, 2018. Activity relating to EnLink and the General Partner are classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows. The associated assets and liabilities of EnLink and the General Partner are presented as assets and liabilities held for sale on the consolidated balance sheets. Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the U.S. and reflect industry practices. The more significant of such policies are discussed below. Principles of Consolidation The accompanying consolidated financial statements include the accounts of Devon and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets. As discussed more fully in Note 2, Devon completed a business combination in 2014 whereby Devon controls both EnLink and the General Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’s net earnings and stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.
Use of Estimates The preparation of financial statements requires management to make estimates 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. Significant items subject to such estimates and assumptions include the following: | • | proved reserves and related present value of future net revenues; |
| • | evaluation of suspended well costs; |
| • | the carrying and fair values of oil and gas properties, other property and equipment and product and equipment inventories; |
| • | derivative financial instruments; |
| • | the fair value of reporting units and related assessment of goodwill for impairment; |
| • | asset retirement obligations; |
| • | obligations related to employee pension and postretirement benefits; |
| • | legal and environmental risks and exposures; and |
| • | general credit risk associated with receivables and other assets. |
57
Table of Contents the carrying value of oil and gas properties, midstream assets and product and equipment inventories;
derivative financial instruments;
the fair value of reporting units and related assessment of goodwill for impairment;
the fair value of intangible assets other than goodwill;
asset retirement obligations;
obligations related to employee pension and postretirement benefits;
legal and environmental risks and exposures; and
general credit risk associated with receivables and other assets.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Revenue Recognition Impact of ASC 606 Adoption In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. The impact of adoption in the current period results is as follows: | | Year Ended December 31, 2018 | | | | Under ASC 606 | | | Under ASC 605 | | | Increase/ (Decrease) | | Upstream revenues | | $ | 6,285 | | | $ | 6,031 | | | $ | 254 | | Marketing revenues | | | 4,449 | | | | 4,449 | | | | — | | Total impacted revenues | | $ | 10,734 | | | $ | 10,480 | | | $ | 254 | | | | | | | | | | | | | | | Production expenses | | $ | 2,225 | | | $ | 1,971 | | | $ | 254 | | Marketing expenses | | | 4,363 | | | | 4,363 | | | | — | | Total impacted expenses | | $ | 6,588 | | | $ | 6,334 | | | $ | 254 | | | | | | | | | | | | | | | Earnings from continuing operations before income taxes | | $ | 920 | | | $ | 920 | | | $ | — | |
Changes to upstream revenues and production expenses are due to the conclusion that Devon represents the principal and controls a promised product before transferring it to the ultimate third party customer in accordance with the control model in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the third-party end customer. As a result, Devon has changed the presentation of revenues and expenses for these agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities, are now presented as production expenses. Upstream Revenues Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, titlecontrol has transferred and collectability of the revenue is probable. DeliveryDevon’s performance obligations are satisfied at a point in time. This occurs and title typicallywhen control is transferred whento the purchaser upon delivery of contract specified production has been deliveredvolumes at a specified point. The transaction price used to recognize revenue is a pipeline, railcar or truck. Cashfunction of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received relating to futurewithin 30 days of the end of the production is deferred and recognized when all revenue recognition criteria are met.month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated comprehensive statements of earnings. 58
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Natural gas and NGL sales Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statements of earnings. In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Oil sales Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statements of earnings. Marketing and midstreamRevenues Marketing revenues are recordedgenerated primarily as a result of Devon selling commodities purchased from third parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold or services are provided to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, titlecontrol has transferred and collectability of the revenue is probable. RevenuesThe transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases transportation and processing contracts are reported on a gross basis when Devon takes title tocontrol of the products and has risks and rewards of ownership. Satisfaction of Performance Obligations and Revenue Recognitions
Because Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon recognizes revenue for sales at the time the natural gas, NGLs or crude oil are delivered at a fixed or determinable price.
59
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Transaction Price Allocated to Remaining Performance Obligations Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Cash received relating to future performance obligations is deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of December 31, 2018. Devon’s product sales and marketing contracts do not give rise to contract assets. Disaggregation of Revenue Revenue from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. Disaggregation of revenue disclosures can be found in Note 22. Customers During 2015, 20142018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales revenue. During 2017 and 2013,2016, no purchaser accounted for more than 10% of Devon’s operating revenues.consolidated sales revenue.
Derivative Financial Instruments Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes. Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps and costless price collars and call options.collars. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. For price collars, Devon utilizes both two-way price collars and three-way price collars. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterpartycounterparty. The three-way price collars consist of a two-way collar with an additional short put option sold by Devon, and cash-settle similarly to the collars. The call options give counterpartiestwo-way collars unless the rightmarket price falls below the additional short put causing the company to purchase production at a predetermined price.receive the market price plus the long put to short put price differential. 60
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of December 31, 2018, Devon did not have any open foreign exchange contracts. All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2015,2018, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets. As of December 31, 2015, Devon accrued $236 million that it received in January 2016 related to cash settlements. DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2015 and December 31, 2014,2018, Devon held $75 million and $524 million, respectively, ofno cash collateral which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. Theits counterparties nor posted collateral is reported in other current liabilities in the accompanying consolidated balance sheets.to its counterparties. General and Administrative Expenses G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.Devon. Share-Based Compensation Independent of EnLink, Devon grants share-based awards to independent members of its Board of Directors and selected employees. EnLink and the General Partner also grant share-based awards to independent members of its Board of Directors and selectedselect employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the accompanying consolidated comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying consolidated comprehensive statements of earnings.
Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are generally available to be issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon repurchase. Income Taxes Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. 61
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent years. See Note 78 for further discussion. DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense. Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur. Net Earnings (Loss) Per Share Attributable to Devon Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.unvested performance share units. Cash and Cash Equivalents Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents. Accounts Receivable Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable, including joint interest receivables, for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance. Investments
Devon periodically invests excess cash in U.S. and Canadian treasury securities and other marketable securities. Devon considers securities with original contractual maturities in excess of three months but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale. Devon reports its investments and other marketable securities at fair value.
Property and Equipment Oil and Gas Property and Equipment Devon follows the full costsuccessful efforts method of accounting for its oil and gas properties. Accordingly, allExploration costs, incidentalsuch as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells, delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful 62
Table of Contents Index to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also Financial StatementsDEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are unsuccessful, are capitalized. Interest costs incurred and attributable to unprovedDevon groups its oil and gas properties under current evaluationwith a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property impairments and majoraccounting for asset dispositions. Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal drilling or development projectsactivities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. Devon reviews the status of all suspended exploratory drilling costs quarterly. Capitalized costs of proved oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Depletion is calculated using the capitalizedProved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly.annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred intoamortized to exploration expense on a group basis using estimated lease surrender rates over average lease terms. Proved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the depletion calculation over holding periods ranging from threecarrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to four years.estimated fair value. Because there is usually 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 or by comparable transactions. 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. SalesGains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized upon disposal ofrecognized.
Devon capitalizes interest costs incurred and attributable to material unproved oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country. As discussed more fully in Note 2, the 2014 divestitures of certain Canadian assets significantly altered such relationship, and Devon recognized a gain, which is included as a separate item in the accompanying consolidated comprehensive statements of earnings. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10% per annum, net of related tax effects. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book valuemajor development projects of oil and gas properties.
Estimated future net cash flows are calculated using end-of-period costs63
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Other Property and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2015 qualified for hedge accounting treatment.Equipment Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Asset Retirement Obligations Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment. Goodwill Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. Such test includes ana 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 the qualitative andassessment 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 factors.goodwill impairment test is performed. The quantitative goodwill impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. Thethe fair value of each reporting unit is estimated andbe compared to the net bookcarrying value of the reporting unit. If the estimated fair value of the reporting unit is less than the net bookcarrying value, including goodwill, thenan impairment charge will be recognized for the goodwill is written down toamount by which the impliedcarrying amount exceeds the fair value of the goodwill through a charge to expense.value. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. Devon performed annual impairment tests of goodwill in the fourth quarters of 2015, 20142018, 2017 and 2013.2016. No impairment of goodwill was required in 2013. However, write-downs were required in 2015 and 2014 based onas a result of the annual impairment test. EnLink’s Texas, Louisiana and Crude and Condensate reporting segment goodwill were deemed impairedtests in 2015, and Devon’s Canadian reporting unit goodwill was deemed impaired in 2014. See Note 12 for further discussion.these time periods. Intangible Assets
Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10-20 years. During 2015, EnLink’s customer relationships were also evaluated for impairment, and a portion of these intangibles was considered impaired. See Note 12 for further discussion.
Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment. 64
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Fair Value Measurements Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels: Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
| • | Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. |
| • | Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active. |
| • | Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model. |
Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.
Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.
Foreign Currency Translation Adjustments The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity. Noncontrolling Interests Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity. Recently IssuedAdopted Accounting Standards The FASB issuedIn January 2018, Devon adopted ASU 2014-09,Revenue from Contracts with Customers (ASC 606), using the modified retrospective method. See revenue recognition section above for further discussion regarding Devon’s adoption of this revenue recognition standard.
In January 2018, Devon adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 606)715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU supersedesrequires entities to present the revenue recognition requirements in Topic 605,Revenue Recognition and industry-specific guidance in Subtopic 932-605,Extractive Activities – Oil and Gas – Revenue Recognition.This ASU provides guidance concerning the recognition and measurementservice cost component of revenue from contracts with customers. Its objective is to increase the usefulness of informationnet periodic benefit cost in the financial statements regardingsame line item as other employee compensation costs. Only the nature, timing and uncertaintyservice cost component of revenues. The effective datenet periodic benefit cost is eligible for ASU 2014-09 was delayed through the issuance of ASU 2015-14,Revenue from Contracts with Customers – Deferralcapitalization. As a result of the Effective Date,to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. Devon is evaluating the impactof this ASU, will have on its consolidated financial statements of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively. Upon adoption, Devon reclassified $7 million and related disclosures$14 million of non-service cost components of net periodic benefit costs for 2017 and does not plan on early adopting.2016, respectively, from G&A to other expenses. The FASB issued ASU 2015-02,Consolidation (Topic 810): Amendments65
Table of Contents Index to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU Financial StatementsDEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) is considered to be an improvement on current accounting requirements as it reduces the numberIn January 2018, Devon adopted ASU 2016-18, Statement of existing consolidation models.Cash Flows (Topic 230): Restricted Cash. This ASU is effective forrequires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. As a result of the adoption of this ASU, Devon beginning January 1, 2016made changes to the statement of cash flows to include the required presentation and will be applied usingreconciliation of cash, cash equivalents, restricted cash, and restricted cash equivalents retrospectively. Other than presentation, adoption of this ASU did not have a material impact on Devon’s consolidated statements of cash flows.
In the retrospective approach.fourth quarter of 2018, Devon early adopted ASU 2018-02, Income Statement – Reporting Comprehensive Income – Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220). This ASU willallows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. As a result of adopting this ASU, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. In the fourth quarter of 2018, Devon early adopted ASU 2018-14, Compensation, Retirement Benefits and Defined Benefit Plans (Subtopic 715-20): Changes to the Disclosure Requirements for Defined Benefit Plans. This ASU eliminated and added certain disclosure requirements for employers that sponsors defined benefit plans and/or other postretirement plans. Other than changes to required disclosures, this ASU did not have a material impact on Devon’s consolidated financial statements and related disclosures. The SEC released Final Rule No. 33 -10532, Disclosure Update and Simplification, which amends various SEC disclosure requirements determined to be redundant, duplicative, overlapping, outdated or superseded as part of the SEC’s ongoing disclosure effectiveness initiative. The rule was effective November 5, 2018. The rule amended numerous SEC rules, items and forms covering a diverse group of topics. Devon has implemented these required changes to disclosures which generally reduced or eliminated disclosures. Devon will adopt the requirement of presenting a current and comparative year-to-date change in stockholder’s equity roll forward during the first quarter of 2019. Issued Accounting Standards Not Yet Adopted The FASB issued ASU 2015-03,Interest2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Short-term leases can continue being accounted for off balance sheet based on a policy election. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. Devon is adopting this ASU beginning January 1, 2019. Devon will apply the guidance using a modified retrospective transition method at the adoption date. Devon has elected the practical expedient provided in the standard that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. Devon also has elected a policy not to recognize right-of-use assets and lease liabilities related to short-term leases. Devon will be allowed to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented with the 2019 adoption year. Devon has implemented processes, controls, and a technology solution needed to comply with the requirements of this ASU. To adopt Topic 842, Devon expects to recognize right-of-use assets of approximately $400 million with a corresponding lease liability based on the present value of the remaining term minimum lease payments. Devon’s right-of-use assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Additionally, Devon will recognize a $24 million before tax, $19 million net of tax cumulative-effect adjustment to reduce retained earnings. 66
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Imputation(Continued) The FASB issued ASU 2018-04, Fair Value Measurement (Topic 820): Changes to the Disclosure Requirements for Fair Value Measurement. This ASU will eliminate, add and modify certain disclosure requirements for fair value measurement. The ASU is effective for annual and interim periods beginning January 1, 2020, with early adoption permitted for either the entire standard or only the provisions that eliminate or modify requirements. The ASU requires the additional disclosure requirements to be adopted using a retrospective approach. Devon is currently evaluating the provisions of Interest (Topic 835)this ASU and assessing the impact it may have on its disclosures in the notes to the consolidated financial statements. The FASB issued ASU 2018-05-15, Intangibles, Goodwill and Other Internal-Use Software (Subtopic 350-40): SimplifyingCustomer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. This ASU will require a customer in a cloud computing arrangement (i.e., hosting arrangement) that is a service contract to follow the Presentation of Debt Issuance Costs and ASU 2015-15,Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.These ASUs require debt issuanceinternal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets or expense as incurred. Capitalized implementation costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet ashosting arrangement that is a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effective for Devon beginning January 1, 2016 andservice contract will be applied usingamortized over the retrospective approach. These ASUs will not have a material impact on Devon’s consolidated financial statements and related disclosures. The FASB issued ASU 2015-17,Balance Sheet Classificationterm of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet.hosting arrangement, beginning when the module or component of the hosting arrangement is ready for its intended use. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively,January 1, 2020, with early adoption permitted. ThisEntities have the option to adopt the ASU will be early-adopted byusing either a retrospective approach or a prospective approach applied to all implementation costs incurred after the date of the adoption. Devon effective January 1, 2016is currently evaluating the provisions of this ASU and will be applied usingassessing the retrospective approach. This ASU will notimpact it may have a material impact on Devon’sits consolidated financial statements and related disclosures.statements.
2. | Acquisitions and Divestitures |
Formation of EnLink and the General Partner
On March 7, 2014, Devon and Crosstex completed a transaction to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a midstream business that consists of the General Partner and EnLink, which are both publicly traded.Acquisitions
In exchange for a controlling interest in both EnLink and the General Partner, Devon contributed its equity interest in a newly formed Devon subsidiary, EMH, and $100 million in cash. EMH owned midstream assets in the Barnett Shale in north Texas and the Cana- and Arkoma-Woodford Shales in Oklahoma, as well as an economic interest in Gulf Coast Fractionators in Mont Belvieu, Texas. This business combination was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, EMH was the accounting acquirer because its parent company, Devon, obtained control of EnLink and the General Partner as a result of the business combination. Consequently, EMH’s assets and liabilities retained their carrying values. Additionally, the Crosstex assets acquired and liabilities assumed by the General Partner and EnLink in the business combination, as well as the General Partner’s noncontrolling interest in EnLink, were recorded at their fair values which were measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of Crosstex’s net assets acquired was recorded as goodwill.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table summarizes the purchase price (millions, except unit price).
| | | | | Crosstex Energy, Inc. outstanding common shares: | | | | | Held by public shareholders | | | 48.0 | | Restricted shares | | | 0.4 | | | | | | | Total subject to conversion | | | 48.4 | | Exchange ratio | | | 1.0 | x | | | | | | Converted shares | | | 48.4 | | Crosstex Energy, Inc. common share price(1) | | $ | 37.60 | | | | | | | Crosstex Energy, Inc. consideration | | $ | 1,823 | | Fair value of noncontrolling interests in E2(2) | | | 18 | | | | | | | Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests | | $ | 1,841 | | | | | | | Crosstex Energy, LP outstanding units: | | | | | Common units held by public unitholders | | | 75.1 | | Preferred units held by third party (3) | | | 17.1 | | Restricted units | | | 0.4 | | | | | | | Total | | | 92.6 | | Crosstex Energy, LP common unit price(4) | | $ | 30.51 | | | | | | | Crosstex Energy, LP common units value | | $ | 2,825 | | Crosstex Energy, LP outstanding unit options value | | | 4 | | | | | | | Total fair value of noncontrolling interests in Crosstex Energy, LP(4) | | | 2,829 | | | | | | | Total consideration and fair value of noncontrolling interests | | $ | 4,670 | | | | | | |
(1) | The final purchase price is based on the fair value of Crosstex Energy, Inc.’s common shares as of the closing date, March 7, 2014. |
(2) | Represents the value of noncontrolling interests related to the General Partner’s equity investment in E2. |
(3) | Crosstex Energy, LP converted the preferred units to common units in February 2014. |
(4) | The final purchase price is based on the fair value of Crosstex Energy, LP’s common units as of the closing date, March 7, 2014. |
The allocation of the purchase price is as follows (millions):
| | | | | Assets acquired: | | | | | Current assets | | $ | 437 | | Property, plant and equipment, net | | | 2,438 | | Intangible assets | | | 569 | | Equity investment | | | 222 | | Goodwill (1) | | | 3,283 | | Other long-term assets | | | 1 | | Liabilities assumed: | | | | | Current liabilities | | | (515 | ) | Long-term debt | | | (1,454 | ) | Deferred income taxes | | | (210 | ) | Other long-term liabilities | | | (101 | ) | | | | | | Total consideration and fair value of noncontrolling interests | | $ | 4,670 | | | | | | |
(1) | Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes. |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
EnLink Acquisitions
The following table presents a summary of EnLink’s acquisition activity for 2015.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchase Price (Millions) | | | Allocation (Millions) | | Date | | Acquiree | | Cash | | | EnLink Units | | | PP&E | | | Goodwill | | | Intangibles | | | Other | | January 31 | | LPC | | $ | 108 | | | | — | | | $ | 30 | | | $ | 30 | | | $ | 43 | | | $ | 5 | | March 16 | | Coronado | | $ | 240 | | | $ | 360 | | | $ | 302 | | | $ | 18 | | | $ | 281 | | | $ | (1 | ) | October 1 | | Matador | | $ | 145 | | | | — | | | $ | 36 | | | $ | 9 | | | $ | 99 | | | $ | 1 | |
On January 7, 2016, EnLink also acquired Anadarko Basin gathering and processing midstream assets from Tall Oak for approximately $1.5 billion, subject to certain adjustments. EnLink paid approximately $800 million of cash at the time of closing, primarily funded with the issuance of EnLink preferred units, with another $500 million of cash to be paid within 24 months. The remainder of the purchase price consisted of approximately 15.6 million General Partner common units.
EnLink Dropdowns
In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million.
In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common control.
Devon Acquisitions
On February 28, 2014, Devon completed its acquisition of interests in certain affiliates of GeoSouthern for approximately $6.0 billion. Devon funded the acquisition with cash on hand and debt financing. In connection with the GeoSouthern transaction, Devon acquired approximately 82,000 net acres (unaudited) located in DeWitt and Lavaca counties in south Texas. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.
The allocation of the purchase price is as follows (millions).
| | | | | Cash and cash equivalents | | $ | 95 | | Other current assets | | | 256 | | Proved properties | | | 5,026 | | Unproved properties | | | 1,007 | | Midstream assets | | | 86 | | Current liabilities | | | (434 | ) | Long-term liabilities | | | (6 | ) | | | | | | Net assets acquired | | $ | 6,030 | | | | | | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On December 17, 2015, Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199 million of equity. A preliminary allocation of the purchase price at December 31, 2015 was $386 million to unproved properties and $113 million to proved properties and gathering systems.
On January 7, 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $850$849 million of cash, after adjustments, and $659 million of equity. The allocation of the purchase price was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.
Pro Forma Financial InformationDivestitures
The following unaudited pro forma financial information has been prepared assuming both
EnLink and General Partner During the third quarter of 2018, Devon completed the sale of its aggregate ownership interests in EnLink formation and the GeoSouthern acquisition occurred on January 1, 2013. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination and acquisition had been completed at the dates indicated. In addition, they do not project Devon’s results of operationsGeneral Partner for any future period. | | | | | | | | | | | Year Ended December 31, | | | | 2014 | | | 2013 | | | | (Millions) | | Total operating revenues | | $ | 20,213 | | | $ | 12,979 | | Net earnings | | $ | 1,716 | | | $ | 35 | | Noncontrolling interests | | $ | 97 | | | $ | 45 | | Net earnings (loss) attributable to Devon | | $ | 1,619 | | | $ | (10 | ) | Net earnings (loss) per common share attributable to Devon | | $ | 3.94 | | | $ | (0.02 | ) |
Asset Divestitures
During 2014, Devon divested certain properties located throughout Canada and the U.S. as part of its asset portfolio transformation.
Canada
In the second quarter of 2014, Devon sold Canadian conventional assets for $2.8$3.125 billion ($3.125 billion Canadian dollars) and recognized a gain totaling $1.1of approximately $2.6 billion ($0.62.2 billion after-tax). ThisThe proceeds from the sale were utilized to increase Devon’s share repurchase program to $4.0 billion, which is discussed further in Note 18. Additional information on these discontinued operations can be found in Note 19.
Upstream Assets During 2018, Devon received proceeds of approximately $1.0 billion and recognized a net gain is included as a separate itemon asset dispositions of approximately $260 million, primarily from sales of non-core assets in the accompanying consolidated comprehensive statementsBarnett Shale and Delaware Basin. As part of earnings. Included in the gain calculation were asset retirement obligations oftransactions, approximately $700 million assumed by the purchaser as well as the derecognition of approximately $700 million of goodwill allocated to the sold assets. In conjunction with the divestiture, Devon repatriated approximately $2.8 billion of proceeds to the U.S. in the second quarter of 2014, which was utilized to repay commercial paper and term loan balances. Between collecting the divestiture proceeds and repatriating funds to the U.S., Devon recognized an $84 million foreign currency exchange loss and a $29 million foreign exchange currency derivative loss. These losses are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings. U.S.
In the third quarter of 2014, Devon sold certain U.S. assets for $2.2 billion. Additionally, approximately $200 million of asset retirement obligations were assumed by the purchaser. No gainpurchasers. In conjunction with the divestitures, Devon settled certain gas processing contracts and recognized $40 million in settlement expense, which is included in asset dispositions within the 2018 consolidated statements of earnings. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 267 MMBoe, or loss was recognized on the sale. These proceeds were used toward the early retirement18%, of $1.9 billion in senior notes in November 2014 as discussed in Note 13. total U.S. proved reserves. 67
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 3. DerivativeAdditionally, in the first quarter of 2019, Devon completed two separate divestitures of non-core assets in the Permian Basin totaling $300 million. One of the divestitures related to the sale of an entire common operating field, and Devon expects to recognize a gain of approximately $35 million during the first quarter of 2019. As of December 31, 2018, these associated assets and liabilities were classified as held for sale in the accompanying consolidated balance sheet. See Note 19 for additional information. In aggregate, the total estimated proved reserves associated with these divested assets were approximately 25 MMBoe, or less than 2%, of total U.S. proved reserves.
During 2017, Devon received proceeds totaling approximately $420 million, and recognized a net gain on asset dispositions of $212 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves. During 2016, Devon received proceeds totaling approximately $1.9 billion and recognized a net gain on asset dispositions of $809 million, primarily from sales of non-core assets in the Mississippian, east Texas, the Anadarko Basin and the Midland Basin. Estimated proved reserves associated with these assets were approximately 157 MMBoe, or 10%, of total U.S. proved reserves. As part of the transactions, approximately $290 million of asset retirement obligations were assumed by purchasers and approximately $80 million of goodwill was allocated to these divested assets. Access Pipeline In October 2016, Devon divested its 50% interest in Access Pipeline for $1.1 billion ($1.4 billion Canadian dollars) and recognized a gain of approximately $540 million on the transaction. In conjunction with the divestiture, Devon entered into a transportation agreement whereby Devon’s Canadian thermal-oil acreage is dedicated to Access Pipeline for an initial term of 25 years. Devon will be charged a market-based toll on its thermal-oil production over this term. Devon is committed to use less than 90% of the potential pipeline capacity. In addition, Devon is entitled to an incremental payment of approximately $150 million Canadian dollars following sanctioning and committing to the requisite volume increase in respect of a new thermal-oil project on Devon’s Pike lease in Alberta, with such incremental payment being received prior to tolls being payable on such volumes. Canada and Barnett Shale (Subsequent Event) In February 2019, Devon announced its intent to separate its Canadian business and Barnett Shale assets from the Company, based on authorizations provided by its Board of Directors subsequent to December 31, 2018. Devon will evaluate multiple methods of separation for these assets, including potential sales or spin-offs. Devon is in the early stages of marketing these assets and does not currently have any indications that it would recognize an impairment upon separating its Canadian business or its Barnett Shale assets. Devon anticipates reporting all financial information for its Canadian business and Barnett Shale assets as discontinued operations in 2019 when all the requisite criteria are met for such financial statement presentation. 68
Table of Contents Index to Financial InstrumentsStatements
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 3. | Derivative Financial Instruments |
Commodity Derivatives As of December 31, 2015,2018, Devon had the following open oil derivative positions. The first table presentstwo tables present Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The secondthird table presents Devon’s oil derivatives that settle against the respective indices noted within the table. | | | Call Options Sold | | | Price Swaps | | | Price Collars | | Period | | Volume (Bbls/d) | | | Weighted Average Price ($/Bbl) | | | Volume (Bbls/d) | | | Weighted Average Price ($/Bbl) | | | Volume (Bbls/d) | | | Weighted Average Floor Price ($/Bbl) | | | Weighted Average Ceiling Price ($/Bbl) | | Q1-Q4 2016 | | | 18,500 | | | $ | 73.18 | | | Q1-Q4 2019 | | | | 51,719 | | | $ | 59.48 | | | | 87,921 | | | $ | 54.48 | | | $ | 64.49 | | Q1-Q4 2020 | | | | 1,740 | | | $ | 62.88 | | | | 8,951 | | | $ | 52.85 | | | $ | 63.13 | |
| | | | | | | | | | | | | Oil Basis Swaps | | Period | | Index | | Volume (Bbls/d) | | | Weighted Average Differential to WTI ($/Bbl) | | Q1-Q4 2016 | | Western Canadian Select | | | 5,249 | | | $ | (13.67 | ) | Q1-Q4 2016 | | West Texas Sour | | | 5,000 | | | $ | (0.53 | ) | Q1-Q4 2016 | | Midland Sweet | | | 13,000 | | | $ | 0.25 | |
| | Three-Way Price Collars | | Period | | Volume (Bbls/d) | | | Weighted Average Floor Sold Price ($/Bbl) | | | Weighted Average Floor Purchased Price ($/Bbl) | | | Weighted Average Ceiling Price ($/Bbl) | | Q1-Q4 2019 | | | 5,000 | | | $ | 50.00 | | | $ | 63.00 | | | $ | 74.80 | |
| | Oil Basis Swaps | | Period | | Index | | Volume (Bbls/d) | | | Weighted Average Differential to WTI ($/Bbl) | | Q1-Q4 2019 | | Midland Sweet | | | 28,000 | | | $ | (0.46 | ) | Q1-Q4 2019 | | Argus LLS | | | 17,500 | | | $ | 5.00 | | Q1-Q4 2019 | | Argus MEH | | | 16,000 | | | $ | 2.84 | | Q1-Q4 2019 | | NYMEX Roll | | | 38,000 | | | $ | 0.45 | | Q1-Q4 2019 | | Western Canadian Select | | | 31,505 | | | $ | (21.73 | ) | Q1-Q4 2020 | | NYMEX Roll | | | 38,000 | | | $ | 0.31 | | Q1-Q4 2020 | | Western Canadian Select | | | 915 | | | $ | (20.75 | ) |
As of December 31, 2015,2018, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table. | | | Price Swaps | | | Call Options Sold | | | Price Swaps | | | Price Collars | | Period | | Volume (MMBtu/d) | | | Weighted Average Price ($/MMBtu) | | | Volume (MMBtu/d) | | | Weighted Average Price ($/MMBtu) | | | Volume (MMBtu/d) | | | Weighted Average Price ($/MMBtu) | | | Volume (MMBtu/d) | | | Weighted Average Floor Price ($/MMBtu) | | | Weighted Average Ceiling Price ($/MMBtu) | | Q1-Q4 2016 | | | 54,650 | | | $ | 3.17 | | | | 400,000 | | | $ | 4.30 | | | Q1-Q4 2019 | | | | 266,293 | | | $ | 2.86 | | | | 231,474 | | | $ | 2.69 | | | $ | 3.06 | | Q1-Q4 2020 | | | | 26,480 | | | $ | 2.92 | | | | 24,490 | | | $ | 2.74 | | | $ | 3.04 | |
69
Table of Contents | | | | | | | | | | | | | Natural Gas Basis Swaps | | Period | | Index | | Volume (MMBtu/d) | | | Weighted Average Differential to Henry Hub ($/MMBtu) | | Q1-Q4 2016 | | Panhandle Eastern Pipe Line | | | 175,000 | | | $ | (0.34 | ) | Q1-Q4 2016 | | El Paso Natural Gas | | | 125,000 | | | $ | (0.12 | ) | Q1-Q4 2016 | | Houston Ship Channel | | | 30,000 | | | $ | 0.11 | | Q1-Q4 2016 | | Transco Zone 4 | | | 70,000 | | | $ | 0.01 | | Q1-Q4 2017 | | Panhandle Eastern Pipe Line | | | 150,000 | | | $ | (0.34 | ) | Q1-Q4 2017 | | El Paso Natural Gas | | | 50,000 | | | $ | (0.14 | ) | Q1-Q4 2017 | | Houston Ship Channel | | | 35,000 | | | $ | 0.06 | | Q1-Q4 2017 | | Transco Zone 4 | | | 185,000 | | | $ | 0.03 | |
Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) | | Natural Gas Basis Swaps | | Period | | Index | | Volume (MMBtu/d) | | | Weighted Average Differential to Henry Hub ($/MMBtu) | | Q1-Q4 2019 | | Panhandle Eastern Pipe Line | | | 84,466 | | | $ | (0.73 | ) | Q1-Q4 2019 | | El Paso Natural Gas | | | 130,000 | | | $ | (1.46 | ) | Q1-Q4 2019 | | Houston Ship Channel | | | 142,637 | | | $ | 0.01 | | Q1-Q4 2019 | | Transco Zone 4 | | | 7,397 | | | $ | (0.03 | ) |
As of December 31, 2015, EnLink2018, Devon had the following open NGL derivative positions associated with gas processing and fractionation. EnLink’spositions. Devon’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index. | | | | | | | | | | | | | | | | | | | | | | | Price Swaps | | Period | | Product | | Volume (Bbls/d) | | | Weighted Average Price ($/Bbl) | | Q1-Q4 2019 | | Ethane | | | 1,000 | | | $ | 11.55 | | Q1-Q4 2019 | | Natural Gasoline | | | 4,500 | | | $ | 55.93 | | Q1-Q4 2019 | | Normal Butane | | | 4,000 | | | $ | 33.69 | | Q1-Q4 2019 | | Propane | | | 8,500 | | | $ | 30.01 | |
Period
| | Product | | Volume (Total) | | | Weighted Average
Price Paid | | | Weighted Average
Price Received | | Q1 2016-Q4 2016
| | Ethane | | | 571 | | | | MBbls | | | $ | 0.29/gal | | | | Index | | Q1 2016-Q4 2016
| | Propane | | | 812 | | | | MBbls | | | | Index | | | $ | 0.81/gal | | Q1 2016-Q4 2016
| | Normal Butane | | | 113 | | | | MBbls | | | | Index | | | $ | 0.61/gal | | Q1 2016-Q4 2016
| | Natural Gasoline | | | 61 | | | | MBbls | | | | Index | | | $ | 1.02/gal | | Q1 2016-Q1 2017
| | Natural Gas | | | 13,829 | | | | MMBtu/d | | | $ | 2.65/MMBtu | | | | Index | |
Interest Rate Derivatives As of December 31, 2015,2018, Devon had the following open interest rate derivative positions: | | | | | | | Notional | | Rate Received | | Rate Paid | | Expiration | (Millions) | | | | | | | $100 | | Three Month LIBOR | | 0.92% | | December 2016 | $100 | | 1.76% | | Three Month LIBOR | | January 2019 | $750 | | Three Month LIBOR | | 2.98% | | December 2048 (1) |
Notional | | | Rate Received | | | Rate Paid | | Expiration | $ | 100 | | | 1.76% | | | Three Month LIBOR | | January 2019 |
(1) | Mandatory settlement in December 2018. |
Foreign Currency Derivatives
As of December 31, 2015, Devon had the following open foreign currencyIn January 2019, this interest rate derivative position:position settled.
| | | | | | | | | Forward Contract | Currency | | Contract Type | | CAD Notional | | Weighted Average Fixed Rate Received | | Expiration | | | | | (Millions) | | (CAD-USD) | | | Canadian Dollar | | Sell | | $3,560 | | 0.723 | | March 2016 |
Financial Statement Presentation The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption. | | | Year Ended December 31, | | | | | 2015 | | | 2014 | | | 2013 | | | Year Ended December 31, | | | | (Millions) | | | 2018 | | | 2017 | | | 2016 | | Commodity derivatives: | | | | | | | | | | | | �� | | | | | | | Oil, gas and NGL derivatives | | $ | 503 | | | $ | 1,989 | | | $ | (191 | ) | | Marketing and midstream revenues | | | 9 | | | | 22 | | | | — | | | Upstream revenues | | | $ | 608 | | | $ | 157 | | | $ | (201 | ) | Marketing revenues | | | | (1 | ) | | | 3 | | | | (2 | ) | Interest rate derivatives: | | | | | | | | | | | | | | | | | | | Other nonoperating items | | | (20 | ) | | | (1 | ) | | | — | | | Other expenses | | | | 65 | | | | (22 | ) | | | (19 | ) | Foreign currency derivatives: | | | | | | | | | | | | | | | | | | | Other nonoperating items | | | 246 | | | | 60 | | | | 56 | | | | | | | | | | | | | | Other expenses | | | | — | | | | — | | | | (153 | ) | Net gains (losses) recognized | | $ | 738 | | | $ | 2,070 | | | $ | (135 | ) | | $ | 672 | | | $ | 138 | | | $ | (375 | ) | | | | | | | | | | | |
70
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption. | | | December 31, 2015 | | | December 31, 2014 | | | | | (Millions) | | | December 31, 2018 | | | December 31, 2017 | | Commodity derivative assets: | | | | | | | | | | | | | Derivatives, at fair value | | $ | 34 | | | $ | 1,984 | | | Other current assets | | | $ | 637 | | | $ | 203 | | Other long-term assets | | | 1 | | | | 11 | | | | 40 | | | | 2 | | Interest rate derivative assets: | | | | | | | | | | | | | Derivatives, at fair value | | | 1 | | | | 1 | | | Other long-term assets | | | 1 | | | | — | | | Foreign currency derivative assets: | | | | | | Derivatives, at fair value | | | 8 | | | | 8 | | | | | | | | | | | Other current assets | | | | — | | | | 1 | | Total derivative assets | | $ | 45 | | | $ | 2,004 | | | $ | 677 | | | $ | 206 | | | | | | | | | | Commodity derivative liabilities: | | | | | | | | | | | | | Other current liabilities | | $ | 14 | | | $ | 28 | | | $ | 67 | | | $ | 259 | | Other long-term liabilities | | | 4 | | | | 28 | | | | 1 | | | | 27 | | Interest rate derivative liabilities: | | | | | | | | | | | | | Other current liabilities | | | — | | | | 1 | | | | — | | | | 64 | | Other long-term liabilities | | | 22 | | | | — | | | Foreign currency derivative liabilities: | | | | | | Other current liabilities | | | 8 | | | | — | | | | | | | | | | | Total derivative liabilities | | $ | 48 | | | $ | 57 | | | $ | 68 | | | $ | 350 | | | | | | | | | |
4. | Share-Based Compensation |
In the second quarter of 2015,2017, Devon’s stockholders approved the 2015 Long-Term Incentive2017 Plan. The 20152017 Plan replaces the 2009 Long-Term Incentive Plan, as amended.2015 Plan. From the effective date of the 20152017 Plan, no further awards may be made under the 20092015 Plan, and awards previously granted will continue to be governed by the terms of the 2009 Plan.respective award documents. Subject to the terms of the 20152017 Plan, awards may be made under the 2015 Plan for a total of 2833.5 million shares of Devon common stock, plus the number of shares available for issuance under the 20092015 Plan (including shares subject to outstanding awards underthat were transferred to the 20092017 Plan that are subsequently forfeited, canceled or expire)in accordance with its terms). The 20152017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance awards or units and stock appreciation rights to eligible employees. The 20152017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 20152017 Plan, options and stock appreciation rights represent one share and other awards represent three2.3 shares. Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.
Devon did not have an annual long-term incentive grant in 2013 due to revisions in the timing of the employee compensation cycle. The annual long-term incentive grant related to 2013 performance was granted in February 2014.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the effects of share-based compensation included in Devon’s accompanying consolidated comprehensive statements of earnings. Gross G&A for the years ended December 31, 2015 and 2014 includes $31 million and $17 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans.
The vesting for certain share-based awards was accelerated in 20142018 and 2016 in conjunction with the divestiturereduction of Devon’s Canadian conventional assets. For the year ended December 31, 2014, approximately $15 million of associated expense for these accelerated awardsworkforce activities described in Note 6 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings. | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | Gross general and administrative expense for share-based compensation | | $ | 225 | | | $ | 199 | | | $ | 157 | | Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties | | $ | 63 | | | $ | 53 | | | $ | 60 | | Related income tax benefit | | $ | 45 | | | $ | 42 | | | $ | 29 | |
The table below presents the share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings. | | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | G&A | | $ | 122 | | | $ | 141 | | | $ | 124 | | Exploration expenses | | | 4 | | | | 7 | | | | 6 | | Restructuring and transaction costs | | | 31 | | | | — | | | | 60 | | Total | | $ | 157 | | | $ | 148 | | | $ | 190 | | Related income tax benefit | | $ | 22 | | | $ | 6 | | | $ | 6 | |
71
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plans. | | | | | | | | | | | | | | Restricted Stock | | | Performance-Based | | | Performance | | | | Restricted Stock Awards and Units | | | Performance-Based Restricted Stock Awards | | | Performance Share Units | | | Awards and Units | | | Restricted Stock Awards | | | Share Units | | | | Awards and Units | | Weighted Average Grant-Date Fair Value | | | Awards | | Weighted Average Grant-Date Fair Value | | | Units | | Weighted Average Grant-Date Fair Value | | | Awards and Units | | | Weighted Average Grant-Date Fair Value | | | Awards | | | Weighted Average Grant-Date Fair Value | | | Units | | | | | Weighted Average Grant-Date Fair Value | | | | (Thousands, except fair value data) | | | (Thousands, except fair value data) | | Unvested at 12/31/14 | | | 4,304 | | | $ | 60.85 | | | | 380 | | | $ | 59.41 | | | | 1,477 | | | $ | 70.90 | | | Unvested at 12/31/17 | | | | 6,328 | | | $ | 36.81 | | | | 575 | | | $ | 38.92 | | | | 2,758 | | | | $ | 41.21 | | Granted | | | 2,771 | | | $ | 63.57 | | | | 236 | | | $ | 62.02 | | | | 786 | | | $ | 84.14 | | | | 3,592 | | | $ | 35.98 | | | | — | | | $ | — | | | | 845 | | | | $ | 37.40 | | Vested | | | (1,834 | ) | | $ | 60.33 | | | | (153 | ) | | $ | 59.49 | | | | (337 | ) | | $ | 66.00 | | | | (3,114 | ) | | $ | 38.75 | | | | (273 | ) | | $ | 42.22 | | | | (571 | ) | | | $ | 84.22 | | Forfeited | | | (503 | ) | | $ | 62.22 | | | | (29 | ) | | $ | 64.18 | | | | (67 | ) | | $ | 79.20 | | | | (843 | ) | | $ | 35.58 | | | | — | | | $ | — | | | | (164 | ) | | | $ | 33.92 | | | | | | | | | | | | | | | | | | | Unvested at 12/31/15 | | | 4,738 | | | $ | 62.49 | | | | 434 | | | $ | 60.48 | | | | 1,859 | (1) | | $ | 76.17 | | | | | | | | | | | | | | | | | | | | Unvested at 12/31/18 | | | | 5,963 | | | $ | 35.47 | | | | 302 | | | $ | 35.93 | | | | 2,868 | | | (1 | ) | | $ | 30.14 | |
(1) | A maximum of 3.75.7 million common shares could be awarded based upon Devon’s final TSR ranking. |
The following table presents the aggregate fair value of awards and units that vested during the indicated period. | | | | | | | | | | | | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | Restricted stock awards and units | | $ | 101 | | | $ | 112 | | | $ | 141 | | Performance-based restricted stock awards | | $ | 8 | | | $ | 10 | | | $ | 5 | | Performance share units | | $ | 22 | | | $ | — | | | $ | — | |
| | 2018 | | | 2017 | | | 2016 | | Restricted Stock Awards and Units | | $ | 111 | | | $ | 105 | | | $ | 73 | | Performance-Based Restricted Stock Awards | | $ | 10 | | | $ | 10 | | | $ | 5 | | Performance Share Units | | $ | 20 | | | $ | 38 | | | $ | 13 | |
The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2015.2018. | | | | | | | | | | | | | | | Restricted Stock Awards and Units | | | Performance-Based Restricted Stock Awards | | | Performance Share Units | | Unrecognized compensation cost (millions) | | $ | 198 | | | $ | 6 | | | $ | 45 | | Weighted average period for recognition (years) | | | 2.5 | | | | 2.6 | | | | 1.8 | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | Performance-Based | | | | | | | | Restricted Stock | | | Restricted Stock | | | Performance | | | | Awards and Units | | | Awards | | | Share Units | | Unrecognized compensation cost | | $ | 117 | | | $ | 1 | | | $ | 23 | | Weighted average period for recognition (years) | | | 2.4 | | | | 1.0 | | | | 1.7 | |
Restricted Stock Awards and Units Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from zeroone to four years. During the vesting period, recipients of restricted stock awards made under the 2015 Plan or 2009 Plan receive dividends that are not subject to restrictions or other limitations. However, dividends declared during the vesting period with respect to restricted stock awards made under the 2017 Plan and all restricted stock units will not be paid until the underlying award vests. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period. 72
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Performance-Based Restricted Stock Awards Performance-based restricted stock awards arewere granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zeroone to four years. In order for awards to vest, the performance target must be met in the first year, and ifyear. If the performance target is met, recipients arethe recipient is entitled to dividends onunder the awards over the remaining service vesting period.same terms described above for nonperformance-based restricted stock. If the performance target and service period requirements are not met, the award does not vest. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period. Performance Share Units Performance share units are granted to certain members of Devon’s management and senior management.employees. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200% of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date. At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents the assumptions related to performance share units granted. | | | 2015 | | 2014 | | 2013 | | 2018 | | | 2017 | | | 2016 | | Grant-date fair value | | $81.99 – $85.05 | | $70.18 – $81.05 | | $61.27 – $63.48 | | | $36.23 | | | — | | $ | 37.88 | | | | $51.05 | | | — | | | $53.12 | | | | $9.24 | | | — | | | $10.61 | | Risk-free interest rate | | 1.06% | | 0.54% | | 0.26% – 0.36% | | 2.28% | | | 1.50% | | | 0.94% | | Volatility factor | | 26.2% | | 28.8% | | 30.3% | | 45.8% | | | 45.8% | | | 37.7% | | Contractual term (years) | | 2.89 | | 2.89 | | 3.0 | | 2.89 | | | 2.89 | | | 2.83 | |
Stock Options In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zeroone to four years. The fair value of stock options on DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions, including a volatility factor, dividend yield rate, risk-free interest rate and expected term. No stock options were granted in 2015, 20142018, 2017 and 2013.2016. The following table presents a summary of Devon’s outstanding stock options. | | | | | | Weighted Average | | | | | | | | Options | | | Exercise Price | | | Remaining Term | | | Intrinsic Value | | | | (Thousands) | | | | | | | (Years) | | | | | | Outstanding at December 31, 2017 | | | 1,746 | | | $ | 70.04 | | | | | | | | | | Expired | | | (1,029 | ) | | $ | 72.51 | | | | | | | | | | Outstanding at December 31, 2018 | | | 717 | | | $ | 66.49 | | | | 0.87 | | | $ | — | | Exercisable at December 31, 2018 | | | 717 | | | $ | 66.49 | | | | 0.87 | | | $ | — | |
73
Table of Contents | | | | | | | | | | | | | | | | | | | | | | Weighted Average | | | | | | | Options | | | Exercise Price | | | Remaining Term | | | Intrinsic Value | | | | (Thousands) | | | | | | (Years) | | | (Millions) | | Outstanding at December 31, 2014 | | | 4,218 | | | $ | 70.56 | | | | | | | | | | Granted | | | — | | | $ | — | | | | | | | | | | Exercised | | | (63 | ) | | $ | 64.25 | | | | | | | | | | Expired | | | (680 | ) | | $ | 84.36 | | | | | | | | | | Forfeited | | | (27 | ) | | $ | 66.71 | | | | | | | | | | | | | | | | | | | | | | | | | | | Outstanding at December 31, 2015 | | | 3,448 | | | $ | 67.98 | | | | 2.41 | | | $ | — | | | | | | | | | | | | | | | | | | | Vested and expected to vest at December 31, 2015 | | | 3,448 | | | $ | 67.98 | | | | 2.41 | | | $ | — | | | | | | | | | | | | | | | | | | | Exercisable at December 31, 2015 | | | 3,448 | | | $ | 67.98 | | | | 2.41 | | | $ | — | | | | | | | | | | | | | | | | | | |
The aggregate intrinsic value of stock options that were exercised during 2015, 2014 and 2013 was $0.2 million, $9 million and $0.3 million, respectively. Index to Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) As of December 31, 2015,2018, Devon had no unrecognized compensation cost related to unvested stock options. EnLink Share-Based Awards
In March 2015, the General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees for 2014. The combined grant fair value was $7 million, and the total cost was recognized in the first quarter of 2015 due to the awards vesting immediately.
The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units asconsolidated comprehensive statements of December 31, 2015.earnings. | | | | | | | | | | | | | | | | | | | General Partner | | | EnLink | | | | Restricted Incentive Units | | | Performance Units | | | Restricted Incentive Units | | | Performance Units | | Unrecognized compensation cost (millions) | | $ | 17 | | | $ | 3 | | | $ | 16 | | | $ | 3 | | Weighted average period for recognition (years) | | | 1.6 | | | | 2.0 | | | | 1.6 | | | | 2.0 | |
| | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Proved oil and gas assets | | $ | 109 | | | $ | — | | | $ | 435 | | Other assets | | | 47 | | | | — | | | | 2 | | Total asset impairments | | $ | 156 | | | $ | — | | | $ | 437 | | | | | | | | | | | | | | | Unproved impairments | | $ | 95 | | | $ | 217 | | | $ | 77 | |
Proved Oil and Gas and Other Asset Impairments In 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no longer in its development plans and approximately $47 million of non-oil and gas asset impairments. In 2016, Devon impaired a portion of its U.S. oil and gas portfolio due to lower forecasted oil, gas and NGL prices. UnprovedImpairments In 2018, 2017 and 2016, Devon allowed certain non-core acreage to expire without plans for development resulting in unproved impairments. 6. | Restructuring and Transaction Costs |
The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated balance sheets. | | Other | | | Other | | | | | | | | Current | | | Long-term | | | | | | | | Liabilities | | | Liabilities | | | Total | | Balance as of December 31, 2016 | | $ | 48 | | | $ | 62 | | | $ | 110 | | Changes related to prior years’ restructurings | | | (29 | ) | | | (31 | ) | | | (60 | ) | Balance as of December 31, 2017 | | $ | 19 | | | $ | 31 | | | $ | 50 | | Changes due to 2018 workforce reductions | | | 30 | | | | — | | | | 30 | | Changes related to prior years’ restructurings | | | (2 | ) | | | (15 | ) | | | (17 | ) | Balance as of December 31, 2018 | | $ | 47 | | | $ | 16 | | | $ | 63 | |
74
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) The following table presents the asset impairments recognized in 2015, 2014 and 2013.
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | U.S. oil and gas assets | | $ | 17,992 | | | $ | — | | | $ | 1,110 | | Canada oil and gas assets | | | 1,257 | | | | — | | | | 843 | | Canada goodwill | | | — | | | | 1,941 | | | | — | | EnLink goodwill | | | 1,328 | | | | — | | | | — | | EnLink other intangible assets | | | 223 | | | | — | | | | — | | Other assets | | | 20 | | | | 12 | | | | 23 | | | | | | | | | | | | | | | Total asset impairments | | $ | 20,820 | | | $ | 1,953 | | | $ | 1,976 | | | | | | | | | | | | | | |
Oil and Gas Impairments
Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1.
The oil and gas impairments resulted from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, natural gas and NGLs, which significantly reduced proved reserves values and, to a lesser degree, proved reserves. For further information, see Note 21.
Goodwill and Other Intangible Assets Impairments2018 Workforce Reductions
In 2015,2018, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon recognized goodwill and other intangible asset impairments related to EnLink’s business. In 2014, Devon recognized a goodwill impairment related to its Canadian reporting unit. Additional information regarding these impairments is discussed in Note 12. Canadian Reduction in Work Force
In 2015, Devon recognized $24$114 million of employee related and other costs associated with the reduction in work force made subsequent to the completionrestructuring expenses during 2018, primarily consisting of the Jackfish development projects and a decrease in planned capital investment resulting from the drop in commodity prices. Devon incurred employee severance, lease obligation and other costs related to the vacated office space as part of the cost reduction plan.
Canadian Divestitures
During 2014, Devon recognized $46employee-related costs. Of these expenses, $31 million of employee related and other costs associated with its divestiture of certain Canadian assets. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are noncash charges.
Office Consolidation
Near the end Additionally, $14 million resulted from estimated settlements of 2012, Devon consolidated its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon closed its office in Houston,
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)defined retirement benefits.
transferred operational responsibilities for assetsPrior Years’ Restructurings
In 2016, Devon recognized $227 million in south Texas, east Texasemployee-related and Louisiana to Oklahoma City and incurred $134 million of restructuringother costs associated with a reduction in workforce that was made in response to the consolidation. The employee severance and retentiondepressed commodity price environment. Of these employee-related costs, included amounts related to cash severance costs andapproximately $60 million resulted from accelerated vesting of share-based grants. The lease obligations and other costsgrants, which are associated withnoncash charges. Additionally, approximately $24 million resulted from estimated defined benefit settlements. As a result of the reduction of workforce, Devon ceased using certain office space that iswas subject to non-cancellable operating lease agreementsarrangements. Devon recognized $23 million in restructuring costs that represent the present value of its future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using. Transaction Costs In 2016, Devon ceased using as partrecognized $11 million in transaction costs primarily associated with the closing of the office consolidation.STACK acquisition discussed in Note 2. Due to a lack of demand for vacated office space in which Devon’s remaining leases are located, in 2015, Devon recognized an additional $54 million expense as a result of its inability to fully sublease remaining office space.
Financial Statement Presentation
The following table summarizes restructuring costsDevon’s other expenses presented in the accompanying consolidated comprehensive statements of earnings. | | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Foreign exchange (gain) loss, net | | $ | 139 | | | $ | (132 | ) | | $ | 39 | | Asset retirement obligation accretion | | | 59 | | | | 62 | | | | 75 | | Other, net | | | (58 | ) | | | (13 | ) | | | (13 | ) | Total | | $ | 140 | | | $ | (83 | ) | | $ | 101 | |
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | Office consolidation and offshore divestiture: | | | | | | | | | | | | | Employee severance and retention | | $ | — | | | $ | — | | | $ | 13 | | Lease obligations and other | | | 54 | | | | — | | | | 41 | | Canada divestitures: | | | | | | | | | | | | | Employee severance and retention | | | 11 | | | | 42 | | | | — | | Lease obligations and other | | | 13 | | | | 4 | | | | — | | | | | | | | | | | | | | | Restructuring costs | | $ | 78 | | | $ | 46 | | | $ | 54 | | | | | | | | | | | | | | |
The following table summarizes Devon’s restructuring liabilities.Foreign exchange (gain) loss, net
| | | | | | | | | | | | | | | Other Current Liabilities | | | Other Long-term Liabilities | | | Total | | | | (Millions) | | Balance as of December 31, 2013 | | $ | 27 | | | $ | 18 | | | $ | 45 | | Changes due to office consolidation and offshore divestiture | | | (18 | ) | | | (11 | ) | | | (29 | ) | Changes due to Canadian divestitures | | | 4 | | | | — | | | | 4 | | | | | | | | | | | | | | | Balance as of December 31, 2014 | | | 13 | | | | 7 | | | | 20 | | Changes due to office consolidation and offshore divestiture | | | 1 | | | | 46 | | | | 47 | | Changes due to Canadian divestitures | | | (1 | ) | | | 10 | | | | 9 | | | | | | | | | | | | | | | Balance as of December 31, 2015 | | $ | 13 | | | $ | 63 | | | $ | 76 | | | | | | | | | | | | | | |
The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. The amounts in the table above include both unrealized and realized foreign exchange impacts of foreign currency denominated monetary assets and liabilities, including intercompany loans between subsidiaries with different functional currencies. Unrealized gains and losses arise from the remeasurement of these foreign currency denominated monetary assets and liabilities and intercompany loans. Realized gains and losses arise when there are settlements of these foreign currency denominated monetary assets and liabilities and intercompany loans. 75
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Foreign currency denominated intercompany loan activity during 2018 resulted in a realized loss of $241 million, as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. These losses during 2018, were partially offset by reversing $195 million of previously recognized unrealized losses on intercompany loan activity. Foreign currency denominated intercompany loan activity during 2016 resulted in a realized gain of $63 million, as a result of the weakening of the U.S. dollar in relation to the Canadian dollar. These gains during 2016, were partially offset by reversing $10 million of previously recognized unrealized gains on intercompany loan activity. Income Tax Expense (Benefit) The following table presents Devon’s income tax components. | | | Year Ended December 31, | | | | | 2015 | | | 2014 | | | 2013 | | | Year Ended December 31, | | | | (Millions) | | | 2018 | | | 2017 | | | 2016 | | Current income tax expense (benefit): | | | | | | | | | | | | | | | | | | | U.S. federal | | $ | (243 | ) | | $ | 152 | | | $ | 73 | | | $ | (14 | ) | | $ | 9 | | | $ | 3 | | Various states | | | (8 | ) | | | 18 | | | | (5 | ) | | | (3 | ) | | | — | | | | (11 | ) | Canada and various provinces | | | 14 | | | | 307 | | | | 4 | | | | (53 | ) | | | 103 | | | | 106 | | | | | | | | | | | | | Total current tax expense (benefit) | | | (237 | ) | | | 477 | | | | 72 | | | | (70 | ) | | | 112 | | | | 98 | | | | | | | | | | | | | Deferred income tax expense (benefit): | | | | | | | | | | | | | | | | | | | U.S. federal | | | (5,033 | ) | | | 1,610 | | | | 198 | | | | 248 | | | | — | | | | — | | Various states | | | (336 | ) | | | 93 | | | | 59 | | | | 63 | | | | — | | | | — | | Canada and various provinces | | | (459 | ) | | | 188 | | | | (160 | ) | | | (85 | ) | | | (97 | ) | | | 43 | | | | | | | | | | | | | Total deferred tax expense (benefit) | | | (5,828 | ) | | | 1,891 | | | | 97 | | | | 226 | | | | (97 | ) | | | 43 | | | | | | | | | | | | | Total income tax expense (benefit) | | $ | (6,065 | ) | | $ | 2,368 | | | $ | 169 | | | | | | | | | | | | | | Total income tax expense | | | $ | 156 | | | $ | 15 | | | $ | 141 | |
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following: | | | | | | | | Year Ended December 31, | | | | Year Ended December 31, | | | 2018 | | | 2017 | | | 2016 | | | | 2015 | | 2014 | | 2013 | | | Total income tax expense (benefit) (millions) | | $ | (6,065 | ) | | $ | 2,368 | | | $ | 169 | | | Current income tax expense (benefit) | | | $ | (70 | ) | | $ | 112 | | | $ | 98 | | Deferred income tax expense (benefit) | | | | 226 | | | | (97 | ) | | | 43 | | Total income tax expense | | | $ | 156 | | | $ | 15 | | | $ | 141 | | | | | | | | | | | | | | | | | | | | | | | | U.S. statutory income tax rate | | | (35 | )% | | | 35 | % | | | 35 | % | | | 21 | % | | | 35 | % | | | 35 | % | Non-deductible goodwill and intangible impairment | | | 2 | % | | | 23 | % | | | 0 | % | | Taxation on Canadian operations | | | 1 | % | | | (4 | )% | | | 9 | % | | U.S. Tax Reform | | | | 0 | % | | | 36 | % | | | 0 | % | Legal entity restructuring | | | | 2 | % | | | (94 | %) | | | 19 | % | State income taxes | | | (1 | )% | | | 2 | % | | | 23 | % | | | 5 | % | | | 0 | % | | | 10 | % | Repatriations | | | 0 | % | | | 2 | % | | | 65 | % | | Change in unrecognized tax benefits | | | | (5 | %) | | | 2 | % | | | (16 | %) | Other | | | | (0 | %) | | | (13 | %) | | | 8 | % | Deferred tax asset valuation allowance | | | 4 | % | | | 0 | % | | | 0 | % | | | (6 | %) | | | 36 | % | | | (89 | %) | Other | | | 0 | % | | | 0 | % | | | (19 | )% | | | | | | | | | | | | | Effective income tax rate | | | (29 | )% | | | 58 | % | | | 113 | % | | | 17 | % | | | 2 | % | | | (33 | %) | | | | | | | | | | | |
Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur.
76
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examinationexaminations by the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
allowance. Numerous judgementsjudgments and assumptions are inherent in the determination of future taxable income, including factors such as future operationoperating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. 2015
2018 In the thirdsecond quarter of 2018, Devon’s Canadian segment utilized a portion of its capital losses as a part of an internal legal entity restructuring. A valuation allowance remains recorded against the remaining balance of the capital losses. During 2018, Devon recorded a tax benefit of $42 million related to unrecognized tax benefits, primarily as a result of a favorable Canadian court decision and fourththe closure of prior year IRS audits. Throughout 2017 and through the first two quarters of 2015,2018, Devon’s U.S. segment maintained a 100% valuation allowance against its U.S. deferred tax assets. However, upon closing the EnLink divestiture in the third quarter of 2018, Devon realized a pre-tax gain of $2.6 billion. Based on its net deferred tax liability position, current period projected net operating loss utilization, and projections of future taxable income, 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. As part of its reassessment, Devon determined that apart from the sale of EnLink and the General Partner, Devon’s U.S. segment would have remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the $259 million of the deferred tax benefit resulting from the release of the remainder of the full valuation allowance position was allocated entirely to discontinued operations. A partial valuation allowance continues to be held against certain Canadian segment deferred tax assets. During 2018, the Canadian segment reduced its valuation allowance by approximately $59 million. 2017 The Tax Reform Legislation, enacted on December 22, 2017, contained several key tax provisions that affected Devon, including a one-time mandatory transition tax on accumulated foreign earnings and a reduction of the corporate income tax rate to 21% effective January 1, 2018. Devon was required to recognize the effect of the tax law changes in the period of enactment, such as determining the transition tax, remeasuring U.S. deferred tax assets and liabilities and reassessing the net realizability of deferred tax assets and liabilities. Devon’s U.S. segment recognized $167 million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings, and $108 million in deferred tax expense related to the reduction of the U.S. corporate income tax rate to 21%. 77
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) In the fourth quarter of 2017, Devon’s Canadian segment generated nonrecurring capital losses from internal legal entity restructuring. A deferred tax asset of $727 million was recognized related to the capital losses, offset by a $641 million increase in the valuation allowance. Devon maintained a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to asset impairments and significant net operating losses for U.S. federal and state income tax. Devon reduced its U.S. segment valuation allowance by $323 million in 2017 based primarily on the financial income recorded during the period. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets. Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate in 2017 due to lower relative earnings during the period. 2016 Devon recorded a tax expense of $63 million related to unrecognized tax benefits during 2016, primarily as a result of Canadian audits and legal proceedings. During 2016, Devon’s U.S. segment recognized an additional $313 million valuation allowance against its deferred tax assets. The allowance resulted from continued financial losses in 2016. As of December 31, 2016, the allowance continued to represent a 100% valuation against the U.S. net deferred tax assets. Additionally, the Canadian segment recognized a $71 million partial valuation allowance resulting from continued financial losses. During the third quarter of 2016, Devon derecognized $83 million of goodwill related to its U.S. operations in conjunction with the divestiture of certain non-core U.S. upstream oil and intangibles impairments of approximately $1.6 billion. gas assets. These impairments areitems were not deductible for purposes of calculating income tax and, therefore, have an impact onimpacted the effective tax rate. During 2015, Devon recorded approximately $18 billion78
Table of oil and gas impairments relatedContents Index to its U.S. operations. These impairments resulted in deferred tax assets against which we recognized a $967 million valuation allowance that impacted the effective tax rate and is discussed in the next section.Financial Statements 2014
In the second and fourth quarters of 2014, goodwill was removed in conjunction with the Canadian conventional asset divestitures, and Devon recorded a goodwill impairment in the Canadian reporting unit, respectively. These transactions are not deductible for purposes of calculating income tax and therefore have an impact on the effective tax rate.
Additionally, during 2014, Devon repatriated to the U.S. $2.8 billion of cash relating to the Canadian asset divestiture. In conjunction with the repatriation, Devon recognized approximately $105 million of additional income tax expense for the full year. Prior to the repatriation, Devon had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, Devon retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax. After the use of foreign tax credits, the current income tax on the repatriation was $67 million.
Furthermore, Devon completed its divestiture program of certain assets in the U.S. In conjunction with the divestiture closing and due to the availability of additional tax deductions, Devon recognized $294 million of current income tax expense. The current tax expense was entirely offset by the recognition of deferred tax benefits.
Devon also recorded a $46 million deferred tax liability in conjunction with the formation of EnLink in 2014.
2013
In the second and fourth quarters of 2013, Devon repatriated to the U.S. a total of $4.3 billion of its cash held outside of the U.S. In the fourth quarter of 2013, Devon announced plans to divest of its Canadian conventional assets. These events resulted in an incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Deferred Tax Assets and Liabilities The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities. | | | December 31, | | | | | 2015 | | 2014 | | | December 31, | | | | (Millions) | | | 2018 | | | 2017 | | Deferred tax assets: | | | | | | | | | | | | | Property and equipment | | $ | 490 | | | $ | — | | | Asset retirement obligations | | | 485 | | | | 458 | | | $ | 300 | | | $ | 313 | | Accrued liabilities | | | 160 | | | | 150 | | | | 50 | | | | 62 | | Net operating loss carryforwards | | | 175 | | | | 200 | | | | 287 | | | | 796 | | Pension benefit obligations | | | 106 | | | | 113 | | | | 44 | | | | 54 | | Canadian capital loss carryforwards | | | | 609 | | | | 760 | | Other | | | 162 | | | | 180 | | | | 87 | | | | 135 | | | | | | | | | | Total deferred tax assets before valuation allowance | | | 1,578 | | | | 1,101 | | | | 1,377 | | | | 2,120 | | Less: valuation allowance | | | (967 | ) | | | — | | | | (640 | ) | | | (968 | ) | | | | | | | | | Net deferred tax assets | | | 611 | | | | 1,101 | | | | 737 | | | | 1,152 | | | | | | | | | | Deferred tax liabilities: | | | | | | | | | | | | | Property and equipment | | | (1,187 | ) | | | (6,940 | ) | | | (1,473 | ) | | | (1,288 | ) | Fair value of financial instruments | | | — | | | | (699 | ) | | Long-term debt | | | (36 | ) | | | (115 | ) | | | — | | | | (92 | ) | Other | | | (271 | ) | | | (160 | ) | | | (141 | ) | | | (261 | ) | | | | | | | | | Total deferred tax liabilities | | | (1,494 | ) | | | (7,914 | ) | | | (1,614 | ) | | | (1,641 | ) | | | | | | | | | Net deferred tax liability | | $ | (883 | ) | | $ | (6,813 | ) | | $ | (877 | ) | | $ | (489 | ) | | | | | | | | |
At December 31, 2015,2018, Devon has $175recognized $287 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The Canadian segment has $595 million of noncapital loss carryforwards expiring between 2029 and 2038. Devon’s U.S. segment has $389 million of U.S. federal net operating loss carryforwards consist of $495 million of Canadian carryforwards that expire between 2030expiring in 2037 and 2035, $275$784 million of U.S. state net operating loss carryforwards that expireexpiring between 20182019 and 2035 and $205 million of carryforwards related to EnLink’s operations that expire between 2028 and 2035.2038. In the current environment, Devon expects the tax benefits from the U.S. federal, majority of U.S. state and Canadian and EnLink net operatingnoncapital loss carryforwards to be utilized in 20172019 and beyond. Devon also has $6 million of deferred tax assets related to alternative minimum tax credits, which have no expiration date and will be available for use against tax on future taxable income.beyond. At the end of 2015, Devon had deferred tax assets that largely resulted from the full cost impairments recognized during 2015. As a result of Devon’s sale of its aggregate ownership interests in EnLink and the recent cumulative financial losses, Devon recorded a $967General Partner during the third quarter of 2018, Devon’s U.S. segment reassessed its position and released its full valuation allowance position, maintaining only $31 million or 100%,of valuation allowance against the U.S.certain deferred tax assets, asincluding certain tax credits and state net operating losses. Also during 2018, Devon’s Canadian segment maintained a valuation allowance of December 31, 2015.$609 million against the deferred tax asset related to the Canadian capital loss carryforward due to projected lack of future capital gain income. In the event Devon were to determine that it would be able to realize the deferred income tax assets in the future, Devon would adjust the valuation allowance, reducing the provision for income taxes in the period of such adjustment.
AsAfter enactment of the Tax Reform Legislation, Devon’s Canadian segment is the sole foreign operation to be considered for the indefinitely reinvested assertion of APB 23. Devon’s Canadian operations are robust and active and requires continuing capital investment. Accordingly, as of December 31, 2015,2018, no income taxes should be accrued by Devon relative to its investment in its Canadian operations. In view of Devon’s unremitted foreign earnings from its other international operations totaled approximately $1.2 billion. All but $37 milliondecision in February 2019 to dispose of the $1.2 billion was deemed to beCanadian business, the indefinitely reinvested into the developmentassertion of APB 23 and growthany required accrual of Devon’s Canadian business. Therefore, Devon has not recognized a deferredincome tax liability for U.S. income taxes associated with such earnings. If such earnings werewill be reevaluated in 2019.
79
Table of Contents Index to be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate. Financial StatementsDEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) For the remaining $37 million of unremitted earnings deemed not to be indefinitely reinvested, Devon has recognized a $10 million deferred tax liability associated with such unremitted earnings as of December 31, 2015.
Unrecognized Tax Benefits The following table presents changes in Devon’s unrecognized tax benefits. | | | December 31, | | | | | 2015 | | | 2014 | | | December 31, | | | | (Millions) | | | 2018 | | | 2017 | | Balance at beginning of year | | $ | 241 | | | $ | 243 | | | $ | 115 | | | $ | 202 | | Tax positions taken in prior periods | | | (19 | ) | | | — | | | | (43 | ) | | | (7 | ) | Tax positions taken in current year | | | 31 | | | | — | | | | (2 | ) | | | (3 | ) | Accrual of interest related to tax positions taken | | | (5 | ) | | | 2 | | | | 3 | | | | 16 | | Settlements | | | (108 | ) | | | — | | | | — | | | | (101 | ) | Foreign currency translation | | | (9 | ) | | | (4 | ) | | | (3 | ) | | | 8 | | | | | | | | | | Balance at end of year | | $ | 131 | | | $ | 241 | | | $ | 70 | | | $ | 115 | | | | | | | | | |
Devon’s unrecognized tax benefit balance at December 31, 20152018 and 20142017 included $29$12 million and $34$28 million, respectively, of interest and penalties. If recognized, $131$70 million of Devon’s unrecognized tax benefits as of December 31, 20152018 would affect Devon’s effective income tax rate.During 2018, Devon removed $43 million of unrecognized tax benefits, including $20 million of interest, as a result of the closure of certain tax examinations. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities. | | | | | Jurisdiction | | Tax Years Open | | U.S. Federal | | | 2008-2015 | 2015-2018 | Various U.S. states | | | 2008-2015 | 2014-2018 | Canada Federal | | | 2003-2015 | 2004-2018 | Various Canadian provinces | | | 2003-2015 | 2004-2018 |
Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months. 80
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 8.9. | Net Earnings (Loss) Per Share Attributable to Devon from Continuing Operations |
The following table reconciles net earnings (loss) attributable to Devonfrom continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.share from continuing operations. | | | | | | | | Year Ended December 31, | | | | Year Ended December 31, | | | 2018 | | | 2017 | | | 2016 | | | | 2015 | | 2014 | | 2013 | | | | | (Millions, except per share amounts) | | | Net earnings (loss): | | | | | | | | Net earnings (loss) attributable to Devon | | $ | (14,454 | ) | | $ | 1,607 | | | $ | (20 | ) | | Net earnings (loss) from continuing operations: | | | | | | | | | | | | | | Net earnings (loss) from continuing operations | | | $ | 764 | | | $ | 758 | | | $ | (574 | ) | Attributable to participating securities | | | (5 | ) | | | (17 | ) | | | (2 | ) | | | (9 | ) | | | (8 | ) | | | (2 | ) | | | | | | | | | | | | Basic and diluted earnings (loss) | | $ | (14,459 | ) | | $ | 1,590 | | | $ | (22 | ) | | | | | | | | | | | | | Basic and diluted earnings (loss) from continuing operations | | | $ | 755 | | | $ | 750 | | | $ | (576 | ) | Common shares: | | | | | | | | | | | | | | | | | | | Common shares outstanding - total | | | 412 | | | | 409 | | | | 406 | | | | 499 | | | | 525 | | | | 513 | | Attributable to participating securities | | | (5 | ) | | | (4 | ) | | | (4 | ) | | | (5 | ) | | | (5 | ) | | | (6 | ) | | | | | | | | | | | | Common shares outstanding - basic | | | 407 | | | | 405 | | | | 402 | | | | 494 | | | | 520 | | | | 507 | | Dilutive effect of potential common shares issuable | | | — | | | | 2 | | | | — | | | | 3 | | | | 3 | | | | — | | | | | | | | | | | | | Common shares outstanding - diluted | | | 407 | | | | 407 | | | | 402 | | | | 497 | | | | 523 | | | | 507 | | | | | | | | | | | | | Net earnings (loss) per share attributable to Devon: | | | | | | | | Net earnings (loss) per share from continuing operations: | | | | | | | | | | | | | | Basic | | $ | (35.55 | ) | | $ | 3.93 | | | $ | (0.06 | ) | | $ | 1.53 | | | $ | 1.44 | | | $ | (1.14 | ) | Diluted | | $ | (35.55 | ) | | $ | 3.91 | | | $ | (0.06 | ) | | $ | 1.52 | | | $ | 1.43 | | | $ | (1.14 | ) | Antidilutive options (1) | | | 4 | | | | 3 | | | | 7 | | | | 1 | | | | 2 | | | | 3 | |
(1) | Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive. |
9.10. | Other Comprehensive Earnings |
Components of other comprehensive earnings consist of the following: | | | Year Ended December 31, | | | | | 2015 | | 2014 | | 2013 | | | Year Ended December 31, | | | | (Millions) | | | 2018 | | | 2017 | | | 2016 | | Foreign currency translation: | | | | | | | | | | | | | | | | | | | Beginning accumulated foreign currency translation | | $ | 983 | | | $ | 1,448 | | | $ | 1,996 | | | $ | 1,309 | | | $ | 1,226 | | | $ | 1,215 | | Change in cumulative translation adjustment | | | (621 | ) | | | (499 | ) | | | (574 | ) | | | (166 | ) | | | 113 | | | | 22 | | Income tax benefit | | | 62 | | | | 34 | | | | 26 | | | | | | | | | | | | | | Income tax benefit (expense) | | | | 14 | | | | (30 | ) | | | (11 | ) | Ending accumulated foreign currency translation | | | 424 | | | | 983 | | | | 1,448 | | | | 1,157 | | | | 1,309 | | | | 1,226 | | | | | | | | | | | | | Pension and postretirement benefit plans: | | | | | | | | | | | | | | | | | | | Beginning accumulated pension and postretirement benefits | | | (204 | ) | | | (180 | ) | | | (225 | ) | | | (143 | ) | | | (172 | ) | | | (194 | ) | Net actuarial gain (loss) and prior service cost arising in current year | | | (5 | ) | | | (57 | ) | | | 48 | | | Net actuarial loss and prior service cost arising in current year | | | | (3 | ) | | | 10 | | | | (28 | ) | Recognition of net actuarial loss and prior service cost in earnings (1) | | | 21 | | | | 20 | | | | 24 | | | | 12 | | | | 19 | | | | 26 | | Income tax benefit (expense) | | | (6 | ) | | | 13 | | | | (27 | ) | | | | | | | | | | | | | Curtailment and settlement of pension benefits | | | | 47 | | | | — | | | | 24 | | Income tax expense | | | | (12 | ) | | | — | | | | — | | Other (2) | | | | (33 | ) | | | — | | | | — | | Ending accumulated pension and postretirement benefits | | | (194 | ) | | | (204 | ) | | | (180 | ) | | | (132 | ) | | | (143 | ) | | | (172 | ) | | | | | | | | | | | | Other | | | | 2 | | | | — | | | | — | | Accumulated other comprehensive earnings, net of tax | | $ | 230 | | | $ | 779 | | | $ | 1,268 | | | $ | 1,027 | | | $ | 1,166 | | | $ | 1,054 | | | | | | | | | | | | |
(1) | These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A onother expenses in the accompanying consolidated comprehensive statements of earnings. See Note 1517 for additional details. |
81
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 10.(2) | As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33 million from accumulated other comprehensive income to retained earnings in the December 31, 2018 consolidated balance sheet. See Note 1 for additional details. |
11. | Supplemental Information to Statements of Cash Flows |
| | | | | | | | Year Ended December 31, | | | | Year Ended December 31, | | | 2018 | | | 2017 | | | 2016 | | | | 2015 | | | 2014 | | | 2013 | | | | | (Millions) | | | Net change in working capital accounts: | | | | | | | | Changes in assets and liabilities, net | | | | | | | | | | | | | | Accounts receivable | | $ | 942 | | | $ | 128 | | | $ | (288 | ) | | $ | 88 | | | $ | (94 | ) | | $ | (58 | ) | Income taxes receivable | | | 384 | | | | (467 | ) | | | 29 | | | Other current assets | | | (57 | ) | | | (222 | ) | | | 20 | | | | (128 | ) | | | 20 | | | | 326 | | Other long-term assets | | | | (28 | ) | | | (47 | ) | | | 36 | | Accounts payable | | | (190 | ) | | | (68 | ) | | | 26 | | | | — | | | | 113 | | | | (196 | ) | Revenues and royalties payable | | | (526 | ) | | | 133 | | | | 35 | | | | 153 | | | | 106 | | | | (26 | ) | Income taxes payable | | | (275 | ) | | | 30 | | | | — | | | Other current liabilities | | | (579 | ) | | | 516 | | | | (120 | ) | | | (150 | ) | | | (53 | ) | | | (74 | ) | | | | | | | | | | | | Net change in working capital | | $ | (301 | ) | | $ | 50 | | | $ | (298 | ) | | | | | | | | | | | | | Other long-term liabilities | | | | (78 | ) | | | (13 | ) | | | 16 | | Total | | | $ | (143 | ) | | $ | 32 | | | $ | 24 | | Supplementary cash flow data - total operations: | | | | | | | | | | | | | | Interest paid (net of capitalized interest) | | $ | 494 | | | $ | 514 | | | $ | 406 | | | $ | 385 | | | $ | 481 | | | $ | 569 | | Income taxes paid (received) | | $ | (279 | ) | | $ | 899 | | | $ | 13 | | | $ | 40 | | | $ | 78 | | | $ | (159 | ) |
On March 7, 2014, Devon completed a business combination to form EnLink. With the exception of a $100 million cash payment to noncontrolling interests, the business combination was a non-monetary transaction. EnLink’s noncash acquisition activity during 2015 included a portion of the Coronado transaction.
As discussed in Note 2,In 2016, Devon’s acquisition of certain Powder RiverSTACK assets included the noncash issuance of Devon common stock. See Note 2 for additional details. Further, in 2016, EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets included noncash issuance of General Partner common stock issuance totaling $199 million.units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions.
11.12. | Accounts Receivable |
Components of accounts receivable include the following: | | | December 31, 2015 | | | December 31, 2014 | | | | | (Millions) | | | December 31, 2018 | | | December 31, 2017 | | Oil, gas and NGL sales | | $ | 362 | | | $ | 723 | | | $ | 430 | | | $ | 559 | | Joint interest billings | | | 211 | | | | 475 | | | | 155 | | | | 134 | | Marketing and midstream revenues | | | 520 | | | | 706 | | | Marketing revenues | | | | 285 | | | | 278 | | Other | | | 30 | | | | 71 | | | | 23 | | | | 29 | | | | | | | | | | Gross accounts receivable | | | 1,123 | | | | 1,975 | | | | 893 | | | | 1,000 | | Allowance for doubtful accounts | | | (18 | ) | | | (16 | ) | | | (8 | ) | | | (11 | ) | | | | | | | | | Net accounts receivable | | $ | 1,105 | | | $ | 1,959 | | | $ | 885 | | | $ | 989 | | | | | | | | | |
82
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 12. | Goodwill and Other Intangible Assets |
Goodwill13.Property, Plant and Equipment
Capitalized Costs The following table presents a summary ofreflects the aggregate capitalized costs related to Devon’s goodwill.oil and gas and non-oil and gas activities. | | | | | | | | | | | | | | | | | | | U.S. | | | Canada | | | EnLink | | | Total | | | | (Millions) | | Balance as of December 31, 2013 | | $ | 2,618 | | | $ | 2,838 | | | $ | 402 | | | $ | 5,858 | | Acquired during period | | | — | | | | — | | | | 3,283 | | | | 3,283 | | Asset divestitures | | | — | | | | (706 | ) | | | — | | | | (706 | ) | Impairment | | | — | | | | (1,941 | ) | | | — | | | | (1,941 | ) | Foreign currency translation adjustments | | | — | | | | (191 | ) | | | — | | | | (191 | ) | | | | | | | | | | | | | | | | | | Balance as of December 31, 2014 | | $ | 2,618 | | | $ | — | | | $ | 3,685 | | | $ | 6,303 | | Acquired during period | | | — | | | | — | | | | 57 | | | | 57 | | Impairment | | | — | | | | — | | | | (1,328 | ) | | | (1,328 | ) | | | | | | | | | | | | | | | | | | Balance as of December 31, 2015 | | $ | 2,618 | | | $ | — | | | $ | 2,414 | | | $ | 5,032 | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 | | | | U.S. | | | Canada | | | Total | | Property and equipment: | | | | | | | | | | | | | Proved | | $ | 40,378 | | | $ | 6,427 | | | $ | 46,805 | | Unproved and properties under development | | | 833 | | | | 1,434 | | | | 2,267 | | Total oil and gas | | | 41,211 | | | | 7,861 | | | | 49,072 | | Less accumulated DD&A | | | (32,229 | ) | | | (4,030 | ) | | | (36,259 | ) | Oil and gas property and equipment, net | | $ | 8,982 | | | $ | 3,831 | | | $ | 12,813 | | Other property and equipment | | | | | | | | | | | 1,832 | | Less accumulated DD&A | | | | | | | | | | | (710 | ) | Other property and equipment, net | | | | | | | | | | | 1,122 | | Property and equipment, net | | | | | | | | | | $ | 13,935 | | | | | | | | | | | | | | | | | December 31, 2017 | | | | U.S. | | | Canada | | | Total | | Property and equipment: | | | | | | | | | | | | | Proved | | $ | 40,491 | | | $ | 6,804 | | | $ | 47,295 | | Unproved and properties under development | | | 984 | | | | 1,473 | | | | 2,457 | | Total oil and gas | | | 41,475 | | | | 8,277 | | | | 49,752 | | Less accumulated DD&A | | | (32,379 | ) | | | (4,055 | ) | | | (36,434 | ) | Oil and gas property and equipment, net | | $ | 9,096 | | | $ | 4,222 | | | $ | 13,318 | | Other property and equipment | | | | | | | | | | | 1,955 | | Less accumulated DD&A | | | | | | | | | | | (689 | ) | Other property and equipment, net | | | | | | | | | | | 1,266 | | Property and equipment, net | | | | | | | | | | $ | 14,584 | |
Suspended Exploratory Well Costs The following table presentssummarizes the General Partner’s and EnLink’s goodwill activity by reporting unit.changes in suspended exploratory well costs for the three years ended December 31, 2018. | | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Beginning balance | | $ | 313 | | | $ | 261 | | | $ | 225 | | Additions pending determination of proved reserves | | | 672 | | | | 504 | | | | 247 | | Charges to exploration expense | | | — | | | | — | | | | (29 | ) | Reclassifications to proved properties | | | (662 | ) | | | (466 | ) | | | (189 | ) | Foreign currency translation adjustment | | | (19 | ) | | | 14 | | | | 7 | | Ending balance | | $ | 304 | | | $ | 313 | | | $ | 261 | |
83
Table of Contents | | | | | | | | | | | | | | | | | | | | | | | | | | | Texas | | | Louisiana | | | Oklahoma | | | Crude and Condensate | | | General Partner | | | Total | | | | (Millions) | | Balance as of December 31, 2013 | | $ | 326 | | | $ | — | | | $ | 76 | | | $ | — | | | $ | — | | | $ | 402 | | Acquired during period | | | 842 | | | | 787 | | | | 114 | | | | 113 | | | | 1,427 | | | | 3,283 | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2014 | | $ | 1,168 | | | $ | 787 | | | $ | 190 | | | $ | 113 | | | $ | 1,427 | | | $ | 3,685 | | Acquired during period | | | 28 | | | | — | | | | — | | | | 29 | | | | — | | | | 57 | | Impairment | | | (492 | ) | | | (787 | ) | | | — | | | | (49 | ) | | | — | | | | (1,328 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Balance as of December 31, 2015 | | $ | 704 | | | $ | — | | | $ | 190 | | | $ | 93 | | | $ | 1,427 | | | $ | 2,414 | | | | | | | | | | | | | | | | | | | | | | | | | | |
Acquired During PeriodIndex to Financial Statements
Included in the assets Devon contributed to EMH was $402 million of goodwill. See Note 2 for discussion of acquired goodwill resulting from EnLink’s formation in 2014 and acquisitions in 2015.
Asset Divestitures
In conjunction with the Canadian conventional asset divestitures in 2014, Devon removed $706 million of goodwill, which was allocated to these assets.
Impairment
As further discussed in Note 1, Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units. Furthermore, due to the continued impact of declining commodity prices and EnLink unit price, an update was performed as of December 31, 2015. As a result of these tests, noncash goodwill impairments were recorded related to EnLink’s Texas, Louisiana and Crude and Condensate reporting units in 2015.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) In the fourth quarter of 2014, as a result of its annual impairment test of goodwill, Devon concluded the implied fair value of its Canadian goodwill was zero and wrote off the remaining goodwill. This conclusion was largely based on the significant decline in benchmark oil prices, particularly after OPEC’s decision not to reduce its production targets that was announced in late November 2014. Devon’s Canadian goodwill was originally recognized in 2001 as a result of a business combination consisting almost entirely of conventional gas assets that Devon no longer owns.
Other Intangible Assets
During 2015, EnLink’s customer relationships were also evaluated for impairment due to the factors in the aforementioned goodwill impairment analysis. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment. This assessment resulted in a $223 million noncash impairment related to EnLink’s Crude and Condensate customer relationships in 2015.
The following table presents other intangible assets reported in other long-term assetsprovides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. | | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Exploratory well costs capitalized for a period of one year or less | | $ | 110 | | | $ | 113 | | | $ | 88 | | Exploratory well costs capitalized for a period greater than one year | | | 194 | | | | 200 | | | | 173 | | Ending balance | | $ | 304 | | | $ | 313 | | | $ | 261 | | Number of projects with exploratory well costs capitalized for a period greater than one year | | | 2 | | | | 2 | | | | 2 | |
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling relate to Devon’s heavy oil operations. Management believes these projects with suspended exploratory well costs exhibit sufficient quantities of hydrocarbons to justify potential development. Currently, Devon has not planned additional exploratory work in the accompanying consolidated balance sheets.near future on these assets and will continue to assess its future development timeline of these long cycle projects as it competes for capital allocation within Devon’s portfolio. Devon’s interest in this acreage does not begin to expire until 2025. | | | | | | | | | | | December 31, 2015 | | | December 31, 2014 | | | | (Millions) | | Customer relationships | | $ | 745 | | | $ | 569 | | Accumulated amortization | | | (55 | ) | | | (36 | ) | | | | | | | | | | Net intangibles | | $ | 690 | | | $ | 533 | | | | | | | | | | |
14. | Other Current Liabilities |
The weighted-average amortization period forComponents of other current liabilities include the customer relationships is 12.6 years. Amortization expense for intangibles was approximately $56 million and $36 million for the years ended December 31, 2015 and December 31, 2014, respectively. The remaining aggregate amortization expense is estimatedfollowing:
| December 31, 2018 | | | December 31, 2017 | | Derivative liabilities | $ | 67 | | | $ | 323 | | Accrued interest payable | | 80 | | | | 96 | | Income taxes payable | | 14 | | | | 144 | | Restructuring liabilities | | 47 | | | | 19 | | Other | | 227 | | | | 246 | | Other current liabilities | $ | 435 | | | $ | 828 | |
84
Table of Contents Index to be approximately $46 million each of the next five years. Financial StatementsDEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 13.15. | Debt and Related Expenses |
ASee below for a summary of debt is as follows:instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.
| | | | | | | | | | | December 31, 2015 | | | December 31, 2014 | | | | (Millions) | | Devon debt | | | | | | | | | Commercial paper | | $ | 626 | | | $ | 932 | | Floating rate due December 15, 2015 | | | — | | | | 500 | | Floating rate due December 15, 2016 | | | 350 | | | | 350 | | 8.25% due July 1, 2018 | | | 125 | | | | 125 | | 2.25% due December 15, 2018 | | | 750 | | | | 750 | | 6.30% due January 15, 2019 | | | 700 | | | | 700 | | 4.00% due July 15, 2021 | | | 500 | | | | 500 | | 3.25% due May 15, 2022 | | | 1,000 | | | | 1,000 | | 5.85% due December 15, 2025 | | | 850 | | | | — | | 7.50% due September 15, 2027 | | | 150 | | | | 150 | | 7.875% due September 30, 2031 | | | 1,250 | | | | 1,250 | | 7.95% due April 15, 2032 | | | 1,000 | | | | 1,000 | | 5.60% due July 15, 2041 | | | 1,250 | | | | 1,250 | | 4.75% due May 15, 2042 | | | 750 | | | | 750 | | 5.00% due June 15, 2045 | | | 750 | | | | — | | Net discount on debentures and notes | | | (28 | ) | | | (18 | ) | | | | | | | | | | Total Devon debt | | | 10,023 | | | | 9,239 | | | | | | | | | | | EnLink debt | | | | | | | | | Credit facilities | | | 414 | | | | 237 | | 2.70% due April 1, 2019 | | | 400 | | | | 400 | | 7.125% due June 1, 2022 | | | 163 | | | | 163 | | 4.40% due April 1, 2024 | | | 550 | | | | 550 | | 4.15% due June 1, 2025 | | | 750 | | | | — | | 5.60% due April 1, 2044 | | | 350 | | | | 350 | | 5.05% due April 1, 2045 | | | 450 | | | | 300 | | Net premium on debentures and notes | | | 13 | | | | 23 | | | | | | | | | | | Total EnLink debt | | | 3,090 | | | | 2,023 | | | | | | | | | | | Total debt | | | 13,113 | | | | 11,262 | | Less amount classified as short-term debt (1) | | | 976 | | | | 1,432 | | | | | | | | | | | Total long-term debt | | $ | 12,137 | | | $ | 9,830 | | | | | | | | | | |
| | December 31, 2018 | | | December 31, 2017 | | 8.25% due July 1, 2018 (1) | | $ | — | | | $ | 20 | | 2.25% due December 15, 2018 | | | — | | | | 95 | | 6.30% due January 15, 2019 | | | 162 | | | | 162 | | 4.00% due July 15, 2021 | | | 500 | | | | 500 | | 3.25% due May 15, 2022 | | | 1,000 | | | | 1,000 | | 5.85% due December 15, 2025 | | | 485 | | | | 485 | | 7.50% due September 15, 2027 (1) | | | 73 | | | | 73 | | 7.875% due September 30, 2031 (2) (3) | | | 675 | | | | 1,059 | | 7.95% due April 15, 2032 (2) | | | 366 | | | | 789 | | 5.60% due July 15, 2041 | | | 1,250 | | | | 1,250 | | 4.75% due May 15, 2042 | | | 750 | | | | 750 | | 5.00% due June 15, 2045 | | | 750 | | | | 750 | | Net discount on debentures and notes | | | (24 | ) | | | (30 | ) | Debt issuance costs | | | (40 | ) | | | (39 | ) | Total debt | | | 5,947 | | | | 6,864 | | Less amount classified as short-term debt (4) | | | 162 | | | | 115 | | Total long-term debt | | $ | 5,785 | | | $ | 6,749 | |
(1) | 2015These instruments were assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The fair value and effective rates of these 8.25% notes and 7.50% notes at the time assumed was $147 million and 5.5%, respectively, and $169 million and 6.5%, respectively.These instruments are the unsecured and unsubordinated obligations of Devon OEI Operating, L.L.C. and are guaranteed by Devon Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon. |
(2) | These senior notes were included in 2018 tender offer repurchases discussed below. |
(3) | Issued in October 2001, these are the unsecured and unsubordinated obligations of Devon Financing, a wholly owned subsidiary of Devon. These instruments are fully and unconditionally guaranteed by Devon. |
(4) | 2018 short-term debt consists of $626$162 million of commercial paper and the $350 million floating rate6.30% senior notes due on DecemberJanuary 15, 2016. 2014 short-term debt consists of $932 million of commercial paper and $500 million floating rate due on December 15, 2015.2019. |
Debt maturities as of December 31, 2018, excluding debt issuance costs, premiums and discounts, are as follows: | | Total | | 2019 | | $ | 162 | | 2020 | | | — | | 2021 | | | 500 | | 2022 | | | 1,000 | | 2023 | | | — | | Thereafter | | | 4,349 | | Total | | $ | 6,011 | |
85
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Debt maturities asCredit Lines
Under its 2012 Senior Credit Facility, Devon had $3.0 billion of December 31, 2015, excluding premiumsavailable credit. On October 5, 2018, Devon terminated its 2012 Senior Credit Facility and discounts, are as follows (millions): | | | | | 2016 | | $ | 976 | | 2017 | | | — | | 2018 | | | 875 | | 2019 | | | 1,100 | | 2020 | | | 414 | | Thereafter | | | 9,763 | | | | | | | Total | | $ | 13,128 | | | | | | |
Credit Lines
Devon has asubsequently entered into its new $3.0 billion revolving 2018 Senior Credit Facility. The maturity date for $30 million of the2018 Senior Credit Facility ismatures on October 24, 2017. The5, 2023, with the option to extend the maturity date for $164 million of the Senior Credit Facility is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019.by two additional one-year periods subject to lender consent. Amounts borrowed under the 2018 Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The 2018 Senior Credit Facility currently provides for an annual facility fee of $3.8 million that is payable quarterly in arrears.$6.1 million. As of December 31, 2015, there2018, Devon had $48 million in outstanding letters of credit under the 2018 Senior Credit Facility. There were no borrowings under the Senior Credit Facility.Facility as of December 31, 2018.
The 2018 Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated financial statements. Also,For example, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwillasset impairments. As of December 31, 2015,2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.7%21.0%. Commercial Paper Devon’s 2018 Senior Credit Facility supports its $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the commercial paper market. As of December 31, 2015, Devon’s2018, Devon had no outstanding commercial paper borrowings had a weighted-average borrowing rate of 0.63%.borrowings. IssuanceRetirement of Senior Notes
In June 2015,During 2018, Devon issued $750completed tender offers to repurchase $807 million in aggregate principal amount of debt using cash on hand. This included $384 million of 5.0%the 7.875% senior notes due 2045 that are unsecuredSeptember 30, 2031 and unsubordinated obligations. Devon used the net proceeds to repay the floating rate senior notes that matured on December 15, 2015, as well as outstanding commercial paper balances.
In December 2015, in conjunction with the announcement$423 million of the Powder River Basin and STACK acquisitions, Devon issued $850 million of 5.85%7.95% senior notes due 2025 thatApril 15, 2032. Devon recognized a $312 million loss on early retirement of debt, consisting of $304 million in cash retirement costs and $8 million of noncash charges. These costs, along with other charges associated with retiring the debt, are unsecuredincluded in net financing costs in the consolidated comprehensive statements of earnings. In December 2018, Devon repaid the $95 million of 2.25% senior notes at maturity. Additionally, in January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity.
During 2016, Devon completed tender offers to repurchase $2.1 billion of debt securities, using proceeds from the asset divestitures discussed in Note 2. Devon recognized a loss on early retirement of debt, primarily consisting of $265 million in cash retirement costs and unsubordinated obligations. Devon usedother fees. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net proceedsfinancing costs in the consolidated comprehensive statements of earnings. 86
Table of Contents Index to fund the cash portion of these acquisitions. Financial StatementsDEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Retirement of Senior Notes
In November 2014, Devon redeemed $1.9 billion of senior notes prior to their scheduled maturity, primarily with proceeds received from its asset divestitures. The redemption includes the 2.4% $500 million senior notes due 2016, the 1.2% $650 million senior notes due 2016 and the 1.875% $750 million senior notes due 2017. The notes were redeemed for $1.9 billion, which included 100% of the principal amount and a make-whole premium of $40 million. On the date of redemption, these notes also had an unamortized discount of $2 million and unamortized debt issuance costs of $6 million. The make-whole premium, unamortized discounts and debt issuance costs are included in net financing costs on the accompanying 2014 consolidated comprehensive statement of earnings.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2015 and 2014, as listed in the table presented at the beginning of this note.
GeoSouthern Debt
In December 2013, in conjunction with the planned GeoSouthern acquisition, Devon issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes. Devon repaid the floating rate senior notes due 2015 upon maturity and redeemed the 1.2% senior notes due December 15, 2016 in November 2014. As of December 31, 2015, the floating rate senior notes due 2016 and the 2.25% senior notes due December 15, 2018 were outstanding. The floating rate senior notes due 2016 bear interest at a rate equal to three-month LIBOR plus 0.54%, which will be reset quarterly.
Other Notes
In 2012, 2011, 2009 and 2002, Devon issued senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper, credit facility borrowings and other long-term debt. The schedule below summarizes the key terms of these notes (millions).
| | | | | | | | | | | | | | | | | | | Date Issued | | | | May 2012 | | | July 2011 | | | January 2009 | | | March 2002 | | 3.25% due May 15, 2022 | | $ | 1,000 | | | $ | — | | | $ | — | | | $ | — | | 4.75% due May 15, 2042 | | | 750 | | | | — | | | | — | | | | — | | 4.00% due July 15, 2021 | | | — | | | | 500 | | | | — | | | | — | | 5.60% due July 15, 2041 | | | — | | | | 1,250 | | | | — | | | | — | | 6.30% due January 15, 2019 | | | — | | | | — | | | | 700 | | | | — | | 7.95% due April 15, 2032 | | | — | | | | — | | | | — | | | | 1,000 | | Discount and issuance costs | | | (28 | ) | | | (24 | ) | | | (8 | ) | | | (14 | ) | | | | | | | | | | | | | | | | | | Net proceeds | | $ | 1,722 | | | $ | 1,726 | | | $ | 692 | | | $ | 986 | | | | | | | | | | | | | | | | | | |
Ocean Debt
On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2015, including the fair value of the debt at April 25, 2003 and the effective interest rate of the debt after determining the fair values using
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
April 25, 2003 market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.
| | | | | | | | | | | Fair Value of Debt Assumed | | | Effective Rate of Debt Assumed | | Debt Assumed | | (Millions) | | | | | 8.25% due July 2018 (principal of $125 million) | | $ | 147 | | | | 5.5 | % | 7.50% due September 2027 (principal of $150 million) | | $ | 169 | | | | 6.5 | % |
7.875% Debentures due September 30, 2031
In October 2001, Devon, through Devon Financing, a wholly owned finance subsidiary, sold debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed, on an unsecured and unsubordinated basis, the obligations of Devon Financing under the debt securities. The proceeds were used to fund a portion of the Anderson Exploration acquisition.
EnLink Debt
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
The table below summarizes the fair value of EnLink’s debt as of March 7, 2014, the formation date of EnLink. The premiums are being amortized using the effective interest method.
| | | | | | | | | | | March 7, 2014 Fair Value of Debt | | | Effective Rate of Debt | | | | (Millions) | | | | | 8.875% due February 2018 (principal of $725 million)(1) | | $ | 760 | | | | 7.7 | % | 7.125% due June 2022 (principal of $197 million) | | | 226 | | | | 5.3 | % | Credit facilities | | | 468 | | | | | | | | | | | | | | | Total long-term debt | | $ | 1,454 | | | | | | | | | | | | | | |
(1) | The 2018 senior notes were redeemed on April 18, 2014. |
In February 2015, the commitments under EnLink’s $1.0 billion unsecured revolving credit facility were increased to $1.5 billion, and the maturity date was extended by a year to March 6, 2020. As of December 31, 2015, there were $11 million in outstanding letters of credit and $414 million outstanding borrowings, with a weighted-average borrowing rate of 1.7%, under the $1.5 billion credit facility. The General Partner has a $250 million revolving credit facility that will mature on March 7, 2019. As of December 31, 2015, the General Partner had no outstanding borrowings under the $250 million credit facility. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2015.
In March 2014, EnLink issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400 million of its 2.70% senior notes due 2019, $450 million of its 4.40% senior notes due 2024 and $350 million of its 5.60% senior notes due 2044, at discounts of their face value. EnLink used the net proceeds to redeem the 2018 senior notes, reduce outstanding credit facility borrowings, for capital expenditures and for general operations.
In November 2014, EnLink issued $100 million of its 4.40% senior notes due 2024 and $300 million of its 5.05% senior notes due 2045, at a premium and discount, respectively, of their face value. The 2024 notes were
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
offered as an additional issue of EnLink’s outstanding 4.40% senior notes due 2024, issued in March 2014. The 2024 notes issued in March 2014 and November 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. EnLink used the net proceeds for capital expenditures and for general operations.
In May 2015, EnLink issued $900 million principal amount of unsecured senior notes, consisting of $750 million principal amount of its 4.15% senior notes due 2025 and an additional $150 million principal amount of its 5.05% senior notes due 2045. EnLink used the net proceeds to repay outstanding revolving credit facility borrowings, for capital expenditures and for general operations.
Net Financing Costs, Net
The following schedule includes the components of net financing costs. | | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | Interest based on debt outstanding | | $ | 565 | | | $ | 532 | | | $ | 466 | | Early retirement of debt | | | — | | | | 48 | | | | — | | Capitalized interest | | | (62 | ) | | | (70 | ) | | | (56 | ) | Other fees and expenses | | | 20 | | | | 26 | | | | 27 | | | | | | | | | | | | | | | Interest expense | | | 523 | | | | 536 | | | | 437 | | Interest income | | | (6 | ) | | | (10 | ) | | | (20 | ) | | | | | | | | | | | | | | Net financing costs | | $ | 517 | | | $ | 526 | | | $ | 417 | | | | | | | | | | | | | | |
| | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Interest based on debt outstanding | | $ | 339 | | | $ | 390 | | | $ | 488 | | Early retirement of debt | | | 312 | | | | — | | | | 269 | | Capitalized interest | | | (41 | ) | | | (69 | ) | | | (61 | ) | Other | | | (16 | ) | | | (4 | ) | | | 21 | | Total net financing costs | | $ | 594 | | | $ | 317 | | | $ | 717 | |
14.16. | Asset Retirement Obligations |
The following table presents the changes in asset retirement obligations. | | | Year Ended December 31, | | | | | 2015 | | | 2014 | | | Year Ended December 31, | | | | (Millions) | | | 2018 | | | 2017 | | Asset retirement obligations as of beginning of period | | $ | 1,399 | | | $ | 2,228 | | | $ | 1,138 | | | $ | 1,258 | | Liabilities incurred | | | 63 | | | | 97 | | | | 39 | | | | 40 | | Liabilities settled and divested(1) | | | (89 | ) | | | (1,009 | ) | | Liabilities settled and divested | | | | (116 | ) | | | (68 | ) | Revision of estimated obligation | | | 62 | | | | 70 | | | | (25 | ) | | | (184 | ) | Accretion expense on discounted obligation | | | 75 | | | | 89 | | | | 59 | | | | 62 | | Foreign currency translation adjustment | | | (96 | ) | | | (76 | ) | | | (38 | ) | | | 30 | | | | | | | | | | Asset retirement obligations as of end of period | | | 1,414 | | | | 1,399 | | | | 1,057 | | | | 1,138 | | Less current portion | | | 44 | | | | 60 | | | | 27 | | | | 39 | | | | | | | | | | Asset retirement obligations, long-term | | $ | 1,370 | | | $ | 1,339 | | | $ | 1,030 | | | $ | 1,099 | | | | | | | | | |
During 2018, Devon reduced its asset retirement obligation by $84 million, primarily as a result of Devon’s 2018 divestitures. For additional information, see Note 2. During 2017, Devon reduced its asset retirement obligations by $184 million, primarily due to changes in the assumed inflation rate and retirement dates for its oil and gas assets. (1)17. | During 2014, Devon reduced its asset retirement obligation by $953 million for those obligations that were assumed by purchasers of Devon’s Canadian and U.S. divested oil and gas properties.Retirement Plans |
Defined Contribution Plans Devon sponsors defined contribution plans covering its employees in the U.S. and Canada. Such plans include its 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. Devon contributed $50 million, $53 million and $57 million to these plans in 2018, 2017 and 2016, respectively. 87
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Defined Benefit Plans Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans. The qualified plans provide retirement benefits for certaincovering eligible U.S. and Canadian employees and former employees meeting certain age and service requirements. Benefits forunder the qualifieddefined benefit plans arehave been closed to new employees; however, eligible employees continue to accrue benefits based on the employees’upon years of service and compensation andcompensation. Benefits are primarily funded from assets held in the plans’ trusts. The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans’ benefits are based on the employees’ years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans’ benefit obligations. The total value of these trusts was $22 million and $25 million at December 31, 2015 and 2014, respectively and is included in other long-term assets in the accompanying consolidated balance sheets. For the remaining nonqualified plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.
Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. The plans provide medical and, in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Benefit Obligations and Funded Status
The following table presents the funded status of Devon’s qualified and nonqualified pension and postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans was $1.2 billion at December 31, 2015 and 2014. Devon’s benefit obligations and plan assets are measured each year as of December 31. The projected benefit obligations for Devon’s qualified plans were fully funded as of December 31, 2015 and 2014.
| | | | | | | | | | | | | | | | | | | Pension Benefits | | | Postretirement Benefits | | | | 2015 | | | 2014 | | | 2015 | | | 2014 | | | | (Millions) | | Change in benefit obligation: | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | 1,377 | | | $ | 1,177 | | | $ | 24 | | | $ | 24 | | Service cost | | | 33 | | | | 30 | | | | 1 | | | | 1 | | Interest cost | | | 52 | | | | 55 | | | | 1 | | | | 1 | | Actuarial loss (gain) | | | (68 | ) | | | 203 | | | | (2 | ) | | | — | | Plan amendments | | | — | | | | — | | | | 1 | | | | — | | Plan settlements | | | — | | | | (4 | ) | | | — | | | | — | | Foreign exchange rate changes | | | (6 | ) | | | (3 | ) | | | — | | | | — | | Participant contributions | | | — | | | | — | | | | 2 | | | | 2 | | Benefits paid | | | (80 | ) | | | (81 | ) | | | (4 | ) | | | (4 | ) | | | | | | | | | | | | | | | | | | Benefit obligation at end of year | | | 1,308 | | | | 1,377 | | | | 23 | | | | 24 | | | | | | | | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | | 1,149 | | | | 1,006 | | | | — | | | | — | | Actual return on plan assets | | | (16 | ) | | | 200 | | | | — | | | | — | | Employer contributions | | | 11 | | | | 29 | | | | 2 | | | | 2 | | Participant contributions | | | — | | | | — | | | | 2 | | | | 2 | | Plan settlements | | | — | | | | (4 | ) | | | — | | | | — | | Benefits paid | | | (80 | ) | | | (81 | ) | | | (4 | ) | | | (4 | ) | Foreign exchange rate changes | | | (5 | ) | | | (1 | ) | | | — | | | | — | | | | | | | | | | | | | | | | | | | Fair value of plan assets at end of year | | | 1,059 | | | | 1,149 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | Funded status at end of year | | $ | (249 | ) | | $ | (228 | ) | | $ | (23 | ) | | $ | (24 | ) | | | | | | | | | | | | | | | | | | Amounts recognized in balance sheet: | | | | | | | | | | | | | | | | | Other long-term assets | | $ | 2 | | | $ | 22 | | | $ | — | | | $ | — | | Other current liabilities | | | (12 | ) | | | (10 | ) | | | (3 | ) | | | (3 | ) | Other long-term liabilities | | | (239 | ) | | | (240 | ) | | | (20 | ) | | | (21 | ) | | | | | | | | | | | | | | | | | | Net amount | | $ | (249 | ) | | $ | (228 | ) | | $ | (23 | ) | | $ | (24 | ) | | | | | | | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive earnings: | | | | | | | | | | | | | | | | | Net actuarial loss (gain) | | $ | 302 | | | $ | 317 | | | $ | (11 | ) | | $ | (11 | ) | Prior service cost (credit) | | | 14 | | | | 19 | | | | (6 | ) | | | (9 | ) | | | | | | | | | | | | | | | | | | Total | | $ | 316 | | | $ | 336 | | | $ | (17 | ) | | $ | (20 | ) | | | | | | | | | | | | | | | | | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $11 million and $10 million for 2015 and 2014, respectively, which were transferred from the trusts established for the nonqualified plans.
Certain of Devon’s pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2015 and 2014, as presented in the following table.
| | | | | | | | | | | December 31, | | | | 2015 | | | 2014 | | | | (Millions) | | Projected benefit obligation | | $ | 244 | | | $ | 250 | | Accumulated benefit obligation | | $ | 199 | | | $ | 191 | | Fair value of plan assets | | $ | — | | | $ | — | |
Net Periodic Benefit Cost and Other Comprehensive Earnings
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
| | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Postretirement Benefits | | | | 2015 | | | 2014 | | | 2013 | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | Net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Service cost | | $ | 33 | | | $ | 30 | | | $ | 36 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | Interest cost | | | 52 | | | | 55 | | | | 51 | | | | 1 | | | | 1 | | | | 1 | | Expected return on plan assets | | | (58 | ) | | | (54 | ) | | | (62 | ) | | | — | | | | — | | | | — | | Curtailment and settlement expense | | | — | | | | 1 | | | | — | | | | — | | | | — | | | | — | | Recognition of net actuarial loss (gain)(1) | | | 20 | | | | 18 | | | | 22 | | | | (1 | ) | | | (1 | ) | | | (1 | ) | Recognition of prior service cost(1) | | | 4 | | | | 4 | | | | 4 | | | | (2 | ) | | | (2 | ) | | | (1 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Total net periodic benefit cost(2) | | | 51 | | | | 54 | | | | 51 | | | | (1 | ) | | | (1 | ) | | | — | | Other comprehensive loss (earnings): | | | | | | | | | | | | | | | | | | | | | | | | | Actuarial loss (gain) arising in current year | | | 5 | | | | 57 | | | | (39 | ) | | | (1 | ) | | | — | | | | (3 | ) | Prior service cost (credit) arising in current year | | | — | | | | — | | | | 2 | | | | 1 | | | | — | | | | (8 | ) | Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost | | | (20 | ) | | | (19 | ) | | | (22 | ) | | | 1 | | | | 1 | | | | 1 | | Recognition of prior service cost, including curtailment, in net periodic benefit cost | | | (4 | ) | | | (4 | ) | | | (4 | ) | | | 1 | | | | 2 | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | Total other comprehensive loss (earnings) | | | (19 | ) | | | 34 | | | | (63 | ) | | | 2 | | | | 3 | | | | (9 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Total recognized | | $ | 32 | | | $ | 88 | | | $ | (12 | ) | | $ | 1 | | | $ | 2 | | | $ | (9 | ) | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) | These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. |
(2) | Net periodic benefit cost is a component of G&A on the accompanying consolidated comprehensive statements of earnings. |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2016.
| | | | | | | | | | | Pension Benefits | | | Postretirement Benefits | | | | (Millions) | | Net actuarial loss (gain) | | $ | 22 | | | $ | (2 | ) | Prior service cost (credit) | | | 4 | | | | (1 | ) | | | | | | | | | | Total | | $ | 26 | | | $ | (3 | ) | | | | | | | | | |
Assumptions
The following table presents the weighted-average actuarial assumptions used to determine obligations and periodic costs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Postretirement Benefits | | | | 2015 | | | 2014 | | | 2013 | | | 2015 | | | 2014 | | | 2013 | | Assumptions to determine benefit obligations: | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | | 4.25 | % | | | 3.90 | % | | | 4.80 | % | | | 3.63 | % | | | 3.25 | % | | | 3.65 | % | Rate of compensation increase | | | 4.49 | % | | | 4.49 | % | | | 4.48 | % | | | N/A | | | | N/A | | | | N/A | | Assumptions to determine net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | | 3.90 | % | | | 4.80 | % | | | 3.85 | % | | | 3.25 | % | | | 3.65 | % | | | 3.30 | % | Rate of compensation increase | | | 4.49 | % | | | 4.49 | % | | | 4.48 | % | | | N/A | | | | N/A | | | | N/A | | Expected return on plan assets | | | 5.22 | % | | | 5.42 | % | | | 5.48 | % | | | N/A | | | | N/A | | | | N/A | |
Discount rate – Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.
At the end of 2015, Devon changed the approach used to measure service and interest costs for pension and other postretirement benefits. For 2015, Devon measured service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016, Devon elected to measure service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. Devon believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations nor the funded status of the plans. The change in the service and interest costs going forward is not expected to be significant. This change has been accounted for as a change in accounting estimate.
Rate of compensation increase – For measurement of the 2015 benefit obligation for the pension plans, a 4.49% compensation increase was assumed.
Expected return on plan assets – The expected rate of return on plan assets was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types. See the pension plan assets section below for more information on Devon’s target allocations.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Mortality rate assumptions – In 2014, the Society of Actuaries issued updated versions of its mortality tables and mortality improvement scale, reflecting the increasing life expectancies in the U.S. While not required to strictly adhere to this data, Devon utilized actuary-produced mortality tables and an improvement scale derived from the updated tables and the actuary’s best estimate of mortality for the population of participants in Devon’s plans.
Other assumptions – For measurement of the 2015 benefit obligation for the other postretirement medical plans, a 7.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2015 by less than $1 million and would change the 2015 service and interest cost components of net periodic benefit cost by less than $1 million.
Pension Plan Assets
Devon’s overall investment objective for its pension plans’ assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon’s target allocationallocations for its pension plan assets. | | | | | | | | | | | December 31, | | | | 2015 | | | 2014 | | Fixed income | | | 70 | % | | | 70 | % | Equity | | | 20 | % | | | 20 | % | Other | | | 10 | % | | | 10 | % |
Theassets are 70% fixed income, 20% equity and 10% other. See the following tables present the fair values ofdiscussion for Devon’s pension assets by asset class.
| | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | | | | | | | | | Fair Value Measurements Using: | | | | Actual Allocation | | | Total | | | Level 1 Inputs | | | Level 2 Inputs | | | Level 3 Inputs | | | | (Millions) | | Fixed-income securities: | | | | | | | | | | | | | | | | | | | | | U.S. Treasury obligations | | | 17 | % | | $ | 179 | | | $ | 88 | | | $ | 91 | | | $ | — | | Corporate bonds | | | 48 | % | | | 507 | | | | 371 | | | | 136 | | | | — | | Other bonds | | | 3 | % | | | 35 | | | | 35 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | Total fixed-income securities | | | 68 | % | | | 721 | | | | 494 | | | | 227 | | | | — | | | | | | | | | | | | | | | | | | | | | | | Equity securities: | | | | | | | | | | | | | | | | | | | | | Global (large, mid, small cap) | | | 18 | % | | | 186 | | | | — | | | | 186 | | | | — | | | | | | | | | | | | | | | | | | | | | | | Other securities: | | | | | | | | | | | | | | | | | | | | | Hedge fund and alternative investments | | | 11 | % | | | 120 | | | | — | | | | — | | | | 120 | | Short-term investments | | | 3 | % | | | 32 | | | | 6 | | | | 26 | | | | — | | | | | | | | | | | | | | | | | | | | | | | Total other securities | | | 14 | % | | | 152 | | | | 6 | | | | 26 | | | | 120 | | | | | | | | | | | | | | | | | | | | | | | Total investments | | | 100 | % | | $ | 1,059 | | | $ | 500 | | | $ | 439 | | | $ | 120 | | | | | | | | | | | | | | | | | | | | | | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | | | | | | | | Fair Value Measurements Using: | | | | Actual Allocation | | | Total | | | Level 1 Inputs | | | Level 2 Inputs | | | Level 3 Inputs | | | | (Millions) | | Fixed-income securities: | | | | | | | | | | | | | | | | | | | | | U.S. Treasury obligations | | | 35 | % | | $ | 405 | | | $ | 50 | | | $ | 355 | | | $ | — | | Corporate bonds | | | 32 | % | | | 364 | | | | 269 | | | | 95 | | | | — | | Other bonds | | | 3 | % | | | 30 | | | | 30 | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | Total fixed-income securities | | | 70 | % | | | 799 | | | | 349 | | | | 450 | | | | — | | | | | | | | | | | | | | | | | | | | | | | Equity securities: | | | | | | | | | | | | | | | | | | | | | Global (large, mid, small cap) | | | 17 | % | | | 197 | | | | — | | | | 197 | | | | — | | | | | | | | | | | | | | | | | | | | | | | Other securities: | | | | | | | | | | | | | | | | | | | | | Hedge fund and alternative investments | | | 10 | % | | | 112 | | | | — | | | | — | | | | 112 | | Short-term investments | | | 3 | % | | | 41 | | | | 15 | | | | 26 | | | | — | | | | | | | | | | | | | | | | | | | | | | | Total other securities | | | 13 | % | | | 153 | | | | 15 | | | | 26 | | | | 112 | | | | | | | | | | | | | | | | | | | | | | | Total investments | | | 100 | % | | $ | 1,149 | | | $ | 364 | | | $ | 673 | | | $ | 112 | | | | | | | | | | | | | | | | | | | | | | |
The following methods and assumptions were used to estimate the fair values in the tables above.
Fixed-income securities – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices. Devon’s fixed income securities also includeprices and were $193 million and $342 million at December 31, 2018 and 2017, respectively. Also, included are commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.managers and were $301 million and $401 million at December 31, 2018 and 2017, respectively.
Equity securities– Devon’s equity securities include a commingled global equity fundfunds that investsinvest in large, mid and small capitalization stocks across the world’s developed and emerging markets.markets and international large cap equity securities. These equity securities can be redeemedsold on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.managers and were $84 million and $157 million at December 31, 2018 and 2017, respectively. Other securities – Devon’s other securities include cash and commingled, short-term investment funds. The short-term investment funds’ securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers. Devon’s hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategiesfunds and a hedge fund of funds that investsinvest both long and short using a variety of investment strategies. Devon’s hedge fund of funds is not actively traded, and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3these securities is based upon the net asset values provided by investment representsmanagers and were $132 million and $135 million at December 31, 2018 and 2017, respectively.
Defined Postretirement Plans Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying U.S. retirees. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the fair valueplans is to fund the benefits as determined bythey become payable with available cash and cash equivalents. Benefit Obligations and Funded Status The following table summarizes the hedge fund manager. benefit obligations, assets, funded status and balance sheet impacts associated with its defined pension and postretirement plans. Devon’s benefit obligations and plan assets are measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the projected benefit obligation at December 31, 2018 and 2017.88
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) | | Pension Benefits | | | Postretirement Benefits | | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | Change in benefit obligation: | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | 1,279 | | | $ | 1,249 | | | $ | 19 | | | $ | 21 | | Service cost | | | 10 | | | | 15 | | | | — | | | | — | | Interest cost | | | 39 | | | | 42 | | | | — | | | | — | | Actuarial loss (gain) | | | (83 | ) | | | 59 | | | | (3 | ) | | | — | | Plan amendments | | | — | | | | — | | | | — | | | | — | | Plan curtailments | | | 2 | | | | — | | | | 2 | | | | — | | Plan settlements | | | (241 | ) | | | — | | | | — | | | | — | | Foreign exchange rate changes | | | (3 | ) | | | 2 | | | | — | | | | — | | Participant contributions | | | — | | | | — | | | | 2 | | | | 1 | | Benefits paid | | | (60 | ) | | | (88 | ) | | | (3 | ) | | | (3 | ) | Benefit obligation at end of year | | | 943 | | | | 1,279 | | | | 17 | | | | 19 | | Change in plan assets: | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | | 1,035 | | | | 985 | | | | — | | | | — | | Actual return on plan assets | | | (36 | ) | | | 122 | | | | — | | | | — | | Employer contributions | | | 14 | | | | 14 | | | | 1 | | | | 2 | | Participant contributions | | | — | | | | — | | | | 2 | | | | 1 | | Plan settlements | | | (241 | ) | | | — | | | | — | | | | — | | Benefits paid | | | (60 | ) | | | (88 | ) | | | (3 | ) | | | (3 | ) | Foreign exchange rate changes | | | (3 | ) | | | 2 | | | | — | | | | — | | Fair value of plan assets at end of year | | | 709 | | | | 1,035 | | | | — | | | | — | | Funded status at end of year | | $ | (234 | ) | | $ | (244 | ) | | $ | (17 | ) | | $ | (19 | ) | Amounts recognized in balance sheet: | | | | | | | | | | | | | | | | | Other long-term assets | | $ | 3 | | | $ | 4 | | | $ | — | | | $ | — | | Other current liabilities | | | (14 | ) | | | (13 | ) | | | (3 | ) | | | (3 | ) | Other long-term liabilities | | | (223 | ) | | | (235 | ) | | | (14 | ) | | | (16 | ) | Net amount | | $ | (234 | ) | | $ | (244 | ) | | $ | (17 | ) | | $ | (19 | ) | Amounts recognized in accumulated other comprehensive earnings: | | | | | | | | | | | | | | | | | Net actuarial loss (gain) | | $ | 202 | | | $ | 257 | | | $ | (11 | ) | | $ | (11 | ) | Prior service cost (credit) | | | 4 | | | | 6 | | | | (2 | ) | | | (3 | ) | Total | | $ | 206 | | | $ | 263 | | | $ | (13 | ) | | $ | (14 | ) |
During the third quarter of 2018, Devon entered into a group annuity contract, under which a third party has permanently assumed certain of Devon’s defined benefit pension obligations. The purchase of this group annuity contract reduced Devon’s pension assets and liabilities and is the primary component of the $241 million of plan settlements within the preceding table. In connection with the group annuity contract transaction, Devon recorded a settlement expense of approximately $33 million, which was reclassified from other comprehensive earnings to other expense on the consolidated comprehensive statements of earnings in 2018. 89
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit obligation in excess of plan assets at December 31, 2018 and December 31, 2017, as presented in the table below. | | December 31, | | | | 2018 | | | 2017 | | Projected benefit obligation | | $ | 922 | | | $ | 1,255 | | Accumulated benefit obligation | | $ | 906 | | | $ | 1,226 | | Fair value of plan assets | | $ | 685 | | | $ | 1,007 | |
The following table presents a summarythe components of net periodic benefit cost and other comprehensive earnings. | | Pension Benefits | | | Postretirement Benefits | | | | 2018 | | | 2017 | | | 2016 | | | 2018 | | | 2017 | | | 2016 | | Net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Service cost | | $ | 10 | | | $ | 15 | | | $ | 15 | | | $ | — | | | $ | — | | | $ | — | | Interest cost | | | 39 | | | | 42 | | | | 42 | | | | — | | | | — | | | | 1 | | Expected return on plan assets | | | (49 | ) | | | (54 | ) | | | (55 | ) | | | — | | | | — | | | | — | | Recognition of net actuarial loss (gain) (1) | | | 13 | | | | 19 | | | | 25 | | | | (1 | ) | | | (1 | ) | | | (1 | ) | Recognition of prior service cost (1) | | | 1 | | | | 2 | | | | 3 | | | | (1 | ) | | | (1 | ) | | | (1 | ) | Total net periodic benefit cost (2) | | | 14 | | | | 24 | | | | 30 | | | | (2 | ) | | | (2 | ) | | | (1 | ) | Other comprehensive loss (earnings): | | | | | | | | | | | | | | | | | | | | | | | | | Actuarial loss (gain) arising in current year | | | 4 | | | | (9 | ) | | | 26 | | | | (1 | ) | | | (1 | ) | | | — | | Prior service cost arising in current year | | | — | | | | — | | | | 2 | | | | — | | | | — | | | | — | | Recognition of net actuarial gain (loss), including settlement expense, in net periodic benefit cost (3) | | | (60 | ) | | | (19 | ) | | | (43 | ) | | | 1 | | | | 1 | | | | 1 | | Recognition of prior service cost, including curtailment, in net periodic benefit cost (3) | | | (2 | ) | | | (2 | ) | | | (9 | ) | | | 1 | | | | 1 | | | | 1 | | Total other comprehensive loss (earnings) | | | (58 | ) | | | (30 | ) | | | (24 | ) | | | 1 | | | | 1 | | | | 2 | | Total recognized | | $ | (44 | ) | | $ | (6 | ) | | $ | 6 | | | $ | (1 | ) | | $ | (1 | ) | | $ | 1 | |
(1) | These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. |
(2) | The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in other expenses in the accompanying consolidated comprehensive statements of earnings. |
(3) | These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2018 and 2016. See Note 6 for further discussion. |
Assumptions | | Pension Benefits | | | Postretirement Benefits | | | | 2018 | | | 2017 | | | 2016 | | | 2018 | | | 2017 | | | 2016 | | Assumptions to determine benefit obligations: | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | 4.21% | | | 3.59% | | | 4.07% | | | 4.01% | | | 3.25% | | | 3.46% | | Rate of compensation increase | | 2.50% | | | 2.50% | | | 4.49% | | | N/A | | | N/A | | | N/A | | Assumptions to determine net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate - service cost | | 3.98% | | | 4.29% | | | 4.39% | | | 4.13% | | | 4.22% | | | 3.63% | | Discount rate - interest cost | | 3.22% | | | 2.99% | | | 4.39% | | | 2.67% | | | 2.39% | | | 3.63% | | Rate of compensation increase | | 2.50% | | | 4.48% | | | 4.49% | | | N/A | | | N/A | | | N/A | | Expected return on plan assets | | 5.67% | | | 5.69% | | | 5.20% | | | N/A | | | N/A | | | N/A | |
90
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Discount Rate - Future pension and post-retirement obligations are discounted based on the rate at which obligations could be effectively settled, considering the timing of expected future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. Expected return on plan assets – This was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions and consideration of target allocation of investment types. Mortality rate – Devon utilized the Society of Actuaries produced mortality tables and an improvement scale derived from the updated tables for 2017 and 2018 and the actuary’s best estimate of mortality for 2016 for the population of participants in Devon’s plans. Other assumptions – For measurement of the changes2018 benefit obligation for the other postretirement medical plans, a 7.1% annual rate of increase in Devon’s Level 3 plan assets (millions).the per capita cost of covered health care benefits was assumed for 2019. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. | | | | | December 31, 2013 | | $ | 112 | | Disbursements | | | (6 | ) | Investment returns | | | 6 | | | | | | | December 31, 2014 | | | 112 | | Purchases | | | 5 | | Investment returns | | | 3 | | | | | | | December 31, 2015 | | $ | 120 | | | | | | |
Expected Cash Flows The following table presents expected cash flow informationDevon expects benefit plan payments to average approximately $59 million a year for Devon’s pensionthe next five years and postretirement benefit plans.
| | | | | | | | | | | Pension Benefits | | | Postretirement Benefits | | | | (Millions) | | Devon’s 2016 contributions | | $ | 12 | | | $ | 3 | | Benefit payments: | | | | | | | | | 2016 | | $ | 73 | | | $ | 3 | | 2017 | | $ | 75 | | | $ | 3 | | 2018 | | $ | 77 | | | $ | 3 | | 2019 | | $ | 78 | | | $ | 3 | | 2020 | | $ | 83 | | | $ | 2 | | 2021 to 2025 | | $ | 446 | | | $ | 7 | |
Expected contributions included in$153 million total for the table above include amounts related to Devon’s qualified plans, nonqualified plans and postretirement plans.five years thereafter. Of the benefits expectedthese payments to be paid in 2016, the $122019, $17 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans, and the $3 million of postretirement benefits is expected to be funded from Devon’s available cash, cash equivalents and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.
Defined Contribution Plans
Independent of EnLink, Devon maintains defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. EnLink also maintains a 401(k) plan covering eligible employees. The following table presents expense related to these defined contribution plans.assets.
| | | | | | | | | | | | | | | Year Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | | (Millions) | | 401(k) and enhanced contribution plans | | $ | 63 | | | $ | 49 | | | $ | 41 | | Canadian pension and savings plans | | | 16 | | | | 20 | | | | 26 | | | | | | | | | | | | | | | Total | | $ | 79 | | | $ | 69 | | | $ | 67 | | | | | | | | | | | | | | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
16.18. | Stockholders’ Equity |
The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors. Common Stock Issued In December 2015, Devon issued approximately 7 million shares of common stock as part of the Powder River Basin asset acquisition discussed in Note 2. Additionally, in January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition.acquisition discussed in Note 2. Additionally, in February 2016, Devon issued 79 million shares of common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion. DividendsShare Repurchase Program
In March 2018, Devon announced a share repurchase program to buy up to $1.0 billion of shares of common stock. In June 2018, in conjunction with the announced divestiture of its investment in EnLink and the General Partner, Devon increased its program by an additional $3.0 billion. In February 2019, Devon’s Board of Directors authorized an expansion of the share repurchase program by an additional $1.0 billion, bringing the total to $5.0 billion. The share repurchase program expires December 31, 2019. 91
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) During the third quarter of 2018, Devon entered into and completed an ASR transaction to repurchase $1.0 billion of the $4.0 billion program. The table below provides information regarding purchases of Devon’s common stock that were made during 2018 (shares in thousands). | | Total Number of Shares Purchased | | | Dollar Value of Shares Purchased | | | Average Price Paid per Share | | First quarter 2018: | | | | | | | | | | | | | Open-Market | | | 2,561 | | | $ | 82 | | | $ | 32.19 | | Second quarter 2018: | | | | | | | | | | | | | Open-Market | | | 11,154 | | | | 439 | | | | 39.35 | | Third quarter 2018: | | | | | | | | | | | | | Open-Market | | | 16,492 | | | | 712 | | | | 43.13 | | ASR | | | 24,330 | | | | 1,000 | | | | 41.10 | | Total | | | 40,822 | | | | 1,712 | | | | 41.92 | | Fourth quarter 2018: | | | | | | | | | | | | | Open-Market | | | 23,612 | | | | 745 | | | | 31.57 | | Total year-to-date | | | 78,149 | | | $ | 2,978 | | | $ | 38.11 | |
Dividends The table below summarizes the dividends Devon paid on its common stock dividends of $396 million, $386 million and $348 million in 2015, 2014 and 2013, respectively. Thestock. | Amounts | | | Rate Per Share | | Year Ended 2018: | | | | | | | | First quarter | $ | 32 | | | $ | 0.06 | | Second quarter | | 42 | | | $ | 0.08 | | Third quarter | | 38 | | | $ | 0.08 | | Fourth quarter | | 37 | | | $ | 0.08 | | Total year-to-date | $ | 149 | | | | | | Year Ended 2017: | | | | | | | | First quarter | $ | 32 | | | $ | 0.06 | | Second quarter | | 33 | | | $ | 0.06 | | Third quarter | | 30 | | | $ | 0.06 | | Fourth quarter | | 32 | | | $ | 0.06 | | Total year-to-date | $ | 127 | | | | | | Year Ended 2016: | | | | | | | | First quarter | $ | 125 | | | $ | 0.24 | | Second quarter | | 33 | | | $ | 0.06 | | Third quarter | | 32 | | | $ | 0.06 | | Fourth quarter | | 31 | | | $ | 0.06 | | Total year-to-date | $ | 221 | | | | | |
In response to the depressed commodity price environment, Devon reduced the quarterly cash dividend was $0.20 per share in the first quarter of 2013. Devon increased the dividend rate from $0.24 to $0.22$0.06 per share in the second quarter of 2013 and2016. Devon increased the quarterly dividend by 33% to $0.24$0.08 per share in the second quarter of 2014.2018. In February 2019, Devon announced a 12.5% increase to its quarterly dividend, to $0.09 per share, beginning in the second quarter of 2019. Stock Option Proceeds92
Devon received $4 million, $93 million and $3 million from stock option proceeds in 2015, 2014 and 2013, respectively.Table of Contents
17. | Noncontrolling Interests |
Acquisition of Noncontrolling InterestsIndex to Financial Statements
In March 2014, EnLink was formed as a publicly traded consolidated subsidiary of Devon to provide midstream services to Devon and third parties. Devon obtained approximately 120.5 million units, or a 52% ownership interest, as a result of this transaction. Approximately 92.7 million units were issued to the public for a 41% ownership interest, with the remaining 7% ownership interest held by the General Partner.
Subsidiary Equity Transactions
Through its equity distribution agreements, EnLink has the ability to sell common units through an “at the market” equity offering program. During 2015 and 2014, EnLink issued and sold approximately 1.3 million and 14.8 million common units through its at the market program and general public offerings, generating net proceeds of $25 million and $410 million, respectively. Furthermore, in October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction with the General Partner, generating approximately $50 million in proceeds.
In 2015, Devon conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising net proceeds of $654 million.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) As a result of these transactions, the Coronado acquisition and dropdown transactions discussed in Note 2, the ownership of EnLink at December 31, 2015 is approximately:
28% – Devon
19. | Discontinued Operations and Assets Held For Sale |
27% – General Partner (controlled by Devon)
The net gains and losses and related income taxes resulting from these transactions have been recorded asOn June 6, 2018, Devon announced that it had entered into an adjustmentagreement to equity, and the changesell its aggregate ownership interests in ownership reflected as an adjustment to noncontrolling interests.
As further discussed in Note 2, in January 2016, EnLink acquired midstream assets in exchange for cash and equity. Subsequent to this transaction, the ownership of the General Partner is approximately:
Subsequent to this transaction, the ownership of EnLink is approximately:
23% – General Partner (controlled by Devon)
Distributions to Noncontrolling Interests
In conjunction with the formation of the General Partner in 2014, Devon made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $254 millionfor $3.125 billion. Upon entering into the agreement to sell its ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and $135 millionmet the requirements of assets held for sale and discontinued operations. As part of its assessment, Devon considered the following: 1) Devon is exiting its entire midstream business ownership; 2) EnLink and the General Partner are a separate reportable segment and are a component of Devon’s business; and 3) the transaction resulted in a material reduction in total assets, debt, revenues, net earnings and operating cash flows. As a result, Devon classified the results of operations and cash flows related to non-Devon unitholders during 2015EnLink and 2014, respectively.the General Partner as discontinued operations on its consolidated financial statements. Additionally, Devon ceased depreciation and amortization for all plant, property and equipment and intangible assets classified as assets held for sale on the date the sales agreement was signed.
On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). Current (cash) income tax associated with the transaction was approximately $12 million. The vast majority of the tax effect relates to deferred tax expense offset by the valuation allowance adjustment explained inNote 8. As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the minimum volume commitments for the Bridgeport and Cana plants expired at the end of 2018. Devon has minimum volume commitments for gathering and processing of 77-128 MMcf/d with EnLink at the Chisholm plant through early 2021. From the period of July 19, 2018 through December 31, 2018, Devon had net outflows of approximately $380 million with EnLink, which primarily related to gathering and processing expenses. These net outflows represent gross cash amounts and not net working interest amounts. Prior to the divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to EnLink represent third-party transactions and are no longer eliminated in consolidation. 93
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) The following table presents the amounts reported in the consolidated comprehensive statements of earnings as discontinued operations. | | Year Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Marketing and midstream revenues | | $ | 3,567 | | | $ | 5,071 | | | $ | 3,551 | | Marketing and midstream expenses | | | 2,912 | | | | 4,111 | | | | 2,712 | | Depreciation, depletion and amortization | | | 244 | | | | 545 | | | | 504 | | General and administrative expenses | | | 65 | | | | 128 | | | | 118 | | Financing costs, net | | | 98 | | | | 181 | | | | 190 | | Asset impairments | | | — | | | | 17 | | | | 873 | | Asset dispositions | | | (2,607 | ) | | | — | | | | 13 | | Other expenses | | | (8 | ) | | | (34 | ) | | | 25 | | Total expenses | | | 704 | | | | 4,948 | | | | 4,435 | | Earnings (loss) from discontinued operations before income taxes | | | 2,863 | | | | 123 | | | | (884 | ) | Income tax expense (benefit) | | | 403 | | | | (197 | ) | | | — | | Net earnings (loss) from discontinued operations, net of income tax expense | | | 2,460 | | | | 320 | | | | (884 | ) | Net earnings (loss) attributable to noncontrolling interests | | | 160 | | | | 180 | | | | (403 | ) | Net earnings (loss) from discontinued operations attributable to Devon | | $ | 2,300 | | | $ | 140 | | | $ | (481 | ) |
The following table presents the carrying amounts of the assets and liabilities classified as held for sale on the consolidated balance sheets. The assets and liabilities classified as held for sale at December 31, 2018 are related to the divestiture of non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2. The assets and liabilities classified as held for sale at December 31, 2017 are related to the divestiture of EnLink and the General Partner. | | December 31, 2018 | | | December 31, 2017 | | Cash and cash equivalents | | $ | — | | | $ | 31 | | Accounts receivable | | | 7 | | | | 681 | | Other current assets | | | — | | | | 48 | | Oil and gas property and equipment, based on successful efforts accounting, net | | | 190 | | | | — | | Midstream and other property and equipment, net | | | — | | | | 6,587 | | Goodwill | | | — | | | | 1,542 | | Other long-term assets | | | — | | | | 1,600 | | Total assets held for sale | | $ | 197 | | | $ | 10,489 | | | | | | | | | | | Accounts payable | | $ | 3 | | | $ | 186 | | Revenues and royalties payable | | | — | | | | 432 | | Other current liabilities | | | 19 | | | | 373 | | Long-term debt | | | — | | | | 3,542 | | Deferred income taxes | | | — | | | | 346 | | Asset retirement obligations | | | 47 | | | | 14 | | Other long-term liabilities | | | — | | | | 34 | | Total liabilities held for sale | | $ | 69 | | | $ | 4,927 | |
94
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 18.20. | Commitments and Contingencies |
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates. Royalty Matters Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. TheDevon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits allegeare claims that the producers and related partiesDevon used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters. DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Environmental Matters Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material. Beginning in 2013, various parishes in Louisiana filed suit against more than 100 oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although we cannot predict the ultimate outcome of these matters, Devon is vigorously defending against these claims. Other Matters Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject. 95
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Commitments The following table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2015.2018. | Year Ending December 31, | | Purchase Obligations | | | Drilling and Facility Obligations | | | Operational Agreements | | | Office and Equipment Leases | | | Purchase Obligations | | | Drilling and Facility Obligations | | | Operational Agreements | | | Office and Equipment Leases | | | | (Millions) | | | 2016 | | $ | 557 | | | $ | 69 | | | $ | 994 | | | $ | 70 | | | 2017 | | | 703 | | | | 51 | | | | 972 | | | | 58 | | | 2018 | | | 791 | | | | 34 | | | | 936 | | | | 76 | | | 2019 | | | 803 | | | | 5 | | | | 402 | | | | 68 | | | $ | 541 | | | $ | 274 | | | $ | 587 | | | $ | 64 | | 2020 | | | 845 | | | | 2 | | | | 255 | | | | 42 | | | | 567 | | | | 85 | | | | 519 | | | | 43 | | 2021 | | | | 140 | | | | 48 | | | | 373 | | | | 31 | | 2022 | | | | — | | | | 14 | | | | 419 | | | | 26 | | 2023 | | | | — | | | | 8 | | | | 354 | | | | 25 | | Thereafter | | | 206 | | | | 28 | | | | 1,042 | | | | 129 | | | | — | | | | 16 | | | | 3,374 | | | | 311 | | | | | | | | | | | | | | | | Total | | $ | 3,905 | | | $ | 189 | | | $ | 4,601 | | | $ | 443 | | | $ | 1,248 | | | $ | 445 | | | $ | 5,626 | | | $ | 500 | | | | | | | | | | | | | | | |
Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s 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 Devon’s internal estimate of future condensate market prices. Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. The value of the drilling obligations reported is based on gross contractual value. Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets. Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in G&A underrecognized for operating leases, net of sublease income, was $88$11 million, $64$7 million and $26$11 million in 2015, 20142018, 2017 and 2013,2016, respectively. 96
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 19.21. | Fair Value Measurements |
The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at December 31, 20152018 and December 31, 2014.2017, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, information regarding the fair values of oil and gas assets goodwill and other intangible assetsrelated impairments are measured as of the impairment date using Level 3 inputs. Additional information on asset impairments and the pension plan assets is provided in Note 5, and Note 12 and Note 15,17, respectively. | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using: | | | | | | | | Fair Value Measurements Using: | | | Carrying | | | Total Fair | | | Level 1 | | | Level 2 | | | | Carrying Amount | | Total Fair Value | | Level 1 Inputs | | | Level 2 Inputs | | Level 3 Inputs | | | Amount | | | Value | | | Inputs | | | Inputs | | | | (Millions) | | | December 31, 2015 assets (liabilities): | | | | | | | | | | | | December 31, 2018 assets (liabilities): | | | | | | | | | | | | | | | | | | Cash equivalents | | | $ | 1,505 | | | $ | 1,505 | | | $ | 1,405 | | | $ | 100 | | Commodity derivatives | | | $ | 677 | | | $ | 677 | | | $ | — | | | $ | 677 | | Commodity derivatives | | | $ | (68 | ) | | $ | (68 | ) | | $ | — | | | $ | (68 | ) | Debt | | | $ | (5,947 | ) | | $ | (5,965 | ) | | $ | — | | | $ | (5,965 | ) | December 31, 2017 assets (liabilities): | | | | | | | | | | | | | | | | | | Cash equivalents | | $ | 1,871 | | | $ | 1,871 | | | $ | 1,471 | | | $ | 400 | | | $ | — | | | $ | 1,533 | | | $ | 1,533 | | | $ | 1,454 | | | $ | 79 | | Commodity derivatives | | $ | 35 | | | $ | 35 | | | $ | — | | | $ | 35 | | | $ | — | | | $ | 205 | | | $ | 205 | | | $ | — | | | $ | 205 | | Commodity derivatives | | $ | (18 | ) | | $ | (18 | ) | | $ | — | | | $ | (18 | ) | | $ | — | | | $ | (286 | ) | | $ | (286 | ) | | $ | — | | | $ | (286 | ) | Interest rate derivatives | | $ | 2 | | | $ | 2 | | | $ | — | | | $ | 2 | | | $ | — | | | $ | 1 | | | $ | 1 | | | $ | — | | | $ | 1 | | Interest rate derivatives | | $ | (22 | ) | | $ | (22 | ) | | $ | — | | | $ | (22 | ) | | $ | — | | | $ | (64 | ) | | $ | (64 | ) | | $ | — | | | $ | (64 | ) | Foreign currency derivatives | | $ | 8 | | | $ | 8 | | | $ | — | | | $ | 8 | | | $ | — | | | Foreign currency derivatives | | $ | (8 | ) | | $ | (8 | ) | | $ | — | | | $ | (8 | ) | | $ | — | | | Debt | | $ | (13,113 | ) | | $ | (11,927 | ) | | $ | — | | | $ | (11,927 | ) | | $ | — | | | $ | (6,864 | ) | | $ | (8,131 | ) | | $ | — | | | $ | (8,131 | ) | Capital lease obligations | | $ | (17 | ) | | $ | (16 | ) | | $ | — | | | $ | (16 | ) | | $ | — | | | | December 31, 2014 assets (liabilities): | | | | | | | | | | | | Cash equivalents | | $ | 950 | | | $ | 950 | | | $ | 340 | | | $ | 610 | | | $ | — | | | Commodity derivatives | | $ | 1,995 | | | $ | 1,995 | | | $ | — | | | $ | 1,995 | | | $ | — | | | Commodity derivatives | | $ | (56 | ) | | $ | (56 | ) | | $ | — | | | $ | (56 | ) | | $ | — | | | Interest rate derivatives | | $ | 1 | | | $ | 1 | | | $ | — | | | $ | 1 | | | $ | — | | | Interest rate derivatives | | $ | (1 | ) | | $ | (1 | ) | | $ | — | | | $ | (1 | ) | | $ | — | | | Foreign currency derivatives | | $ | 8 | | | $ | 8 | | | $ | — | | | $ | 8 | | | $ | — | | | Debt | | $ | (11,262 | ) | | $ | (12,472 | ) | | $ | — | | | $ | (12,472 | ) | | $ | — | | | Capital lease obligations | | $ | (20 | ) | | $ | (20 | ) | | $ | — | | | $ | (20 | ) | | $ | — | | |
The following methods and assumptions were used to estimate the fair values in the tables above. Level 1 Fair Value Measurements Cash equivalents– Amounts consist primarily of money market investments. Theinvestments and the fair value approximates the carrying value. Level 2 Fair Value Measurements Cash equivalents – Amounts consist primarily of commercial paper and Canadian agency and provincial securities investments. The fair value approximates the carrying value. Commodity and interest rate and foreign currency derivatives– The fair values of commodity and interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements. DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Debt – Devon’s debt instruments do not actively trade in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity. The fair values of commercial paper and credit facility balances are the carrying values. Capital lease obligations – The fair value was calculated using inputs from third-party banks.
97
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) 20.22. | Segment Information |
Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian exploration and production operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged in oil and gas exploration and production activities, and certain information regarding such activities for each segment is included in Note 21.23. Devon considers EnLink, combined with the General Partner, to be an operatinga segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located acrossin the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore,However, with Devon’s closing of the divestment of EnLink isand the General Partner in July 2018, activity related to EnLink and the General Partner have now been classified as discontinued operations within Devon’s consolidated comprehensive statements of earnings and consolidated statements of cash flows, and the associated assets and liabilities of EnLink and the General Partner are presented as a separate reporting segment. Forassets and liabilities held for sale on the reporting periods prior to the formationconsolidated balance sheets. Additional information can be found in Note 19. 98
Table of EnLink, Devon has reclassified, from its U.S. segment to the EnLink segment, all asset-level amounts related to the midstream assets that it contributed to EnLink.Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) | | | | | | | | | | | | | | | | | | | | | | | U.S. (1) | | | Canada | | | EnLink (1) | | | Eliminations | | | Total | | | | (Millions) | | Year Ended December 31, 2015: | | | | | | | | | | | | | | | | | | | | | Revenues from external customers | | $ | 8,360 | | | $ | 1,012 | | | $ | 3,773 | | | $ | — | | | $ | 13,145 | | Intersegment revenues | | $ | — | | | $ | — | | | $ | 679 | | | $ | (679 | ) | | $ | — | | Depreciation, depletion and amortization | | $ | 2,220 | | | $ | 522 | | | $ | 387 | | | $ | — | | | $ | 3,129 | | Asset impairments | | $ | 18,000 | | | $ | 1,257 | | | $ | 1,563 | | | $ | — | | | $ | 20,820 | | Interest expense | | $ | 368 | | | $ | 94 | | | $ | 107 | | | $ | (46 | ) | | $ | 523 | | Loss before income taxes | | $ | (18,214 | ) | | $ | (1,670 | ) | | $ | (1,384 | ) | | $ | — | | | $ | (21,268 | ) | Income tax expense (benefit) | | $ | (5,650 | ) | | $ | (445 | ) | | $ | 30 | | | $ | — | | | $ | (6,065 | ) | Net loss | | $ | (12,564 | ) | | $ | (1,225 | ) | | $ | (1,414 | ) | | $ | — | | | $ | (15,203 | ) | Net earnings (loss) attributable to noncontrolling interests | | $ | 1 | | | $ | — | | | $ | (750 | ) | | $ | — | | | $ | (749 | ) | Net loss attributable to Devon | | $ | (12,565 | ) | | $ | (1,225 | ) | | $ | (664 | ) | | $ | — | | | $ | (14,454 | ) | Property and equipment, net | | $ | 8,811 | | | $ | 4,590 | | | $ | 5,667 | | | $ | — | | | $ | 19,068 | | Total assets | | $ | 14,600 | | | $ | 5,464 | | | $ | 9,565 | | | $ | (97 | ) | | $ | 29,532 | | Capital expenditures | | $ | 4,575 | | | $ | 680 | | | $ | 978 | | | $ | — | | | $ | 6,233 | | | | | | | | Year Ended December 31, 2014: | | | | | | | | | | | | | | | | | | | | | Revenues from external customers | | $ | 14,854 | | | $ | 2,063 | | | $ | 2,649 | | | $ | — | | | $ | 19,566 | | Intersegment revenues | | $ | — | | | $ | — | | | $ | 859 | | | $ | (859 | ) | | $ | — | | Depreciation, depletion and amortization | | $ | 2,475 | | | $ | 560 | | | $ | 284 | | | $ | — | | | $ | 3,319 | | Asset impairments | | $ | 12 | | | $ | 1,941 | | | $ | — | | | $ | — | | | $ | 1,953 | | Gains and losses on asset sales | | $ | 5 | | | $ | (1,077 | ) | | $ | — | | | $ | — | | | $ | (1,072 | ) | Interest expense | | $ | 441 | | | $ | 85 | | | $ | 54 | | | $ | (44 | ) | | $ | 536 | | Earnings (loss) before income taxes | | $ | 4,390 | | | $ | (657 | ) | | $ | 326 | | | $ | — | | | $ | 4,059 | | Income tax expense | | $ | 1,797 | | | $ | 495 | | | $ | 76 | | | $ | — | | | $ | 2,368 | | Net earnings (loss) | | $ | 2,593 | | | $ | (1,152 | ) | | $ | 250 | | | $ | — | | | $ | 1,691 | | Net earnings attributable to noncontrolling interests | | $ | 1 | | | $ | — | | | $ | 83 | | | $ | — | | | $ | 84 | | Net earnings (loss) attributable to Devon | | $ | 2,592 | | | $ | (1,152 | ) | | $ | 167 | | | $ | — | | | $ | 1,607 | | Property and equipment, net | | $ | 24,463 | | | $ | 6,790 | | | $ | 5,043 | | | $ | — | | | $ | 36,296 | | Total assets | | $ | 32,037 | | | $ | 8,517 | | | $ | 10,207 | | | $ | (124 | ) | | $ | 50,637 | | Capital expenditures | | $ | 11,214 | | | $ | 1,344 | | | $ | 1,001 | | | $ | — | | | $ | 13,559 | | | | | | | | Year Ended December 31, 2013: | | | | | | | | | | | | | | | | | | | | | Revenues from external customers | | $ | 6,807 | | | $ | 2,656 | | | $ | 934 | | | $ | — | | | $ | 10,397 | | Intersegment revenues | | $ | — | | | $ | — | | | $ | 1,362 | | | $ | (1,362 | ) | | $ | — | | Depreciation, depletion and amortization | | $ | 1,744 | | | $ | 849 | | | $ | 187 | | | $ | — | | | $ | 2,780 | | Asset impairments | | $ | 1,133 | | | $ | 843 | | | $ | — | | | $ | — | | | $ | 1,976 | | Interest expense | | $ | 392 | | | $ | 80 | | | $ | — | | | $ | (35 | ) | | $ | 437 | | Earnings (loss) before income taxes | | $ | 495 | | | $ | (532 | ) | | $ | 186 | | | $ | — | | | $ | 149 | | Income tax expense (benefit) | | $ | 258 | | | $ | (156 | ) | | $ | 67 | | | $ | — | | | $ | 169 | | Net earnings (loss) | | $ | 237 | | | $ | (376 | ) | | $ | 119 | | | $ | — | | | $ | (20 | ) | Property and equipment, net | | $ | 18,201 | | | $ | 8,478 | | | $ | 1,768 | | | $ | — | | | $ | 28,447 | | Total assets | | $ | 27,080 | | | $ | 13,560 | | | $ | 2,237 | | | $ | — | | | $ | 42,877 | | Capital expenditures | | $ | 4,589 | | | $ | 1,841 | | | $ | 213 | | | $ | — | | | $ | 6,643 | |
(1) | Due to Devon’s control of EnLink through its control of the General Partner, the acquisition of VEX by EnLink from Devon in the second quarter of 2015 was considered a transfer of net assets between entities under common control, and EnLink was required to recast its financial statements as of December 31, 2015 to include the activities of such assets from the date of common control. Therefore, the results of VEX have been moved from the U.S. segment to the EnLink segment for the recasted periods. |
| | U.S. | | | Canada | | | Total | | Year Ended December 31, 2018: | | | | | | | | | | | | | Revenues from external customers (1) | | $ | 9,674 | | | $ | 1,060 | | | $ | 10,734 | | Depreciation, depletion and amortization | | $ | 1,328 | | | $ | 330 | | | $ | 1,658 | | Interest expense | | $ | 469 | | | $ | 166 | | | $ | 635 | | Asset impairments | | $ | 156 | | | $ | — | | | $ | 156 | | Asset dispositions | | $ | (263 | ) | | $ | — | | | $ | (263 | ) | Restructuring and transaction costs | | $ | 97 | | | $ | 17 | | | $ | 114 | | Earnings (loss) from continuing operations before income taxes | | $ | 1,294 | | | $ | (374 | ) | | $ | 920 | | Income tax expense (benefit) | | $ | 294 | | | $ | (138 | ) | | $ | 156 | | Net earnings (loss) from continuing operations | | $ | 1,000 | | | $ | (236 | ) | | $ | 764 | | Property and equipment, net | | $ | 10,026 | | | $ | 3,909 | | | $ | 13,935 | | Total assets (2) | | $ | 14,853 | | | $ | 4,516 | | | $ | 19,369 | | Capital expenditures, including acquisitions | | $ | 2,294 | | | $ | 282 | | | $ | 2,576 | | Year Ended December 31, 2017: | | | | | | | | | | | | | Revenues from external customers | | $ | 7,326 | | | $ | 1,552 | | | $ | 8,878 | | Depreciation, depletion and amortization | | $ | 1,149 | | | $ | 380 | | | $ | 1,529 | | Interest expense | | $ | 324 | | | $ | 12 | | | $ | 336 | | Asset dispositions | | $ | (218 | ) | | $ | 1 | | | $ | (217 | ) | Earnings from continuing operations before income taxes | | $ | 443 | | | $ | 330 | | | $ | 773 | | Income tax expense | | $ | 9 | | | $ | 6 | | | $ | 15 | | Net earnings from continuing operations | | $ | 434 | | | $ | 324 | | | $ | 758 | | Property and equipment, net | | $ | 10,274 | | | $ | 4,310 | | | $ | 14,584 | | Total assets (3) | | $ | 14,254 | | | $ | 5,498 | | | $ | 19,752 | | Capital expenditures, including acquisitions | | $ | 1,821 | | | $ | 348 | | | $ | 2,169 | | Year Ended December 31, 2016: | | | | | | | | | | | | | Revenues from external customers | | $ | 5,722 | | | $ | 1,031 | | | $ | 6,753 | | Depreciation, depletion and amortization | | $ | 1,178 | | | $ | 414 | | | $ | 1,592 | | Interest expense | | $ | 624 | | | $ | 100 | | | $ | 724 | | Asset impairments | | $ | 435 | | | $ | 2 | | | $ | 437 | | Asset dispositions | | $ | (955 | ) | | $ | (541 | ) | | $ | (1,496 | ) | Restructuring and transaction costs | | $ | 242 | | | $ | 19 | | | $ | 261 | | Earnings (loss) from continuing operations before income taxes | | $ | (757 | ) | | $ | 324 | | | $ | (433 | ) | Income tax expense (benefit) | | $ | (8 | ) | | $ | 149 | | | $ | 141 | | Net earnings (loss) from continuing operations | | $ | (749 | ) | | $ | 175 | | | $ | (574 | ) | Property and equipment, net | | $ | 10,166 | | | $ | 4,110 | | | $ | 14,276 | | Total assets (3) | | $ | 13,390 | | | $ | 5,071 | | | $ | 18,461 | | Capital expenditures, including acquisitions | | $ | 2,640 | | | $ | 186 | | | $ | 2,826 | |
(1) Revenues from oil, gas and NGL sales and marketing revenues represent revenue from contracts with customers. (2) Total assets in the table above do not include assets held for sale related to Devon’s non-core assets in the Permian Basin closed in January 2019, which totaled $197 million. (3) Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $10.5 billion and $10.2 billion in 2017 and 2016, respectively. 99
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) The following table presents revenue from contracts with customers that are disaggregated based on the type of good. | | Year Ended December 31, 2018 | | | | U.S. | | | Canada | | | Total | | Oil | | $ | 2,957 | | | $ | 814 | | | $ | 3,771 | | Gas | | | 950 | | | | — | | | | 950 | | NGL | | | 956 | | | | — | | | | 956 | | Oil, gas and NGL revenues from contracts with customers | | | 4,863 | | | | 814 | | | | 5,677 | | Oil, gas and NGL derivatives | | | 457 | | | | 151 | | | | 608 | | Upstream revenues | | | 5,320 | | | | 965 | | | | 6,285 | | | | | | | | | | | | | | | Oil | | | 2,745 | | | | 95 | | | | 2,840 | | Gas | | | 738 | | | | — | | | | 738 | | NGL | | | 871 | | | | — | | | | 871 | | Total marketing revenues from contracts with customers | | | 4,354 | | | | 95 | | | | 4,449 | | | | | | | | | | | | | | | Total revenues | | $ | 9,674 | | | $ | 1,060 | | | $ | 10,734 | |
21.23. | Supplemental Information on Oil and Gas Operations (Unaudited) |
Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country. 100
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Costs Incurred The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities. | | | | | | | | Year Ended December 31, 2018 | | | | | U.S. | | | Canada | | | Total | | Property acquisition costs: | | | | | | | | | | | | | | Proved properties | | | $ | 2 | | | $ | — | | | $ | 2 | | Unproved properties | | | | 71 | | | | — | | | | 71 | | Exploration costs | | | | 679 | | | | 85 | | | | 764 | | Development costs | | | | 1,537 | | | | 249 | | | | 1,786 | | Costs incurred | | | $ | 2,289 | | | $ | 334 | | | $ | 2,623 | | | | Year Ended December 31, 2015 | | | | | | | | | | | | | | | | U.S. | | | Canada | | | Total | | | Year Ended December 31, 2017 | | | | (Millions) | | | U.S. | | | Canada | | | Total | | Property acquisition costs: | | | | | | | | | | | | | | | | | | | Proved properties | | $ | 193 | | | $ | 2 | | | $ | 195 | | | $ | 2 | | | $ | — | | | $ | 2 | | Unproved properties | | | 634 | | | | 83 | | | | 717 | | | | 50 | | | | 4 | | | | 54 | | Exploration costs | | | 478 | | | | 109 | | | | 587 | | | | 590 | | | | 87 | | | | 677 | | Development costs | | | 3,269 | | | | 402 | | | | 3,671 | | | | 1,036 | | | | 225 | | | | 1,261 | | | | | | | | | | | | | Costs incurred | | $ | 4,574 | | | $ | 596 | | | $ | 5,170 | | | $ | 1,678 | | | $ | 316 | | | $ | 1,994 | | | | | | | | | | | | | | | | Year Ended December 31, 2014 | | | | | | | | | | | | | | | | U.S. | | | Canada | | | Total | | | Year Ended December 31, 2016 | | | | (Millions) | | | U.S. | | | Canada | | | Total | | Property acquisition costs: | | | | | | | | | | | | | | | | | | | Proved properties | | $ | 5,210 | | | $ | — | | | $ | 5,210 | | | $ | 237 | | | $ | — | | | $ | 237 | | Unproved properties | | | 1,176 | | | | 1 | | | | 1,177 | | | | 1,356 | | | | 2 | | | | 1,358 | | Exploration costs | | | 270 | | | | 52 | | | | 322 | | | | 282 | | | | 78 | | | | 360 | | Development costs | | | 4,400 | | | | 1,063 | | | | 5,463 | | | | 875 | | | | 54 | | | | 929 | | | | | | | | | | | | | Costs incurred | | $ | 11,056 | | | $ | 1,116 | | | $ | 12,172 | | | $ | 2,750 | | | $ | 134 | | | $ | 2,884 | | | | | | | | | | | | | | | | Year Ended December 31, 2013 | | | | | U.S. | | | Canada | | | Total | | | | | (Millions) | | | Property acquisition costs: | | | | | | | | Proved properties | | $ | 19 | | | $ | 3 | | | $ | 22 | | | Unproved properties | | | 213 | | | | 3 | | | | 216 | | | Exploration costs | | | 443 | | | | 152 | | | | 595 | | | Development costs | | | 3,838 | | | | 1,251 | | | | 5,089 | | | | | | | | | | | | | | Costs incurred | | $ | 4,513 | | | $ | 1,409 | | | $ | 5,922 | | | | | | | | | | | | | |
Costs incurred
Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations. Pursuant to the full cost method of accounting, Devon capitalizes certain of its G&A that is related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $372 million, $376 million and $368 million in 2015, 2014 and 2013, respectively. Also,Additionally, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $54$41 million, $45$69 million and $42$61 million in 2015, 20142018, 2017 and 2013,2016, respectively.
101
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Capitalized Costs
The following tables reflect the aggregate capitalized costs related to oil and gas activities.
| | | | | | | | | | | | | | | December 31, 2015 | | | | U.S. | | | Canada | | | Total | | | | (Millions) | | Proved properties | | $ | 64,443 | | | $ | 13,747 | | | $ | 78,190 | | Unproved properties | | | 1,352 | | | | 1,232 | | | | 2,584 | | | | | | | | | | | | | | | Total oil and gas properties | | | 65,795 | | | | 14,979 | | | | 80,774 | | Accumulated DD&A | | | (58,312 | ) | | | (11,185 | ) | | | (69,497 | ) | | | | | | | | | | | | | | Net capitalized costs | | $ | 7,483 | | | $ | 3,794 | | | $ | 11,277 | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | | U.S. | | | Canada | | | Total | | | | (Millions) | | Proved properties | | $ | 59,849 | | | $ | 15,889 | | | $ | 75,738 | | Unproved properties | | | 1,460 | | | | 1,292 | | | | 2,752 | | | | | | | | | | | | | | | Total oil and gas properties | | | 61,309 | | | | 17,181 | | | | 78,490 | | Accumulated DD&A | | | (38,213 | ) | | | (11,347 | ) | | | (49,560 | ) | | | | | | | | | | | | | | Net capitalized costs | | $ | 23,096 | | | $ | 5,834 | | | $ | 28,930 | | | | | | | | | | | | | | |
The following table presents a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2015.
| | | | | | | | | | | | | | | | | | | | | | | Costs Incurred In | | | | 2015 | | | 2014 | | | 2013 | | | Prior to 2013 | | | Total | | | | (Millions) | | Acquisition costs | | $ | 672 | | | $ | 412 | | | $ | 61 | | | $ | 510 | | | $ | 1,655 | | Exploration costs | | | 191 | | | | 132 | | | | 69 | | | | 170 | | | | 562 | | Development costs | | | 9 | | | | 28 | | | | 17 | | | | 128 | | | | 182 | | Capitalized interest | | | 50 | | | | 37 | | | | 32 | | | | 66 | | | | 185 | | | | | | | | | | | | | | | | | | | | | | | Total oil and gas properties not subject to amortization | | $ | 922 | | | $ | 609 | | | $ | 179 | | | $ | 874 | | | $ | 2,584 | | | | | | | | | | | | | | | | | | | | | | |
Included in the $2.6 billion of oil and gas properties not subject to amortization are approximately $1.9 billion of costs that Devon deems significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada and the newly acquired Powder River Basin assets. Devon anticipates determining its Pike development timeline in mid-2016, with its 50% partner. Based on the development plans, Pike costs will begin to be included in the amortization computation when the first phase of this project is fully approved and Devon subsequently begins recognizing the associated proved reserves. Devon is evaluating and plans to develop the newly acquired Powder River Basin properties over the next four to five years.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Results of Operations The following tables include revenues and expenses associated with Devon’s oil and gas producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including DD&A and after giving effect to permanent differences. | | | December 31, 2015 | | | | | U.S. | | | Canada | | | Total | | | Year Ended December 31, 2018 | | | | (Millions) | | | U.S. | | | Canada | | | Total | | Oil, gas and NGL sales | | $ | 4,356 | | | $ | 1,026 | | | $ | 5,382 | | | $ | 4,863 | | | $ | 814 | | | $ | 5,677 | | Lease operating expenses | | | (1,551 | ) | | | (553 | ) | | | (2,104 | ) | | General and administrative expenses | | | (196 | ) | | | (28 | ) | | | (224 | ) | | Production and property taxes | | | (309 | ) | | | (33 | ) | | | (342 | ) | | Production expenses | | | | (1,620 | ) | | | (605 | ) | | | (2,225 | ) | Exploration expenses | | | | (129 | ) | | | (48 | ) | | | (177 | ) | Depreciation, depletion and amortization | | | (2,107 | ) | | | (474 | ) | | | (2,581 | ) | | | (1,234 | ) | | | (325 | ) | | | (1,559 | ) | Asset dispositions | | | | 262 | | | | — | | | | 262 | | Asset impairments | | | (17,992 | ) | | | (1,257 | ) | | | (19,249 | ) | | | (109 | ) | | | — | | | | (109 | ) | Accretion of asset retirement obligations | | | (47 | ) | | | (27 | ) | | | (74 | ) | | | (35 | ) | | | (24 | ) | | | (59 | ) | Income tax benefit | | | 5,547 | | | | 314 | | | | 5,861 | | | | | | | | | | | | | | Income tax (expense) benefit | | | | (460 | ) | | | 51 | | | | (409 | ) | Results of operations | | $ | (12,299 | ) | | $ | (1,032 | ) | | $ | (13,331 | ) | | $ | 1,538 | | | $ | (137 | ) | | $ | 1,401 | | | | | | | | | | | | | Depreciation, depletion and amortization per Boe | | $ | 10.21 | | | $ | 11.30 | | | $ | 10.40 | | | $ | 8.08 | | | $ | 7.63 | | | $ | 7.98 | | | | | | | | | | | | | | | | December 31, 2014 | | | | | U.S. | | | Canada | | | Total | | | | | (Millions) | | | Oil, gas and NGL sales | | $ | 7,867 | | | $ | 2,043 | | | $ | 9,910 | | | Lease operating expenses | | | (1,559 | ) | | | (773 | ) | | | (2,332 | ) | | General and administrative expenses | | | (153 | ) | | | (57 | ) | | | (210 | ) | | Production and property taxes | | | (466 | ) | | | (37 | ) | | | (503 | ) | | Depreciation, depletion and amortization | | | (2,365 | ) | | | (531 | ) | | | (2,896 | ) | | Gain on sale of assets | | | — | | | | 1,077 | | | | 1,077 | | | Accretion of asset retirement obligations | | | (49 | ) | | | (39 | ) | | | (88 | ) | | Income tax expense | | | (1,199 | ) | | | (568 | ) | | | (1,767 | ) | | | | | | | | | | | | | Results of operations(1) | | $ | 2,076 | | | $ | 1,115 | | | $ | 3,191 | | | | | | | | | | | | | | Depreciation, depletion and amortization per Boe | | $ | 11.41 | | | $ | 13.80 | | | $ | 11.79 | | | | | | | | | | | | | | | | | December 31, 2013 | | | | | U.S. | | | Canada | | | Total | | | | | (Millions) | | | Oil, gas and NGL sales | | $ | 5,964 | | | $ | 2,558 | | | $ | 8,522 | | | Lease operating expenses | | | (1,257 | ) | | | (1,011 | ) | | | (2,268 | ) | | General and administrative expenses | | | (125 | ) | | | (77 | ) | | | (202 | ) | | Production and property taxes | | | (380 | ) | | | (59 | ) | | | (439 | ) | | Depreciation, depletion and amortization | | | (1,640 | ) | | | (825 | ) | | | (2,465 | ) | | Asset impairments | | | (1,110 | ) | | | (843 | ) | | | (1,953 | ) | | Accretion of asset retirement obligations | | | (47 | ) | | | (64 | ) | | | (111 | ) | | Income tax benefit (expense) | | | (510 | ) | | | 88 | | | | (422 | ) | | | | | | | | | | | | | Results of operations | | $ | 895 | | | $ | (233 | ) | | $ | 662 | | | | | | | | | | | | | | Depreciation, depletion and amortization per Boe | | $ | 8.69 | | | $ | 12.87 | | | $ | 9.75 | | | | | | | | | | | | | |
(1) | During 2014, Devon recognized a Canadian goodwill impairment, which is not reflected in these tables. See Note 5 for additional information. |
| | Year Ended December 31, 2017 | | | | U.S. | | | Canada | | | Total | | Oil, gas and NGL sales | | $ | 3,746 | | | $ | 1,404 | | | $ | 5,150 | | Production expenses | | | (1,232 | ) | | | (591 | ) | | | (1,823 | ) | Exploration expenses | | | (346 | ) | | | (34 | ) | | | (380 | ) | Depreciation, depletion and amortization | | | (1,050 | ) | | | (369 | ) | | | (1,419 | ) | Asset dispositions | | | 211 | | | | 1 | | | | 212 | | Accretion of asset retirement obligations | | | (38 | ) | | | (24 | ) | | | (62 | ) | Income tax expense | | | — | | | | (104 | ) | | | (104 | ) | Results of operations | | $ | 1,291 | | | $ | 283 | | | $ | 1,574 | | Depreciation, depletion and amortization per Boe | | $ | 6.97 | | | $ | 7.73 | | | $ | 7.15 | | | | | | | | | | | | | | | | | Year Ended December 31, 2016 | | | | U.S. | | | Canada | | | Total | | Oil, gas and NGL sales | | $ | 3,198 | | | $ | 984 | | | $ | 4,182 | | Production expenses | | | (1,313 | ) | | | (492 | ) | | | (1,805 | ) | Exploration expenses | | | (176 | ) | | | (39 | ) | | | (215 | ) | Depreciation, depletion and amortization | | | (1,066 | ) | | | (380 | ) | | | (1,446 | ) | Asset dispositions | | | 946 | | | | 1 | | | | 947 | | Asset impairments | | | (435 | ) | | | — | | | | (435 | ) | Accretion of asset retirement obligations | | | (49 | ) | | | (26 | ) | | | (75 | ) | Income tax expense | | | — | | | | (13 | ) | | | (13 | ) | Results of operations | | $ | 1,105 | | | $ | 35 | | | $ | 1,140 | | Depreciation, depletion and amortization per Boe | | $ | 6.11 | | | $ | 7.75 | | | $ | 6.47 | |
102
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Proved Reserves The following tables presenttable presents Devon’s estimated proved reserves by product and by country. | | | | | | | | | | | | | | | Oil (MMBbls) | | | | U.S. | | | Canada | | | Total | | Proved developed and undeveloped reserves: | | | | | December 31, 2012 | | | 205 | | | | 65 | | | | 270 | | Revisions due to prices | | | 1 | | | | (1 | ) | | | — | | Revisions other than price | | | (18 | ) | | | — | | | | (18 | ) | Extensions and discoveries | | | 69 | | | | 7 | | | | 76 | | Purchase of reserves | | | 1 | | | | — | | | | 1 | | Production | | | (28 | ) | | | (15 | ) | | | (43 | ) | Sale of reserves | | | (1 | ) | | | — | | | | (1 | ) | | | | | | | | | | | | | | December 31, 2013 | | | 229 | | | | 56 | | | | 285 | | Revisions due to prices | | | (1 | ) | | | — | | | | (1 | ) | Revisions other than price | | | (38 | ) | | | 1 | | | | (37 | ) | Extensions and discoveries | | | 94 | | | | 5 | | | | 99 | | Purchase of reserves | | | 132 | | | | — | | | | 132 | | Production | | | (48 | ) | | | (10 | ) | | | (58 | ) | Sale of reserves | | | (17 | ) | | | (29 | ) | | | (46 | ) | | | | | | | | | | | | | | December 31, 2014 | | | 351 | | | | 23 | | | | 374 | | Revisions due to prices | | | (53 | ) | | | 4 | | | | (49 | ) | Revisions other than price | | | (52 | ) | | | 2 | | | | (50 | ) | Extensions and discoveries | | | 51 | | | | 3 | | | | 54 | | Purchase of reserves | | | 5 | | | | — | | | | 5 | | Production | | | (60 | ) | | | (10 | ) | | | (70 | ) | | | | | | | | | | | | | | December 31, 2015 | | | 242 | | | | 22 | | | | 264 | | | | | | | | | | | | | | | Proved developed reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 166 | | | | 62 | | | | 228 | | December 31, 2013 | | | 194 | | | | 56 | | | | 250 | | December 31, 2014 | | | 255 | | | | 23 | | | | 278 | | December 31, 2015 | | | 203 | | | | 22 | | | | 225 | | Proved developed-producing reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 155 | | | | 56 | | | | 211 | | December 31, 2013 | | | 178 | | | | 51 | | | | 229 | | December 31, 2014 | | | 224 | | | | 19 | | | | 243 | | December 31, 2015 | | | 192 | | | | 19 | | | | 211 | | Proved undeveloped reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 39 | | | | 3 | | | | 42 | | December 31, 2013 | | | 35 | | | | — | | | | 35 | | December 31, 2014 | | | 96 | | | | — | | | | 96 | | December 31, 2015 | | | 39 | | | | — | | | | 39 | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | | | | | | | Bitumen | | | | | | | | | | | | | | | NGL | | | | | | | | | | | | | | | | Oil (MMBbls) | | | (MMBbls) | | | Gas (Bcf) | | | (MMBbls) | | | Combined (MMBoe) (1) | | | | U.S. | | | Canada | | | Total | | | Canada | | | U.S. | | | Canada | | | Total | | | U.S. | | | U.S. | | | Canada | | | Total | | Proved developed and undeveloped reserves: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | | 242 | | | | 22 | | | | 264 | | | | 520 | | | | 5,808 | | | | 13 | | | | 5,821 | | | | 428 | | | | 1,638 | | | | 544 | | | | 2,182 | | Revisions due to prices | | | (18 | ) | | | (2 | ) | | | (20 | ) | | | 23 | | | | (103 | ) | | | — | | | | (103 | ) | | | (13 | ) | | | (48 | ) | | | 21 | | | | (27 | ) | Revisions other than price | | | (2 | ) | | | 3 | | | | 1 | | | | (19 | ) | | | 628 | | | | 10 | | | | 638 | | | | 48 | | | | 151 | | | | (14 | ) | | | 137 | | Extensions and discoveries | | | 36 | | | | 2 | | | | 38 | | | | — | | | | 280 | | | | — | | | | 280 | | | | 42 | | | | 124 | | | | 2 | | | | 126 | | Purchase of reserves | | | 8 | | | | — | | | | 8 | | | | — | | | | 33 | | | | — | | | | 33 | | | | 7 | | | | 20 | | | | — | | | | 20 | | Production | | | (47 | ) | | | (8 | ) | | | (55 | ) | | | (40 | ) | | | (510 | ) | | | (7 | ) | | | (517 | ) | | | (42 | ) | | | (174 | ) | | | (49 | ) | | | (223 | ) | Sale of reserves | | | (25 | ) | | | — | | | | (25 | ) | | | — | | | | (521 | ) | | | — | | | | (521 | ) | | | (45 | ) | | | (157 | ) | | | — | | | | (157 | ) | December 31, 2016 | | | 194 | | | | 17 | | | | 211 | | | | 484 | | | | 5,615 | | | | 16 | | | | 5,631 | | | | 425 | | | | 1,554 | | | | 504 | | | | 2,058 | | Revisions due to prices | | | 12 | | | | (1 | ) | | | 11 | | | | (37 | ) | | | 398 | | | | 1 | | | | 399 | | | | 32 | | | | 111 | | | | (38 | ) | | | 73 | | Revisions other than price | | | 6 | | | | 2 | | | | 8 | | | | (10 | ) | | | — | | | | 2 | | | | 2 | | | | (10 | ) | | | (5 | ) | | | (7 | ) | | | (12 | ) | Extensions and discoveries | | | 90 | | | | 4 | | | | 94 | | | | 12 | | | | 403 | | | | — | | | | 403 | | | | 63 | | | | 221 | | | | 16 | | | | 237 | | Production | | | (42 | ) | | | (7 | ) | | | (49 | ) | | | (40 | ) | | | (433 | ) | | | (6 | ) | | | (439 | ) | | | (36 | ) | | | (150 | ) | | | (48 | ) | | | (198 | ) | Sale of reserves | | | (3 | ) | | | — | | | | (3 | ) | | | — | | | | (9 | ) | | | — | | | | (9 | ) | | | (1 | ) | | | (6 | ) | | | — | | | | (6 | ) | December 31, 2017 | | | 257 | | | | 15 | | | | 272 | | | | 409 | | | | 5,974 | | | | 13 | | | | 5,987 | | | | 473 | | | | 1,725 | | | | 427 | | | | 2,152 | | Revisions due to prices | | | 12 | | | | 1 | | | | 13 | | | | 10 | | | | 94 | | | | (3 | ) | | | 91 | | | | 12 | | | | 40 | | | | 11 | | | | 51 | | Revisions other than price | | | (10 | ) | | | 2 | | | | (8 | ) | | | 2 | | | | (163 | ) | | | (4 | ) | | | (167 | ) | | | (23 | ) | | | (60 | ) | | | 3 | | | | (57 | ) | Extensions and discoveries | | | 93 | | | | 5 | | | | 98 | | | | 7 | | | | 446 | | | | — | | | | 446 | | | | 64 | | | | 232 | | | | 11 | | | | 243 | | Production | | | (47 | ) | | | (7 | ) | | | (54 | ) | | | (35 | ) | | | (397 | ) | | | (4 | ) | | | (401 | ) | | | (39 | ) | | | (153 | ) | | | (42 | ) | | | (195 | ) | Sale of reserves | | | (7 | ) | | | — | | | | (7 | ) | | | — | | | | (1,195 | ) | | | — | | | | (1,195 | ) | | | (61 | ) | | | (267 | ) | | | — | | | | (267 | ) | December 31, 2018 | | | 298 | | | | 16 | | | | 314 | | | | 393 | | | | 4,759 | | | | 2 | | | | 4,761 | | | | 426 | | | | 1,517 | | | | 410 | | | | 1,927 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved developed reserves: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | | 203 | | | | 22 | | | | 225 | | | | 219 | | | | 5,694 | | | | 13 | | | | 5,707 | | | | 411 | | | | 1,563 | | | | 243 | | | | 1,806 | | December 31, 2016 | | | 160 | | | | 17 | | | | 177 | | | | 190 | | | | 5,361 | | | | 16 | | | | 5,377 | | | | 387 | | | | 1,439 | | | | 210 | | | | 1,649 | | December 31, 2017 | | | 178 | | | | 15 | | | | 193 | | | | 200 | | | | 5,619 | | | | 13 | | | | 5,632 | | | | 410 | | | | 1,524 | | | | 218 | | | | 1,742 | | December 31, 2018 | | | 198 | | | | 16 | | | | 214 | | | | 187 | | | | 4,331 | | | | 2 | | | | 4,333 | | | | 359 | | | | 1,278 | | | | 204 | | | | 1,482 | | Proved developed-producing reserves: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | | 192 | | | | 19 | | | | 211 | | | | 219 | | | | 5,546 | | | | 13 | | | | 5,559 | | | | 393 | | | | 1,509 | | | | 240 | | | | 1,749 | | December 31, 2016 | | | 143 | | | | 13 | | | | 156 | | | | 190 | | | | 5,243 | | | | 16 | | | | 5,259 | | | | 370 | | | | 1,386 | | | | 207 | | | | 1,593 | | December 31, 2017 | | | 165 | | | | 12 | | | | 177 | | | | 197 | | | | 5,512 | | | | 13 | | | | 5,525 | | | | 397 | | | | 1,481 | | | | 212 | | | | 1,693 | | December 31, 2018 | | | 189 | | | | 12 | | | | 201 | | | | 187 | | | | 4,261 | | | | 2 | | | | 4,263 | | | | 349 | | | | 1,249 | | | | 199 | | | | 1,448 | | Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | | 39 | | | | — | | | | 39 | | | | 301 | | | | 114 | | | | — | | | | 114 | | | | 17 | | | | 75 | | | | 301 | | | | 376 | | December 31, 2016 | | | 34 | | | | — | | | | 34 | | | | 294 | | | | 254 | | | | — | | | | 254 | | | | 38 | | | | 115 | | | | 294 | | | | 409 | | December 31, 2017 | | | 79 | | | | — | | | | 79 | | | | 209 | | | | 355 | | | | — | | | | 355 | | | | 63 | | | | 201 | | | | 209 | | | | 410 | | December 31, 2018 | | | 100 | | | | — | | | | 100 | | | | 206 | | | | 428 | | | | — | | | | 428 | | | | 67 | | | | 239 | | | | 206 | | | | 445 | |
| | | | | | | | | | | | | | | Bitumen (MMBbls) | | | | U.S. | | | Canada | | | Total | | Proved developed and undeveloped reserves: | | | | | December 31, 2012 | | | — | | | | 528 | | | | 528 | | Revisions due to prices | | | — | | | | (11 | ) | | | (11 | ) | Revisions other than price | | | — | | | | 16 | | | | 16 | | Extensions and discoveries | | | — | | | | 38 | | | | 38 | | Production | | | — | | | | (19 | ) | | | (19 | ) | | | | | | | | | | | | | | December 31, 2013 | | | — | | | | 552 | | | | 552 | | Revisions due to prices | | | — | | | | (37 | ) | | | (37 | ) | Revisions other than price | | | — | | | | 18 | | | | 18 | | Extensions and discoveries | | | — | | | | 8 | | | | 8 | | Production | | | — | | | | (20 | ) | | | (20 | ) | | | | | | | | | | | | | | December 31, 2014 | | | — | | | | 521 | | | | 521 | | Revisions due to prices | | | — | | | | 103 | | | | 103 | | Revisions other than price | | | — | | | | (84 | ) | | | (84 | ) | Extensions and discoveries | | | — | | | | 11 | | | | 11 | | Production | | | — | | | | (31 | ) | | | (31 | ) | | | | | | | | | | | | | | December 31, 2015 | | | — | | | | 520 | | | | 520 | | | | | | | | | | | | | | | Proved developed reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | — | | | | 99 | | | | 99 | | December 31, 2013 | | | — | | | | 111 | | | | 111 | | December 31, 2014 | | | — | | | | 137 | | | | 137 | | December 31, 2015 | | | — | | | | 219 | | | | 219 | | Proved developed-producing reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | — | | | | 99 | | | | 99 | | December 31, 2013 | | | — | | | | 111 | | | | 111 | | December 31, 2014 | | | — | | | | 137 | | | | 137 | | December 31, 2015 | | | — | | | | 219 | | | | 219 | | Proved undeveloped reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | — | | | | 429 | | | | 429 | | December 31, 2013 | | | — | | | | 441 | | | | 441 | | December 31, 2014 | | | — | | | | 384 | | | | 384 | | December 31, 2015 | | | — | | | | 301 | | | | 301 | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | | | | | | | | Gas (Bcf) | | | | U.S. | | | Canada | | | Total | | Proved developed and undeveloped reserves: | | | | | December 31, 2012 | | | 8,762 | | | | 684 | | | | 9,446 | | Revisions due to prices | | | 405 | | | | 161 | | | | 566 | | Revisions other than price | | | (299 | ) | | | 67 | | | | (232 | ) | Extensions and discoveries | | | 471 | | | | 19 | | | | 490 | | Purchase of reserves | | | 1 | | | | — | | | | 1 | | Production | | | (709 | ) | | | (165 | ) | | | (874 | ) | Sale of reserves | | | (81 | ) | | | (8 | ) | | | (89 | ) | | | | | | | | | | | | | | December 31, 2013 | | | 8,550 | | | | 758 | | | | 9,308 | | Revisions due to prices | | | 191 | | | | 45 | | | | 236 | | Revisions other than price | | | (299 | ) | | | 4 | | | | (295 | ) | Extensions and discoveries | | | 335 | | | | 8 | | | | 343 | | Purchase of reserves | | | 457 | | | | — | | | | 457 | | Production | | | (660 | ) | | | (41 | ) | | | (701 | ) | Sale of reserves | | | (923 | ) | | | (738 | ) | | | (1,661 | ) | | | | | | | | | | | | | | December 31, 2014 | | | 7,651 | | | | 36 | | | | 7,687 | | Revisions due to prices | | | (1,412 | ) | | | (9 | ) | | | (1,421 | ) | Revisions other than price | | | (3 | ) | | | (6 | ) | | | (9 | ) | Extensions and discoveries | | | 171 | | | | — | | | | 171 | | Purchase of reserves | | | 17 | | | | — | | | | 17 | | Production | | | (579 | ) | | | (8 | ) | | | (587 | ) | Sale of reserves | | | (37 | ) | | | — | | | | (37 | ) | | | | | | | | | | | | | | December 31, 2015 | | | 5,808 | | | | 13 | | | | 5,821 | | | | | | | | | | | | | | | Proved developed reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 7,391 | | | | 679 | | | | 8,070 | | December 31, 2013 | | | 7,707 | | | | 752 | | | | 8,459 | | December 31, 2014 | | | 6,948 | | | | 36 | | | | 6,984 | | December 31, 2015 | | | 5,694 | | | | 13 | | | | 5,707 | | Proved developed-producing reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 7,091 | | | | 624 | | | | 7,715 | | December 31, 2013 | | | 7,425 | | | | 680 | | | | 8,105 | | December 31, 2014 | | | 6,746 | | | | 34 | | | | 6,780 | | December 31, 2015 | | | 5,546 | | | | 13 | | | | 5,559 | | Proved undeveloped reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 1,371 | | | | 5 | | | | 1,376 | | December 31, 2013 | | | 843 | | | | 6 | | | | 849 | | December 31, 2014 | | | 703 | | | | — | | | | 703 | | December 31, 2015 | | | 114 | | | | — | | | | 114 | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | | | | | | | | Natural Gas Liquids (MMBbls) | | | | U.S. | | | Canada | | | Total | | Proved developed and undeveloped reserves: | | | | | December 31, 2012 | | | 571 | | | | 20 | | | | 591 | | Revisions due to prices | | | 8 | | | | 3 | | | | 11 | | Revisions other than price | | | (50 | ) | | | 3 | | | | (47 | ) | Extensions and discoveries | | | 64 | | | | 1 | | | | 65 | | Production | | | (41 | ) | | | (4 | ) | | | (45 | ) | | | | | | | | | | | | | | December 31, 2013 | | | 552 | | | | 23 | | | | 575 | | Revisions due to prices | | | 7 | | | | 1 | | | | 8 | | Revisions other than price | | | 2 | | | | — | | | | 2 | | Extensions and discoveries | | | 47 | | | | — | | | | 47 | | Purchase of reserves | | | 57 | | | | — | | | | 57 | | Production | | | (50 | ) | | | (1 | ) | | | (51 | ) | Sale of reserves | | | (37 | ) | | | (23 | ) | | | (60 | ) | | | | | | | | | | | | | | December 31, 2014 | | | 578 | | | | — | | | | 578 | | Revisions due to prices | | �� | (119 | ) | | | — | | | | (119 | ) | Revisions other than price | | | (6 | ) | | | — | | | | (6 | ) | Extensions and discoveries | | | 24 | | | | — | | | | 24 | | Purchase of reserves | | | 1 | | | | — | | | | 1 | | Production | | | (50 | ) | | | — | | | | (50 | ) | | | | | | | | | | | | | | December 31, 2015 | | | 428 | | | | — | | | | 428 | | | | | | | | | | | | | | | Proved developed reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 431 | | | | 20 | | | | 451 | | December 31, 2013 | | | 468 | | | | 23 | | | | 491 | | December 31, 2014 | | | 486 | | | | — | | | | 486 | | December 31, 2015 | | | 411 | | | | — | | | | 411 | | Proved developed-producing reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 406 | | | | 19 | | | | 425 | | December 31, 2013 | | | 442 | | | | 21 | | | | 463 | | December 31, 2014 | | | 467 | | | | — | | | | 467 | | December 31, 2015 | | | 393 | | | | — | | | | 393 | | Proved undeveloped reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 140 | | | | — | | | | 140 | | December 31, 2013 | | | 84 | | | | — | | | | 84 | | December 31, 2014 | | | 92 | | | | — | | | | 92 | | December 31, 2015 | | | 17 | | | | — | | | | 17 | |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | | | | | | | | Total (MMBoe)(1) | | | | U.S. | | | Canada | | | Total | | Proved developed and undeveloped reserves: | | | | | December 31, 2012 | | | 2,236 | | | | 727 | | | | 2,963 | | Revisions due to prices | | | 76 | | | | 18 | | | | 94 | | Revisions other than price | | | (117 | ) | | | 29 | | | | (88 | ) | Extensions and discoveries | | | 212 | | | | 49 | | | | 261 | | Purchase of reserves | | | 1 | | | | — | | | | 1 | | Production | | | (189 | ) | | | (64 | ) | | | (253 | ) | Sale of reserves | | | (14 | ) | | | (1 | ) | | | (15 | ) | | | | | | | | | | | | | | December 31, 2013 | | | 2,205 | | | | 758 | | | | 2,963 | | Revisions due to prices | | | 38 | | | | (29 | ) | | | 9 | | Revisions other than price | | | (86 | ) | | | 21 | | | | (65 | ) | Extensions and discoveries | | | 197 | | | | 14 | | | | 211 | | Purchase of reserves | | | 265 | | | | — | | | | 265 | | Production | | | (207 | ) | | | (39 | ) | | | (246 | ) | Sale of reserves | | | (207 | ) | | | (176 | ) | | | (383 | ) | | | | | | | | | | | | | | December 31, 2014 | | | 2,205 | | | | 549 | | | | 2,754 | | Revisions due to prices | | | (408 | ) | | | 106 | | | | (302 | ) | Revisions other than price | | | (59 | ) | | | (83 | ) | | | (142 | ) | Extensions and discoveries | | | 104 | | | | 14 | | | | 118 | | Purchase of reserves | | | 9 | | | | — | | | | 9 | | Production | | | (206 | ) | | | (42 | ) | | | (248 | ) | Sale of reserves | | | (7 | ) | | | — | | | | (7 | ) | | | | | | | | | | | | | | December 31, 2015 | | | 1,638 | | | | 544 | | | | 2,182 | | | | | | | | | | | | | | | Proved developed reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 1,829 | | | | 294 | | | | 2,123 | | December 31, 2013 | | | 1,947 | | | | 315 | | | | 2,262 | | December 31, 2014 | | | 1,900 | | | | 165 | | | | 2,065 | | December 31, 2015 | | | 1,563 | | | | 243 | | | | 1,806 | | Proved developed-producing reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 1,743 | | | | 278 | | | | 2,021 | | December 31, 2013 | | | 1,857 | | | | 297 | | | | 2,154 | | December 31, 2014 | | | 1,815 | | | | 162 | | | | 1,977 | | December 31, 2015 | | | 1,509 | | | | 240 | | | | 1,749 | | Proved undeveloped reserves as of: | | | | | | | | | | | | | December 31, 2012 | | | 407 | | | | 433 | | | | 840 | | December 31, 2013 | | | 258 | | | | 443 | | | | 701 | | December 31, 2014 | | | 305 | | | | 384 | | | | 689 | | December 31, 2015 | | | 75 | | | | 301 | | | | 376 | |
(1) | Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and NGL reserves are converted to Boe on a one-to-one basis with oil. |
103
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Proved Undeveloped Reserves The following table presents the changes in Devon’s total proved undeveloped reserves during 20152018 (MMBoe). | | | | | | | | U.S. | | | Canada | | | Total | | | | U.S. | | | Canada | | | Total | | | Proved undeveloped reserves as of December 31, 2014 | | | 305 | | | | 384 | | | | 689 | | | Proved undeveloped reserves as of December 31, 2017 | | | | 201 | | | | 209 | | | | 410 | | Extensions and discoveries | | | 13 | | | | 11 | | | | 24 | | | | 107 | | | | 6 | | | | 113 | | Revisions due to prices | | | (115 | ) | | | 80 | | | | (35 | ) | | | 1 | | | | 6 | | | | 7 | | Revisions other than price | | | (40 | ) | | | (80 | ) | | | (120 | ) | | | (8 | ) | | | (15 | ) | | | (23 | ) | Sale of reserves | | | | (10 | ) | | | — | | | | (10 | ) | Conversion to proved developed reserves | | | (88 | ) | | | (94 | ) | | | (182 | ) | | | (52 | ) | | | — | | | | (52 | ) | | | | | | | | | | | | Proved undeveloped reserves as of December 31, 2015 | | | 75 | | | | 301 | | | | 376 | | | | | | | | | | | | | | Proved undeveloped reserves as of December 31, 2018 | | | | 239 | | | | 206 | | | | 445 | |
Proved
Total proved undeveloped reserves decreased 45%increased 9% from year-end 20142017 to year-end 2015, and2018 with the year-end 20152018 balance represents 17%representing 23% of total proved reserves. DrillingDevon’s focus on drilling and development activities increased Devon’s proved undeveloped reserves 24in the STACK and Delaware Basin was the primary driver of the 113 MMBoe in extensions and resulteddiscoveries. Continued development primarily in the STACK and Delaware Basin led to the conversion of 18252 MMBoe, or 26%, of the 20142017 U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $2.2 billion$691 million for 2015. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 120 MMBoe primarily due to evaluations of certain properties in the U.S. and Canada. The largest revisions, which reduced reserves by 80 MMBoe, relate to evaluations of Jackfish bitumen reserves. Of the 40 MMBoe revisions recorded for U.S. properties, a reduction of approximately 27 MMBoe represents reserves that Devon now does not expect to develop in the next five years, including 20 MMBoe attributable to the Eagle Ford.2018. A significant amount of Devon’s proved undeveloped reserves at the end of 20152018 related to its Jackfish operations. At December 31, 20152018 and 2014,2017, Devon’s Jackfish proved undeveloped reserves were 301206 MMBoe and 384209 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35 MBbl daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves the up-front construction of steam injection/distribution and bitumen processing facilities. Due to the large up-front capital investments and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than 5five years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends through to 2030.2032. At the end of 2015,2018, approximately 184125 MMBoe of proved undeveloped reserves at Jackfish have remained undeveloped for five years or more since the initial booking. No other projects have proved undeveloped reserves that have remained undeveloped more than five years from the initial booking of the reserves. Furthermore, approximately 18081 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop. 104
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Price Revisions 2015 –Reserves increased 40 MMBoe in the U.S. primarily due to price increases in the trailing 12 month average for oil, gas and NGLs in 2018. Reserves increased 11 MMBoe in Canada due to a decrease in the trailing 12 month average price for bitumen in 2018. The decreased price has the effect of decreasing the applicable royalties, which increases the after-royalty volumes.
Reserves increased 111 MMBoe in the U.S. primarily due to significant price increases in the trailing 12 month average for oil, gas and NGLs in 2017. Reserves decreased 30238 MMBoe in Canada due to a significant increase in the trailing 12 month average price for bitumen in 2017. The increased price has the effect of increasing the royalties, which decreases the after-royalty volumes. Reserves decreased 27 MMBoe during 2016 primarily due to lower commodity prices across all products.for oil and gas. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes. 2014 – Reserves increased 9 MMBoe primarily due to higher gas prices in the Barnett Shale and the Anadarko Basin, partially offset by higher bitumen prices, which result in lower after-royalty volumes, in Canada.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
2013 – Reserves increased 94 MMBoe primarily due to higher gas prices. Of this increase, 43 MMBoe related to the Barnett Shale and 19 MMBoe related to the Rocky Mountain area.
Revisions Other Than Price Total revisions other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish are primarily due to a refined reserves methodology that resulted in a reduced recovery factor. Revisions other than price in 2014 and 20132018 primarily related to Devon’s evaluation of certain oil and dry gas regions, with the largest revisions being made in the Cana-WoodfordSTACK. Total revisions other than price in 2016 primarily related to Devon’s evaluation of certain dry gas regions and NGLs, with the largest revisions being made in the Barnett Shale and Barnett Shale.STACK (Cana-Woodford Shale). Extensions and Discoveries 20152018 – Of Approximately 72% of the 118 MMBoe of extensionsadditions were through our focused efforts in the STACK (87 MMBoe) and discoveries, 38 MMBoe related to the Delaware Basin 30 MMBoe related to(88 MMBoe). The remaining extensions were added throughout the Anadarko Basin, 21 MMBoe related to the Eagle Ford and 11 MMBoe related to Jackfish.remainder of Devon’s portfolio.
The 20152018 extensions and discoveries included 1321 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 11 MMBoe at Jackfish. 2014 – Of the 211 MMBoe of extensions and discoveries, 70 MMBoe relatedrelating to the PermianSTACK.
2017 – Over 80% of the additions were through our focused efforts in the STACK (120 MMBoe) and the Delaware Basin 54 MMBoe related to(79 MMBoe). The remaining extensions were added throughout the Eagle Ford, 36 MMBoe related to the Barnett Shale, 14 MMBoe related to the Anadarko Basin, 8 MMBoe related to Jackfish and 14 MMBoe related to the Mississippian-Woodford Trend.remainder of Devon’s portfolio. The 20142017 extensions and discoveries included 566 MMBoe related to additions from Devon’s infill drilling activities primarily consisting of 4 MMBoe atrelated to the Permian Basin.STACK. 20132016 – Of the 261126 MMBoe of extensions and discoveries, 7697 MMBoe related to STACK, 18 MMBoe related to the PermianDelaware Basin 54and 7 MMBoe related to the Barnett Shale, 42 MMBoe related to the Anadarko Basin, 38 MMBoe related to Jackfish and 32 MMBoe related to the Mississippian-Woodford Trend.Eagle Ford.
The 20132016 extensions and discoveries included 17574 MMBoe related to additions from Devon’s infill drilling activities including 23 MMBoe atprimarily related to the Cana-Woodford Shale, 54 MMBoe at the Barnett Shale, 38 MMBoe at Jackfish, 33 MMBoe at the Permian Basin and 20 MMBoe at the Mississippian-Woodford Trend.STACK. Purchase of Reserves 20152016 – Of the 9 MMBoe of reserves purchases, 6 MMBoe Primarily related to Devon’s acquisition in the Powder River Basin.STACK play.
2014 – Of the 265 MMBoe105
Table of reserves purchases, 246 MMBoe relatedContents Index to Devon’s GeoSouthern acquisition in the Eagle Ford.Financial Statements Sale of Reserves
2015 – The 7 MMBoe of reserves sales related to Devon’s asset divestitures in the San Juan Basin.
2014 – The total 383 MMBoe of reserves sales related to Devon’s asset divestitures in the U.S. and Canada.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Sale of Reserves Related to Devon’s 2018, 2017 and 2016 U.S. non-core asset divestitures as discussed further in Note 2. Standardized Measure The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves. | | | | | | | | Year Ended December 31, 2018 | | | | | U.S. | | | Canada | | | Total | | Future cash inflows | | | $ | 40,183 | | | $ | 9,146 | | | $ | 49,329 | | Future costs: | | | | | | | | | | | | | | Development | | | | (3,444 | ) | | | (1,558 | ) | | | (5,002 | ) | Production | | | | (18,107 | ) | | | (5,445 | ) | | | (23,552 | ) | Future income tax expense | | | | (2,969 | ) | | | — | | | | (2,969 | ) | Future net cash flow | | | | 15,663 | | | | 2,143 | | | | 17,806 | | 10% discount to reflect timing of cash flows | | | | (6,897 | ) | | | (717 | ) | | | (7,614 | ) | Standardized measure of discounted future net cash flows | | | $ | 8,766 | | | $ | 1,426 | | | $ | 10,192 | | | | Year Ended December 31, 2015 | | | | | | | | | | | | | | | | U.S. | | | Canada | | | Total | | | Year Ended December 31, 2017 | | | | (Millions) | | | U.S. | | | Canada | | | Total | | Future cash inflows | | $ | 27,398 | | | $ | 13,047 | | | $ | 40,445 | | | $ | 34,701 | | | $ | 13,602 | | | $ | 48,303 | | Future costs: | | | | | | | | | | | | | | | | | | | Development | | | (3,306 | ) | | | (2,759 | ) | | | (6,065 | ) | | | (3,316 | ) | | | (1,853 | ) | | | (5,169 | ) | Production | | | (17,251 | ) | | | (6,891 | ) | | | (24,142 | ) | | | (15,526 | ) | | | (5,986 | ) | | | (21,512 | ) | Future income tax expense | | | — | | | | (475 | ) | | | (475 | ) | | | — | | | | (988 | ) | | | (988 | ) | | | | | | | | | | | | Future net cash flow | | | 6,841 | | | | 2,922 | | | | 9,763 | | | | 15,859 | | | | 4,775 | | | | 20,634 | | 10% discount to reflect timing of cash flows | | | (1,973 | ) | | | (1,102 | ) | | | (3,075 | ) | | | (7,541 | ) | | | (1,756 | ) | | | (9,297 | ) | | | | | | | | | | | | Standardized measure of discounted future net cash flows | | $ | 4,868 | | | $ | 1,820 | | | $ | 6,688 | | | $ | 8,318 | | | $ | 3,019 | | | $ | 11,337 | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2016 | | | | | U.S. | | | Canada | | | Total | | Future cash inflows | | | $ | 22,847 | | | $ | 9,672 | | | $ | 32,519 | | Future costs: | | | | | | | | | | | | | | Development | | | | (2,784 | ) | | | (2,201 | ) | | | (4,985 | ) | Production | | | | (11,934 | ) | | | (6,049 | ) | | | (17,983 | ) | Future income tax expense | | | | — | | | | (121 | ) | | | (121 | ) | Future net cash flow | | | | 8,129 | | | | 1,301 | | | | 9,430 | | 10% discount to reflect timing of cash flows | | | | (3,524 | ) | | | (466 | ) | | | (3,990 | ) | Standardized measure of discounted future net cash flows | | | $ | 4,605 | | | $ | 835 | | | $ | 5,440 | |
| | | | | | | | | | | | | | | Year Ended December 31, 2014 | | | | U.S. | | | Canada | | | Total | | | | (Millions) | | Future cash inflows | | $ | 75,847 | | | $ | 31,371 | | | $ | 107,218 | | Future costs: | | | | | | | | | | | | | Development | | | (7,168 | ) | | | (3,619 | ) | | | (10,787 | ) | Production | | | (29,740 | ) | | | (14,232 | ) | | | (43,972 | ) | Future income tax expense | | | (11,021 | ) | | | (3,026 | ) | | | (14,047 | ) | | | | | | | | | | | | | | Future net cash flow | | | 27,918 | | | | 10,494 | | | | 38,412 | | 10% discount to reflect timing of cash flows | | | (12,819 | ) | | | (5,119 | ) | | | (17,938 | ) | | | | | | | | | | | | | | Standardized measure of discounted future net cash flows | | $ | 15,099 | | | $ | 5,375 | | | $ | 20,474 | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Year Ended December 31, 2013 | | | | U.S. | | | Canada | | | Total | | | | (Millions) | | Future cash inflows | | $ | 61,983 | | | $ | 33,305 | | | $ | 95,288 | | Future costs: | | | | | | | | | | | | | Development | | | (5,448 | ) | | | (5,308 | ) | | | (10,756 | ) | Production | | | (26,663 | ) | | | (15,709 | ) | | | (42,372 | ) | Future income tax expense | | | (9,046 | ) | | | (2,327 | ) | | | (11,373 | ) | | | | | | | | | | | | | | Future net cash flow | | | 20,826 | | | | 9,961 | | | | 30,787 | | 10% discount to reflect timing of cash flows | | | (10,346 | ) | | | (4,700 | ) | | | (15,046 | ) | | | | | | | | | | | | | | Standardized measure of discounted future net cash flows | | $ | 10,480 | | | $ | 5,261 | | | $ | 15,741 | | | | | | | | | | | | | | |
Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 20152018 estimates, Devon’s future realized prices were assumed to be $44.33$58.64 per Bbl of oil, $23.84$22.12 per Bbl of bitumen, $2.06$2.45 per Mcf of gas and $10.11$24.72 per Bbl of NGLs. Of the $6.1$5.0 billion of future development costs as of the end of 2015, $0.62018, $1.2 billion, $0.6 billion and $0.4$0.3 billion are estimated to be spent in 2016, 20172019, 2020 and 2018,2021, respectively. 106
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Future development costs include not only development costs but also future asset retirement costs. Included as part of the $6.1$5.0 billion of future development costs are $1.2$1.4 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws. The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows: | | | Year Ended December 31, | | | | | 2015 | | 2014 | | 2013 | | | Year Ended December 31, | | | | (Millions) | | | 2018 | | | 2017 | | | 2016 | | Beginning balance | | $ | 20,474 | | | $ | 15,741 | | | $ | 13,221 | | | $ | 11,337 | | | $ | 5,440 | | | $ | 7,883 | | Net changes in prices and production costs | | | (20,756 | ) | | | 2,561 | | | | 3,018 | | | | (243 | ) | | | 5,218 | | | | (2,027 | ) | Oil, bitumen, gas and NGL sales, net of production costs | | | (2,704 | ) | | | (6,865 | ) | | | (5,613 | ) | | | (3,452 | ) | | | (3,327 | ) | | | (2,377 | ) | Changes in estimated future development costs | | | 1,313 | | | | (768 | ) | | | 399 | | | | (216 | ) | | | 789 | | | | 112 | | Extensions and discoveries, net of future development costs | | | 1,129 | | | | 4,836 | | | | 4,047 | | | | 3,139 | | | | 2,497 | | | | 674 | | Purchase of reserves | | | 95 | | | | 6,422 | | | | 14 | | | | — | | | | 2 | | | | 224 | | Sales of reserves in place | | | (79 | ) | | | (2,384 | ) | | | (44 | ) | | | (588 | ) | | | (3 | ) | | | (577 | ) | Revisions of quantity estimates | | | (1,451 | ) | | | (746 | ) | | | (1,040 | ) | | | (414 | ) | | | (318 | ) | | | (21 | ) | Previously estimated development costs incurred during the period | | | 2,158 | | | | 1,933 | | | | 1,986 | | | | 962 | | | | 559 | | | | 663 | | Accretion of discount | | | 567 | | | | 1,746 | | | | 1,940 | | | | 960 | | | | 1,034 | | | | 537 | | Foreign exchange and other | | | (1,254 | ) | | | (107 | ) | | | (583 | ) | | | (329 | ) | | | (7 | ) | | | 72 | | Net change in income taxes | | | 7,196 | | | | (1,895 | ) | | | (1,604 | ) | | | (964 | ) | | | (547 | ) | | | 277 | | | | | | | | | | | | | Ending balance | | $ | 6,688 | | | $ | 20,474 | | | $ | 15,741 | | | $ | 10,192 | | | $ | 11,337 | | | $ | 5,440 | | | | | | | | | | | | |
22.24. | Supplemental Quarterly Financial Information (Unaudited) |
The following tables present a summary of Devon’s unaudited interim results of operations. | | | | | | | | | | | | | | | | | | | | | | | 2015 | | | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | Full Year | | | | (Millions, except per share amounts) | | Operating revenues | | $ | 3,265 | | | $ | 3,393 | | | $ | 3,601 | | | $ | 2,886 | | | $ | 13,145 | | Loss before income taxes | | $ | (5,624 | ) | | $ | (4,479 | ) | | $ | (5,623 | ) | | $ | (5,542 | ) | | $ | (21,268 | ) | Net loss attributable to Devon | | $ | (3,599 | ) | | $ | (2,816 | ) | | $ | (3,507 | ) | | $ | (4,532 | ) | | $ | (14,454 | ) | Basic net loss per share attributable to Devon | | $ | (8.88 | ) | | $ | (6.94 | ) | | $ | (8.64 | ) | | $ | (11.12 | ) | | $ | (35.55 | ) | Diluted net loss per share attributable to Devon | | $ | (8.88 | ) | | $ | (6.94 | ) | | $ | (8.64 | ) | | $ | (11.12 | ) | | $ | (35.55 | ) | | | | | 2014 | | | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | Full Year | | | | (Millions, except per share amounts) | | Operating revenues | | $ | 3,725 | | | $ | 4,510 | | | $ | 5,336 | | | $ | 5,995 | | | $ | 19,566 | | Earnings before income taxes | | $ | 560 | | | $ | 1,554 | | | $ | 1,654 | | | $ | 291 | | | $ | 4,059 | | Net earnings (loss) attributable to Devon | | $ | 324 | | | $ | 675 | | | $ | 1,016 | | | $ | (408 | ) | | $ | 1,607 | | Basic net earnings (loss) per share attributable to Devon | | $ | 0.80 | | | $ | 1.65 | | | $ | 2.48 | | | $ | (1.01 | ) | | $ | 3.93 | | Diluted net earnings (loss) per share attributable to Devon | | $ | 0.79 | | | $ | 1.64 | | | $ | 2.47 | | | $ | (1.01 | ) | | $ | 3.91 | |
| | 2018 | | | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | Full Year | | Total revenues | | $ | 2,198 | | | $ | 2,249 | | | $ | 2,579 | | | $ | 3,708 | | | $ | 10,734 | | Asset dispositions (1) | | $ | (12 | ) | | $ | 23 | | | $ | (6 | ) | | $ | (268 | ) | | $ | (263 | ) | Earnings (loss) from continuing operations before income taxes (2) | | $ | (245 | ) | | $ | (481 | ) | | $ | 162 | | | $ | 1,484 | | | $ | 920 | | Net earnings (loss) from continuing operations | | $ | (211 | ) | | $ | (474 | ) | | $ | 300 | | | $ | 1,149 | | | $ | 764 | | Net earnings from discontinued operations, net of income tax expense (3) | | $ | 58 | | | $ | 139 | | | $ | 2,263 | | | $ | — | | | $ | 2,460 | | Net earnings (loss) attributable to Devon | | $ | (197 | ) | | $ | (425 | ) | | $ | 2,537 | | | $ | 1,149 | | | $ | 3,064 | | Basic net earnings (loss) per share attributable to Devon | | $ | (0.38 | ) | | $ | (0.83 | ) | | $ | 5.17 | | | $ | 2.50 | | | $ | 6.14 | | Diluted net earnings (loss) per share attributable to Devon | | $ | (0.38 | ) | | $ | (0.83 | ) | | $ | 5.14 | | | $ | 2.48 | | | $ | 6.10 | |
| | 2017 | | | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | Full Year | | Total revenues | | $ | 2,400 | | | $ | 2,165 | | | $ | 1,933 | | | $ | 2,380 | | | $ | 8,878 | | Asset dispositions (1) | | $ | (8 | ) | | $ | (22 | ) | | $ | (170 | ) | | $ | (17 | ) | | $ | (217 | ) | Earnings from continuing operations before income taxes | | $ | 313 | | | $ | 207 | | | $ | 207 | | | $ | 46 | | | $ | 773 | | Net earnings from continuing operations | | $ | 308 | | | $ | 212 | | | $ | 194 | | | $ | 44 | | | $ | 758 | | Net earnings from discontinued operations, net of income tax expense | | $ | 9 | | | $ | 33 | | | $ | 18 | | | $ | 260 | | | $ | 320 | | Net earnings attributable to Devon | | $ | 303 | | | $ | 219 | | | $ | 193 | | | $ | 183 | | | $ | 898 | | Basic net earnings per share attributable to Devon | | $ | 0.58 | | | $ | 0.41 | | | $ | 0.37 | | | $ | 0.35 | | | $ | 1.71 | | Diluted net earnings per share attributable to Devon | | $ | 0.58 | | | $ | 0.41 | | | $ | 0.37 | | | $ | 0.35 | | | $ | 1.70 | |
(1) | Additional discussion regarding asset dispositions can be found in Note 2. |
107
Table of Contents Index to Financial Statements DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) (2) | Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset impairments can be found in Note 5. |
(3) | Includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner of approximately $2.2 billion (after-tax) in the third quarter of 2018, as discussed in Note 19. |
Net Earnings (Loss) Attributable108
Table of Contents Index to DevonFinancial Statements The 2015 quarterly results include asset impairments of $5.5 billion (or $13.46 per diluted share), $4.2 billion (or $10.27 per diluted share), $5.9 billion ($14.41 per diluted share) and $5.3 billion (or $13.09 per diluted share) for the first quarter through the fourth quarter of 2015, respectively, as discussed in Note 5.
The fourth quarter of 2014 includes asset impairments of $1.9 billion (or $4.79 per diluted share) as discussed in Note 5.
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not Applicable.applicable. Item 9A.Controls and Procedures Disclosure Controls and Procedures We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors. Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 20152018 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms. Management’s Annual Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control – Integrated Frameworkissued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (the “2013 COSO Framework”). Based on this evaluation under the 2013 COSO Framework, which was completed on February 17, 2016,20, 2019, management concluded that its internal control over financial reporting was effective as of December 31, 2015.2018. The effectiveness of our internal control over financial reporting as of December 31, 20152018 has been audited by KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as of and for the year ended December 31, 2015,2018, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” of this report. Changes in Internal Control Over Financial Reporting There was no change in our internal control over financial reporting during the fourth quarter of 20152018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Item 9B.Other Information Not Applicable. applicable.
109
Table of Contents Index to Financial Statements PART III Item 10.Directors, Executive Officers and Corporate Governance The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.120 days following the fiscal year ended December 31, 2018. Item 11.Executive Compensation The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.120 days following the fiscal year ended December 31, 2018. Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.120 days following the fiscal year ended December 31, 2018. Item 13.Certain Relationships and Related Transactions, and Director Independence The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016.120 days following the fiscal year ended December 31, 2018. Item 14.Principal Accountant Fees and Services The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 notno later than April 29, 2016. 120 days following the fiscal year ended December 31, 2018.
110
Table of Contents Index to Financial Statements PART IV Item 15.Exhibits and Financial Statement Schedules (a) The following documents are filedincluded as part of this report: 1. Consolidated Financial Statements Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at “Item 8. Financial Statements and Supplementary Data” in this report. 2. Consolidated Financial Statement Schedules All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated financial statements or notes thereto. 3. Exhibits Exhibit No. | | Description | Exhibit No.
| | Description
| 2.1 | | 1.1 | | UnderwritingPurchase Agreement, dated June 11, 2015,7, 2018, by and among Registrant and Goldman, Sachs & Co. and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed June 16, 2015; File No. 001-32318). | | | 1.2 | | Underwriting Agreement dated December 10, 2015, by and among Registrant and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed December 15, 2015; File No. 001-32318). | | | 2.1 | | Agreement and Plan of Merger dated October 21, 2013, by and among Registrant, Devon Gas Services, L.P., Acacia Natural and Southwestern Gas Corp I, Inc., Crosstex Energy, Inc., New Public RangersPipeline, L.L.C., Boomer Merger Sub, Inc.as sellers, and Rangers Merger Sub, Inc. (incorporatedEnlink Midstream Manager, LLC, Registrant, and GIP III Stetson I, L.P. and GIP III Stetson II, L.P., as acquirors (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed October 22, 2013;June 7, 2018; File No. 001-32318)001-32318). | | | | 2.2 3.1 | | Contribution Agreement dated October 21, 2013, by and among Registrant, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc., Crosstex Energy, L.P. and Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 2.2 to Registrant’s Form 8-K filed October 22, 2013; File No. 001-32318). | | | 2.3 | | Purchase and Sale Agreement dated November 20, 2013, among GeoSouthern Intermediate Holdings, LLC, GeoSouthern Energy Corporation (solely with respect to certain sections specified therein), and Devon Energy Production Company, L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K/A filed May 19, 2014; File No. 001-32318). | | | 2.4 | | Letter Agreement dated February 28, 2014 amending certain provisions of the Purchase and Sale Agreement dated November 20, 2013 among GeoSouthern Intermediate Holdings, LLC, GeoSouthern Energy Corporation and Devon Energy Production Company, L.P (incorporated by reference to Exhibit 2.4 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318). | | | 3.1 | | Registrant’s Restated Certificate of Incorporation (incorporated(incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-K for the fiscal year ending December 31, 2012;filed February 21, 2013; File No. 001-32318)001-32318). | | | | 3.2 | | Registrant’s Bylaws (incorporated(incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed January 27, 2016; File No. 001-32318)001-32318). | | | 4.1 | | Registration Rights Agreement dated January 7, 2016, among Registrant and EnCap FEx Holdings, LLC, Felix Stack Investments, LLC, Felix STACK Holdings, LLC and the other selling stockholders from time to time party thereto. |
| | | Exhibit No.
| | Description
| 4.1 | | 4.2 | | Registration Rights Agreement dated December 17, 2015, among Registrant and NewWoods Petroleum, LLC and the other selling stockholders from time to time party thereto. | | | 4.3 | | Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318)001-32318). | | | | 4.4 4.2 | | Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated(incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed July 12, 2011; File No. 001-32318)001-32318). | | | | 4.5 4.3 | | Supplemental Indenture No. 2, dated as of May 14, 2012, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 3.250% Senior Notes due 2022 and the 4.750% Senior Notes due 2042 (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed May 14, 2012; File No. 001-32318)001-32318). | | | | 4.6 4.4 | | Supplemental Indenture No. 3, dated as of December 19, 2013, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the Floating Rate Senior Notes due 2016 and the 2.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 19, 2013; File No. 001-32318). | | | 4.7 | | Supplemental Indenture No. 4, dated as of June 16, 2015, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.000% Senior Notes due 2045 (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed June 16, 2015; File No. 001-32318)001-32318). | | | | 4.8 4.5 | | Supplemental Indenture No. 5, dated as of December 15, 2015, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.850% Senior Notes due 2025 (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 15, 2015; File No. 001-32318)001-32318). | | | | 4.9 4.6 | | Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as Trustee (incorporated(incorporated by reference to Exhibit 4.1 of Registrant’sForm 8-K filed April 9, 2002; File No. 000-30176)000-30176). |
111
Table of Contents Index to Financial Statements Exhibit No. | | Description | | | | 4.10 4.7 | | Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated(incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed April 9, 2002; File No.000-30176) 000-30176). | | | | 4.11 4.8 | | Supplemental Indenture No. 3, dated as of January 9, 2009, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 6.30% Senior Notes due 2019 (incorporated(incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed January 9, 2009; File No.000-32318) 000-32318). | | | | 4.12 4.9 | | Supplemental Indenture No. 4, dated as of March 22, 2018, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Notes due 2032 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed March 22, 2018; File No. 000-32318). | | | | 4.10 | | Indenture, dated as of October 3, 2001, by and among Devon Financing Company, L.L.C. (f/k/a Devon Financing Corporation, L.L.C.U.L.C.), as Issuer, Registrant, as Guarantor, and The Bank of New York Mellon Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 7.875% Debentures due 2031 (incorporated(incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4 as filed October 31, 2001; File No. 333-68694)333-68694). | | | | 4.13 4.11 | | Senior Indenture, dated as of July 8, 1998 amongSeptember 1, 1997, between Devon OEI Operating, L.L.C. (as successor by merger to OceanSeagull Energy Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 10.24 to the Form 10-Q for the period ended June 30, 1998 of Ocean Energy, Inc.; File No. 001-14252). |
| | | Exhibit No.
| | Description
| | | 4.14 | | First Supplemental Indenture, dated March 30, 1999 to Indenture dated as of July 8, 1998 among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.5 to Ocean Energy, Inc.’s Form 10-Q for the period ended March 31, 1999; File No. 001-08094). | | | 4.15 | | Second Supplemental Indenture, dated as of May 9, 2001 to Indenture dated as of July 8, 1998 among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 99.2 to Ocean Energy, Inc.’sForm 8-K filed May 14, 2001; File No. 033-06444). | | | 4.16 | | Third Supplemental Indenture, dated January 23, 2006 to Indenture dated as of July 8, 1998 among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production Company, L.P., as Successor Guarantor, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.23 of Registrant’s Form 10-K for the year ended December 31, 2005; File No. 001-32318). | | | 4.17 | | Senior Indenture dated September 1, 1997, among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.)Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as Trustee, and related Specimen of 7.50% Senior Notes (incorporateddue 2027 (incorporated by reference to Exhibit 4.4 to Ocean Energy Inc.’s Form 10-K for the year ended December 31, 1997;filed March 23, 1998; File No. 001-08094)001-08094). | | | | 4.18 4.12 | | First Supplemental Indenture, dated as of March 30, 1999, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Duedue 2027 (incorporated(incorporated by reference to Exhibit 4.10 to Ocean Energy’sEnergy, Inc.’s Form 10-Q for the period ended March 31,filed May 17, 1999; File No. 001-08094)001-08094). | | | | 4.19 4.13 | | Second Supplemental Indenture, dated as of May 9, 2001, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors,Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Duedue 2027 (incorporated(incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444)033-06444). | | | | 4.20 4.14 | | Third Supplemental Indenture, dated as of December 31, 2005, to Senior Indenture dated as of September 1, 1997, by and among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production Company, L.P., as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Duedue 2027 (incorporated(incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K for the year ended December 31, 2005;filed March 3, 2006; File No. 001-32318)001-32318). | | | | 4.21 10.1 | | Registrant has not filed instruments defining the rights of holders of long-term indebtedness of Registrant’s majority owned subsidiary, EnLink Midstream Partners, LP, as none of which exceeds ten percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant hereby agrees to furnish a copy of any such agreements to the Commission upon request. | | | 10.1 | | Credit Agreement, dated as of October 24, 2012,5, 2018, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers,Borrower, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, and each lender from time to time party thereto, eachLender and L/C Issuer from time to time party thereto and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender (incorporated(incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed October 29, 2012;9, 2018; File No. 001-32318)001-32318). |
| | | Exhibit No.
| | Description
| 10.2 | | 10.2 | | Extension Agreement dated September 3, 2013 to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NECEnergy Corporation 2009 Long-Term Incentive Plan (as amended and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender, with respect to Borrower’s extension of the Maturity Date from October 24, 2017 to October 24, 2018 (incorporatedrestated effective June 6, 2012) (incorporated by reference to Exhibit 10.110.2 to the Registrant’s Form 10-Q8-K filed November 6, 2013;June 8, 2012; File No. 001-32318)001-32318).* | | | | 10.3 | | First Amendment to Credit Agreement dated February 3, 2014, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, each lender from time to time party thereto, each L/C Issuer from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form8-K filed February 7, 2014; File No. 001-32318). | | | 10.4 | | Extension Agreement dated as of October 17, 2014, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender with respect to the extension of the maturity date from October 24, 2018 to October 24, 2019 (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 5, 2014; File No. 001-32318). | | | 10.5 | | Devon Energy Corporation 2015 Long-Term Incentive Plan (incorporated(incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 3, 2015; File No. 333-204666)333-204666).* | | | |
112
Table of Contents Index to Financial Statements Exhibit No. | | Description | 10.6 10.4 | | Devon Energy Corporation 20092017 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated(incorporated by reference to Exhibit 99.1 to Registrant’s Form S-8 filed June 18, 2012;7, 2017; File No. 333-182198)333-218561).* | | | | 10.7 10.5 | | Devon Energy Corporation 2013 Amendment (effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2013; File No. 001-32318)001-32318).* | | | | 10.8 10.6 | | Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.8 to Registrant’s Form S-8 filed August 17, 2005; File No. 333-127630).* | | | 10.9 | | First Amendment to Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Appendix A to Registrant’s Proxy Statement for the 2006 Annual Meeting of Stockholders filed on April 28, 2006; File No. 001-32318).* | | | 10.10 | | Devon Energy Corporation Incentive Compensation Plan (incorporated(amended and restated effective as of January 1, 2017) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed June 8, 2012;12, 2017; File No. 001-32318)001-32318).* | | | | 10.11 10.7 | | Devon Energy Corporation Non-Qualified Deferred Compensation Plan Amended(amended and Restated Effectiverestated effective as of April 15, 2014 (incorporated2014) (incorporated by reference to Exhibit 10.1 to Registrant’sForm 10-Q filed August 6, 2014; File No. 001-32318)001-32318).* | | | | 10.12 10.8 | | Devon Energy Corporation Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan as amended(amended and restated effective April 15, 2014 (incorporated2014) (incorporated by reference to Exhibit 10.11 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318)001-32318).* | | | | 10.13 10.9 | | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by reference to Exhibit 10.13 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* | | | | 10.10 | | Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective April 15, 2014).* | | | | 10.11 | | Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).* |
| | | Exhibit No.
| | Description
| 10.12 | | 10.14 | | Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.6 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318)001-32318).* | | | | 10.15 10.13 | | Devon Energy Corporation Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318)001-32318).* | | | | 10.16 10.14 | | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* | | | | 10.15 | | Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).* | | | | 10.17 10.16 | | Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318)001-32318).* | | | | 10.18 10.17 | | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* | | | | 10.18 | | Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012).* | | | | 10.19 | | Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).* |
113
Table of Contents Index to Financial Statements Exhibit No. | | Description | | | | 10.19 10.20 | | Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.8 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318)001-32318).* | | | | 10.20 10.21 | | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.23 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* | | | | 10.22 | | Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).* | | | | 10.21 10.23 | | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.25 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* | | | | 10.24 | | Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 24, 2012; File No. 001-32318)001-32318).* | | | | 10.22 10.25 | | Devon Energy Corporation Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated(incorporated by reference to Exhibit 10.9 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318)001-32318).* | | | | 10.23 10.26 | | Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).* | | | | 10.27 | | Devon Energy Corporation Incentive Savings Plan as amended(amended and restated effective January 1, 2014, executed September 22, 2014 (incorporated2018) (incorporated by reference to Exhibit 10.2110.28 to Registrant’s Form 10-K filed February 20, 2015;21, 2018; File No. 001-32318)001-32318).* | | | | 10.24 10.28 | | Devon Energy Corporation Amendment 2015-1,2018-1, executed April 15, 2015,December 14, 2018, to the Devon Energy Corporation Incentive Savings Plan (amended and restated effective January 1, 2014) (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318)2018).* | | | | 10.25 10.29 | | Amended and Restated Form of Employment Agreement between Registrant and certain executive officers (incorporated(incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009; File No. 001-32318)001-32318).* | | | | 10.26 10.30 | | Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant and certain executive officers (incorporated(incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed April 25, 2011; File No. 001-32318)001-32318).* | | | | 10.27 10.31 | | Form of Employment Agreement between Registrant and certain executive officers (Amended and Restated Form of Employment Agreement dated December 15, 2008 (Exhibit 10.22 above), as amended by Amendment No. 1 thereto dated April 19, 2011 (Exhibit 10.23 above)) (incorporated(incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318)001-32318).* |
| | | Exhibit No.
| | Description
| 10.32 | | Employment Agreement, dated April 19, 2017, by and between Registrant and Mr. Jeffrey L. Ritenour (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K, filed on April 20, 2017; File No. 001-32318).* | 10.28 | | | 10.33 | | Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318).* | | | 10.29 | | Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.25 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318).* | | | 10.30 | | Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted stock awarded (incorporated(incorporated by reference to Exhibit 10.29 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318)001-32318).* | | | | 10.31 10.34 | | Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and David A. Hager for performance based restricted stock awarded (incorporated(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 4, 2015; File No. 001-32318)001-32318).* |
114
Table of Contents Index to Financial Statements Exhibit No. | | Description | | | | 10.32 10.35 | | Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 4, 2016; File No. 001-32318).* | | | | 10.36 | | 2017 Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015 Long-Term Incentive Plan between Registrant and executive officers for performance based restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 3, 2017; File No. 001-32318).* | | | | 10.37 | | 2018 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-Term Incentive Plan between Registrant and executive officers for restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 2, 2018; File No. 001-32318).* | | | | 10.38 | | Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 20092015 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted share units awarded (incorporated(incorporated by reference to Exhibit 10.1710.3 to Registrant’s Form 10-K10-Q filed February 21, 2013;May 4, 2016; File No. 001-32318)001-32318).* | | | | 10.33 10.39 | | 2017 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 20092015 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted share units awarded (incorporated(incorporated by reference to Exhibit 10.2810.2 to Registrant’s Form 10-K10-Q filed February 28, 2014;May 3, 2017; File No. 001-32318)001-32318).* | | | | 10.34 10.40 | | 2018 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 20092017 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and certain employees and executive officers for performance based restricted share units awarded (incorporated(incorporated by reference to Exhibit 10.3210.2 to Registrant’s Form 10-K10-Q filed February 20, 2015;May 2, 2018; File No. 001-32318)001-32318).* | | | | 10.35 10.41 | | Form of Notice of Grant of Incentive Stock OptionOptions and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and certain employees and executive officers for incentive stock options granted (incorporated(incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318)001-32318).* | | | | 10.36 10.42 | | Form of EmployeeNotice of Grant of Nonqualified Stock OptionOptions and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and certain employees and executive officers for nonqualified stock options granted (incorporated(incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 25, 2011; File No. 001-32318)001-32318).* | | | 10.37 | | Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for nonqualified stock options granted (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed on February 25, 2010; File No. 001-32318).* |
115
Table of Contents Index to Financial Statements * | Compensatory plansIndicates management contract or arrangementscompensatory plan or arrangement. |
Item 16.Form 10-K Summary Not applicable. 116
Table of Contents Index to Financial Statements SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | | | | DEVON ENERGY CORPORATION | | | | | | | By: | By: /s/ DAVID A. HAGER | | /s/ JEFFREY L. RITENOUR | | | David A. Hager | | Jeffrey L. Ritenour | | | Executive Vice President and Chief ExecutiveFinancial Officer | | |
February 17, 201620, 2019 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. | | | | | | | | | /s/ DAVID A. HAGER | | President, and Chief Executive Officer and | | February 17, 201620, 2019 | | | David A. Hager | | (PrincipalDirector (Principal executive officer) | | | | | | | | | /s/ THOMASJEFFREY L. MITCHELLRITENOUR | | Executive Vice President | | February 17, 201620, 2019 | Jeffrey L. Ritenour | | Thomas L. Mitchell | | and Chief Financial Officer (Principal financial officer) | | | | | | | | | /s/ JEREMY D. HUMPHERS | | Senior Vice President | | February 17, 201620, 2019 | | | Jeremy D. Humphers | | and Chief Accounting Officer (Principal accounting officer) | | | | | | | | | /s/ J. LARRY NICHOLS
| | Executive Chairman of the Board | | February 17, 2016 | | | J. Larry Nichols | | | | | | | | | | | /s/ JOHN RICHELS | | Chairman of the Board | February 20, 2019 | John Richels | | | | | | | | /s/ DUANE C. RADTKE | | Vice Chairman of the Board | | February 17, 201620, 2019 | Duane C. Radtke | | John Richels | | | | | | | | | | | /s/ BARBARA M. BAUMANN | | Director | | February 17, 201620, 2019 | | | Barbara M. Baumann | | | | | | | | | | | /s/ JOHN E. BETHANCOURT | | Director | | February 17, 201620, 2019 | | | John E. Bethancourt | | | | | | | | | | | /s/ ROBERT H. HENRY | | Director | | February 17, 201620, 2019 | | | Robert H. Henry | | | | | | | | | | | /s/ MICHAEL M. KANOVSKY | | Director | | February 17, 201620, 2019 | | | Michael M. Kanovsky | | | | | | | | | /s/ JOHN KRENICKI JR. | | Director | February 20, 2019 | John Krenicki Jr. | | | | | | | | /s/ ROBERT A. MOSBACHER, JR. | | Director | | February 17, 201620, 2019 | | | Robert A. Mosbacher, Jr. | | | | | | | | | | | /s/ DUANE C. RADTKE
| | Director | | February 17, 2016 | | | Duane C. Radtke | | | | | | | | | | | /s/ MARY P. RICCIARDELLO | | Director | | February 17, 201620, 2019 | | | Mary P. Ricciardello | | | | |
INDEX TO EXHIBITS
| | | Exhibit No.
| | Description
| | | 4.1 | | Registration Rights Agreement dated January 7, 2016, among Registrant and EnCap FEx Holdings, LLC, Felix Stack Investments, LLC, Felix STACK Holdings, LLC and the other selling stockholders from time to time party thereto. | | | 4.2 | | Registration Rights Agreement dated December 17, 2015, among Registrant and NewWoods Petroleum, LLC and the other selling stockholders from time to time party thereto. | | | 10.43 | | Amendment to Performance Share Unit Award Agreement dated effective September 16, 2015, between Registrant and John Richels to Performance Share Unit Award Agreement dated February 10, 2015.* | | | 10.44 | | Amendment to Performance Restricted Stock Award Agreement dated effective September 16, 2015, between Registrant and John Richels to Performance Restricted Stock Award Agreement dated February 10, 2015.* | | | 12 | | Statement of computations of ratio of earnings to fixed charges. | | | 21 | | Registrant’s Significant Subsidiaries. | | | 23.1 | | Consent of KPMG LLP. | | | 23.2 | | Consent of LaRoche Petroleum Consultants., Ltd. | | | 23.3 | | Consent of Deloitte. | | | 31.1 | | Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | | | 31.2 | | Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | | | 32.1 | | Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | | | 32.2 | | Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | | | 99.1 | | Report of LaRoche Petroleum Consultants, Ltd. | | | 99.2 | | Report of Deloitte. | | | 101.INS | | XBRL Instance Document. | | | 101.SCH | | XBRL Taxonomy Extension Schema Document. | | | 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document. | | | 101.LAB | | XBRL Taxonomy Extension Labels Linkbase Document. | | | 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document. | | | 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document. |
* | Compensatory plans or arrangements |
130
117 |