OKLAHOMA CITY--(BUSINESS WIRE)--Devon Energy Corp. (NYSE:DVN) today announced core earnings of $320 million, or $0.78 per diluted share, for the second quarter of 2015. This compares with first-quarter 2015 core earnings of $89 million, or $0.22 per diluted share.
“Devon delivered another high-quality performance in the second quarter as we continued to realize significant operational improvements across our portfolio,” said Dave Hager, president and CEO. “Our oil-focused drilling programs in North America’s best resource plays achieved outstanding well performance, and we made substantial progress reducing well costs and operating expenses. This superior execution contributed to more than 30 percent growth in total oil production year over year and record oil output in the U.S., led by our Eagle Ford and Delaware Basin assets.”
“With current industry conditions, we are focused on maintaining flexibility in our capital programs,” Hager said. “To ensure this optionality, we have minimal exposure to long-term service contracts, no long-term project commitments and negligible leasehold expiration issues. This allows us to dynamically allocate capital to our highest-returning areas while balancing investment with cash flow. We believe this advantage, combined with our high-quality asset base and strong balance sheet, positions Devon as well as anyone in the E&P space.”
On a reported basis, due to a non-cash, full-cost ceiling charge, Devon had a net loss of $2.8 billion, or $6.94 per diluted share, for the second-quarter 2015. This compares with second-quarter 2014 reported net earnings of $675 million, or $1.64 per diluted share.
Oil Production Exceeds Expectations for Fourth Consecutive Quarter
Devon’s oil-driven capital program continued to deliver strong results in the second quarter of 2015. Total oil production averaged 270,000 barrels per day, a 32 percent increase compared to the second quarter of 2014. This result surpassed the midpoint of guidance by 5,000 barrels per day, marking the fourth consecutive quarter the Company has exceeded oil production expectations.
The most significant growth came from the Company’s U.S. operations, where oil production averaged a record high 172,000 barrels per day. This result was 35 percent higher than the year-ago quarter and exceeded the top end of guidance expectations by 2,000 barrels per day. Growth in U.S. production was largely attributable to the Company’s Eagle Ford and Delaware Basin assets. Net production in the Eagle Ford averaged 114,000 Boe per day in the second quarter, a 75 percent increase compared to the second quarter of 2014. In the Delaware Basin, led by outstanding results from the Bone Spring play, production increased to 64,000 Boe per day in the second quarter, a 40 percent increase compared to the year-ago period.
In Canada, net production from the Company’s heavy-oil projects reached an average 98,000 barrels of oil per day in the second quarter. Driven by the continued ramp-up of the Jackfish 3 facility, Canadian oil production increased 27 percent compared to the second quarter of 2014. Scheduled maintenance at the Company’s Jackfish 1 oil sands project limited production by approximately 11,000 barrels per day in the quarter.
In total, Devon’s production averaged 674,000 Boe per day during the second quarter of 2015. This result represents a 9 percent increase compared to the second quarter of 2014, with liquids accounting for 60 percent of the Company’s production mix.
Operations Report
For additional details on Devon’s E&P operations, please refer to the Company’s second-quarter 2015 Operations Report at www.devonenergy.com. Highlights from the report include:
- Delaware Basin type curves improving
- Eagle Ford produces best-in-class well results
- Heavy oil output continues to grow while margins expand
- Cana and Meramec plays generate high-rate wells
- Powder River Basin delivers substantial growth rates
Upstream Revenue Increases 18 Percent; Midstream Profit Expands
Revenue from oil, natural gas and natural gas liquids sales totaled $1.6 billion, an 18 percent increase compared to the first quarter of 2015. The revenue growth was attributable to the increase in higher margin U.S. oil production combined with improved oil price realizations. These factors resulted in second-quarter oil sales increasing to more than 70 percent of Devon’s total upstream revenues.
Cash settlements related to oil and natural gas hedges increased revenue by nearly $500 million, or $8 per Boe in the second quarter. At the end of June, the Company’s remaining commodity hedges had a fair-market value of approximately $850 million. This attractive hedging position represents 55 percent of forecasted oil production and 45 percent of expected natural gas production for the remaining two quarters of 2015.
Devon’s midstream operating profit reached $225 million, which exceeded the Company’s guidance and was 16 percent higher than the first quarter of 2015. The increase in operating profit was driven by growth from EnLink Midstream.
Cost Reduction Initiatives Delivering Results
The Company has several cost reduction initiatives underway that positively impacted second-quarter results. Field-level operating costs, which includes both lease operating expenses and production taxes, declined 8 percent compared to the second quarter of 2014 to $11.05 per Boe. These cost savings were realized across all regions of Devon’s asset portfolio.
Significant general and administrative (G&A) cost savings also were achieved in the second quarter. G&A expenses totaled $212 million, which was below the low end of guidance and a 16 percent decline compared to the first quarter.
Based on year-to-date cost savings, Devon now anticipates its field-level operating costs and G&A to decline to around $14.50 per Boe for the full-year 2015. Compared to original guidance, this implies a full-year cost savings of around $400 million.
Balance Sheet and Liquidity Remain Strong
Operating cash flow in the second quarter, excluding the consolidation of EnLink Midstream, reached $1.0 billion. Combined with the sale of the Victoria Express Pipeline, EnLink secondary offering proceeds and EnLink partnership distributions, Devon’s second-quarter cash inflows totaled $1.3 billion.
Devon’s financial position remained exceptionally strong with investment-grade credit ratings and cash balances of $1.7 billion at the end of the quarter. The Company’s net debt, excluding non-recourse EnLink obligations, totaled $7.6 billion.
Production Outlook on Track; Additional Capital Cost Savings Expected
Detailed forward-looking guidance for the third quarter and full-year 2015 is provided later in the release. Given the strong year-to-date production performance, the Company is well positioned to deliver on its 2015 oil growth target of 25 to 35 percent. Devon also remains on track to increase top-line production by 5 to 10 percent.
The Company expects to achieve these attractive production growth targets with lower capital cost requirements. Since the beginning of the year, Devon has reduced projected 2015 capital spending by approximately $350 million.
Non-GAAP Reconciliations
Pursuant to regulatory disclosure requirements, Devon is required to reconcile non-GAAP financial measures to the related GAAP information (GAAP refers to generally accepted accounting principles). Core earnings and net debt are non-GAAP financial measures referenced within this release. Reconciliations of these non-GAAP measures are provided later in this release.
Conference Call Webcast and Supplemental Earnings Materials
Please note that as soon as practicable today, Devon will post additional information, consisting of an operations report and management commentary with associated slides, to its website at www.devonenergy.com. The Company’s second-quarter 2015 conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, August 5, 2015, and will serve primarily as a forum for analyst and investor questions and answers.
Forward-Looking Statements
This press release includes "forward-looking statements" as defined by the Securities and Exchange Commission (SEC). Such statements include those concerning strategic plans, expectations and objectives for future operations, and are often identified by use of the words “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company. Statements regarding future drilling and production are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, the volatility of oil, natural gas and NGL prices; uncertainties inherent in estimating oil, natural gas and NGL reserves; the extent to which we are successful in acquiring and discovering additional reserves; unforeseen changes in the rate of production from our oil and gas properties; uncertainties in future exploration and drilling results; uncertainties inherent in estimating the cost of drilling and completing wells; drilling risks; competition for leases, materials, people and capital; midstream capacity constraints and potential interruptions in production; risk related to our hedging activities; environmental risks; political changes; changes in laws or regulations; our limited control over third parties who operate our oil and gas properties; our ability to successfully complete mergers, acquisitions and divestitures; and other risks identified in our Form 10-K and our other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this press release are made as of the date of this press release, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This release may contain certain terms, such as resource potential and exploration target size. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10-K, available at www.devonenergy.com. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.
About Devon Energy
Devon Energy is a leading independent energy company engaged in finding and producing oil and natural gas. Based in Oklahoma City and included in the S&P 500, Devon operates in several of the most prolific oil and natural gas plays in the U.S. and Canada with an emphasis on a balanced portfolio. The Company is the second-largest oil producer among North American onshore independents. For more information, please visit www.devonenergy.com.
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL
INFORMATION
| Quarter Ended | Six Months Ended | |||||||||||||||
| PRODUCTION NET OF ROYALTIES | June 30, | June 30, | ||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Oil and bitumen (MBbls/d) | ||||||||||||||||
| United States | 172 | 128 | 170 | 112 | ||||||||||||
| Canada | 98 | 77 | 101 | 78 | ||||||||||||
| Retained assets | 270 | 205 | 271 | 190 | ||||||||||||
| Divested assets | - | 4 | - | 10 | ||||||||||||
| Total | 270 | 209 | 271 | 200 | ||||||||||||
| Natural gas liquids (MBbls/d) | ||||||||||||||||
| United States | 134 | 130 | 136 | 125 | ||||||||||||
| Divested assets | - | 6 | - | 11 | ||||||||||||
| Total | 134 | 136 | 136 | 136 | ||||||||||||
| Gas (MMcf/d) | ||||||||||||||||
| United States | 1,607 | 1,689 | 1,612 | 1,638 | ||||||||||||
| Canada | 20 | 23 | 24 | 22 | ||||||||||||
| Retained assets | 1,627 | 1,712 | 1,636 | 1,660 | ||||||||||||
| Divested assets | - | 219 | - | 401 | ||||||||||||
| Total | 1,627 | 1,931 | 1,636 | 2,061 | ||||||||||||
| Oil equivalent (MBoe/d) | ||||||||||||||||
| United States | 573 | 539 | 574 | 511 | ||||||||||||
| Canada | 101 | 81 | 105 | 81 | ||||||||||||
| Retained assets | 674 | 620 | 679 | 592 | ||||||||||||
| Divested assets | - | 47 | - | 87 | ||||||||||||
| Total | 674 | 667 | 679 | 679 | ||||||||||||
| KEY OPERATING STATISTICS BY REGION | |||||||||||
| Quarter Ended June 30, 2015 | |||||||||||
|
Avg. Production |
Gross Wells Drilled |
Operated Rigs at |
|||||||||
| Permian Basin | 113 | 61 | 14 | ||||||||
| Eagle Ford | 114 | 55 | - | ||||||||
| Canadian Heavy Oil | 101 | 10 | 1 | ||||||||
| Anadarko Basin | 82 | 22 | 6 | ||||||||
| Barnett Shale | 185 | - | - | ||||||||
| Rockies | 27 | 21 | 2 | ||||||||
| Other assets | 52 | 20 | - | ||||||||
| Total | 674 | 189 | 23 | ||||||||
| PRODUCTION TREND | 2014 | 2014 | 2014 | 2015 | 2015 | ||||||||||||||
| Quarter 2 | Quarter 3 | Quarter 4 | Quarter 1 | Quarter 2 | |||||||||||||||
| Oil (MBbls/d) | |||||||||||||||||||
| Permian Basin | 55 | 56 | 55 | 60 | 67 | ||||||||||||||
| Eagle Ford | 40 | 47 | 60 | 75 | 67 | ||||||||||||||
| Canadian Heavy Oil | 77 | 80 | 93 | 104 | 98 | ||||||||||||||
| Anadarko Basin | 11 | 10 | 10 | 9 | 10 | ||||||||||||||
| Barnett Shale | 2 | 2 | 2 | 1 | 1 | ||||||||||||||
| Rockies | 8 | 10 | 9 | 12 | 16 | ||||||||||||||
| Other assets | 12 | 11 | 10 | 11 | 11 | ||||||||||||||
| Retained assets | 205 | 216 | 239 | 272 | 270 | ||||||||||||||
| Divested assets | 4 | 3 | - | - | - | ||||||||||||||
| Total | 209 | 219 | 239 | 272 | 270 | ||||||||||||||
| Natural gas liquids (MBbls/d) | |||||||||||||||||||
| Permian Basin | 18 | 19 | 20 | 19 | 21 | ||||||||||||||
| Eagle Ford | 11 | 14 | 18 | 23 | 24 | ||||||||||||||
| Anadarko Basin | 31 | 34 | 34 | 30 | 24 | ||||||||||||||
| Barnett Shale | 55 | 54 | 53 | 51 | 49 | ||||||||||||||
| Rockies | 1 | 1 | 1 | 1 | 1 | ||||||||||||||
| Other assets | 14 | 16 | 15 | 15 | 15 | ||||||||||||||
| Retained assets | 130 | 138 | 141 | 139 | 134 | ||||||||||||||
| Divested assets | 6 | 5 | - | - | - | ||||||||||||||
| Total | 136 | 143 | 141 | 139 | 134 | ||||||||||||||
| Gas (MMcf/d) | |||||||||||||||||||
| Permian Basin | 134 | 136 | 137 | 137 | 152 | ||||||||||||||
| Eagle Ford | 88 | 109 | 127 | 143 | 146 | ||||||||||||||
| Canadian Heavy Oil | 23 | 26 | 23 | 28 | 20 | ||||||||||||||
| Anadarko Basin | 309 | 323 | 329 | 297 | 290 | ||||||||||||||
| Barnett Shale | 932 | 896 | 878 | 827 | 805 | ||||||||||||||
| Rockies | 67 | 66 | 58 | 53 | 62 | ||||||||||||||
| Other assets | 159 | 160 | 155 | 160 | 152 | ||||||||||||||
| Retained assets | 1,712 | 1,716 | 1,707 | 1,645 | 1,627 | ||||||||||||||
| Divested assets | 219 | 138 | 3 | - | - | ||||||||||||||
| Total | 1,931 | 1,854 | 1,710 | 1,645 | 1,627 | ||||||||||||||
| Oil equivalent (MBoe/d) | |||||||||||||||||||
| Permian Basin | 95 | 98 | 98 | 102 | 113 | ||||||||||||||
| Eagle Ford | 65 | 79 | 99 | 122 | 114 | ||||||||||||||
| Canadian Heavy Oil | 81 | 84 | 97 | 109 | 101 | ||||||||||||||
| Anadarko Basin | 93 | 98 | 100 | 88 | 82 | ||||||||||||||
| Barnett Shale | 212 | 205 | 201 | 191 | 185 | ||||||||||||||
| Rockies | 21 | 22 | 19 | 22 | 27 | ||||||||||||||
| Other assets | 53 | 54 | 50 | 51 | 52 | ||||||||||||||
| Retained assets | 620 | 640 | 664 | 685 | 674 | ||||||||||||||
| Divested assets | 47 | 31 | 1 | - | - | ||||||||||||||
| Total | 667 | 671 | 665 | 685 | 674 | ||||||||||||||
| BENCHMARK PRICES | |||||||||||||||||||||||
| (average prices) | Quarter Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||||
| Oil ($/Bbl) - West Texas Intermediate (Cushing) | $ | 57.78 | $ | 103.09 | $ | 53.33 | $ | 100.87 | |||||||||||||||
| Natural Gas ($/Mcf) - Henry Hub | $ | 2.65 | $ | 4.68 | $ | 2.82 | $ | 4.81 | |||||||||||||||
| REALIZED PRICES | Quarter Ended June 30, 2015 | ||||||||||||||||||||||
| Oil /Bitumen | NGL | Gas | Total | ||||||||||||||||||||
| (Per Bbl) | (Per Bbl) | (Per Mcf) | (Per Boe) | ||||||||||||||||||||
| United States | $ | 52.52 | $ | 10.31 | $ | 2.16 | $ | 24.18 | |||||||||||||||
| Canada (1) | $ | 36.49 |
$ |
N/M |
$ | 0.33 | $ | 35.33 | |||||||||||||||
| Realized price without hedges | $ | 46.69 | $ | 10.31 | $ | 2.13 | $ | 25.86 | |||||||||||||||
| Cash settlements | $ | 16.08 | $ | - | $ | 0.58 | $ | 7.83 | |||||||||||||||
| Realized price, including cash settlements | $ | 62.77 | $ | 10.31 | $ | 2.71 | $ | 33.69 | |||||||||||||||
| Quarter Ended June 30, 2014 | |||||||||||||||||||||||
| Oil /Bitumen | NGL | Gas | Total | ||||||||||||||||||||
| (Per Bbl) | (Per Bbl) | (Per Mcf) | (Per Boe) | ||||||||||||||||||||
| United States | $ | 95.71 | $ | 25.22 | $ | 4.19 | $ | 41.06 | |||||||||||||||
| Canada (1) | $ | 69.45 |
$ |
N/M |
$ | 1.56 | $ | 65.96 | |||||||||||||||
| Realized price without hedges | $ | 86.00 | $ | 25.13 | $ | 4.15 | $ | 44.12 | |||||||||||||||
| Cash settlements | $ | (4.17 | ) | $ | - | $ | (0.16 | ) | $ | (1.78 | ) | ||||||||||||
| Realized price, including cash settlements | $ | 81.83 | $ | 25.13 | $ | 3.99 | $ | 42.34 | |||||||||||||||
| Six Months Ended June 30, 2015 | |||||||||||||||||||||||
| Oil | NGL | Gas | Total | ||||||||||||||||||||
| (Per Bbl) | (Per Bbl) | (Per Mcf) | (Per Boe) | ||||||||||||||||||||
| United States | $ | 47.74 | $ | 9.85 | $ | 2.31 | $ | 22.93 | |||||||||||||||
| Canada (1) | $ | 29.51 |
$ |
N/M |
$ | 0.79 | $ | 28.56 | |||||||||||||||
| Realized price without hedges | $ | 40.94 | $ | 9.85 | $ | 2.29 | $ | 23.80 | |||||||||||||||
| Cash settlements | $ | 18.59 | $ | - | $ | 0.55 | $ | 8.72 | |||||||||||||||
| Realized price, including cash settlements | $ | 59.53 | $ | 9.85 | $ | 2.84 | $ | 32.52 | |||||||||||||||
| Six Months Ended June 30, 2014 | |||||||||||||||||||||||
| Oil | NGL | Gas | Total | ||||||||||||||||||||
| (Per Bbl) | (Per Bbl) | (Per Mcf) | (Per Boe) | ||||||||||||||||||||
| United States | $ | 93.96 | $ | 27.34 | $ | 4.26 | $ | 40.30 | |||||||||||||||
| Canada (1) | $ | 65.37 | $ | 50.17 | $ | 3.97 | $ | 53.26 | |||||||||||||||
| Realized price without hedges | $ | 82.10 | $ | 28.11 | $ | 4.23 | $ | 42.61 | |||||||||||||||
| Cash settlements | $ | (3.19 | ) | $ | - | $ | (0.25 | ) | $ | (1.70 | ) | ||||||||||||
| Realized price, including cash settlements | $ | 78.91 | $ | 28.11 | $ | 3.98 | $ | 40.91 | |||||||||||||||
| (1) The reported Canadian gas volumes include volumes 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 financials. | |||||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF EARNINGS | ||||||||||||||||||||||||
| (in millions, except per share amounts) | Quarter Ended | Six Months Ended | ||||||||||||||||||||||
| June 30, | June 30, | |||||||||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||||||||||
| Oil, gas and NGL sales | $ | 1,587 | $ | 2,679 | $ | 2,926 | $ | 5,236 | ||||||||||||||||
| Oil, gas and NGL derivatives | (282 | ) | (399 | ) | 12 | (719 | ) | |||||||||||||||||
| Marketing and midstream revenues | 2,088 | 2,230 | 3,720 | 3,718 | ||||||||||||||||||||
| Total operating revenues | 3,393 | 4,510 | 6,658 | 8,235 | ||||||||||||||||||||
| Lease operating expenses | 562 | 582 | 1,115 | 1,180 | ||||||||||||||||||||
| Marketing and midstream operating expenses | 1,863 | 2,006 | 3,302 | 3,311 | ||||||||||||||||||||
| General and administrative expenses | 212 | 189 | 463 | 400 | ||||||||||||||||||||
| Production and property taxes | 116 | 150 | 224 | 287 | ||||||||||||||||||||
| Depreciation, depletion and amortization | 814 | 828 | 1,744 | 1,567 | ||||||||||||||||||||
| Asset impairments | 4,168 | - | 9,628 | - | ||||||||||||||||||||
| Restructuring costs | - | 5 | - | 42 | ||||||||||||||||||||
| Gains and losses on asset sales | (1 | ) | (1,057 | ) | (1 | ) | (1,072 | ) | ||||||||||||||||
| Other operating items | 22 | 33 | 41 | 56 | ||||||||||||||||||||
| Total operating expenses | 7,756 | 2,736 | 16,516 | 5,771 | ||||||||||||||||||||
| Operating income (loss) | (4,363 | ) | 1,774 | (9,858 | ) | 2,464 | ||||||||||||||||||
| Net financing costs | 125 | 131 | 242 | 243 | ||||||||||||||||||||
| Other nonoperating items | (9 | ) | 89 | 3 | 107 | |||||||||||||||||||
| Earnings (loss) before income taxes | (4,479 | ) | 1,554 | (10,103 | ) | 2,114 | ||||||||||||||||||
| Income tax expense (benefit) | (1,686 | ) | 854 | (3,721 | ) | 1,085 | ||||||||||||||||||
| Net earnings (loss) | (2,793 | ) | 700 | (6,382 | ) | 1,029 | ||||||||||||||||||
| Net earnings attributable to noncontrolling interests | 23 | 25 | 33 | 30 | ||||||||||||||||||||
| Net earnings (loss) attributable to Devon | $ | (2,816 | ) | $ | 675 | $ | (6,415 | ) | $ | 999 | ||||||||||||||
| Net earnings (loss) per share attributable to Devon: | ||||||||||||||||||||||||
| Basic | $ | (6.94 | ) | $ | 1.65 | $ | (15.81 | ) | $ | 2.45 | ||||||||||||||
| Diluted | $ | (6.94 | ) | $ | 1.64 | $ | (15.81 | ) | $ | 2.44 | ||||||||||||||
| Weighted average common shares outstanding: | ||||||||||||||||||||||||
| Basic | 411 | 408 | 411 | 408 | ||||||||||||||||||||
| Diluted | 411 | 411 | 411 | 410 | ||||||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||||||
| (in millions) | Quarter Ended | Six Months Ended | ||||||||||||||||||||||
| June 30, | June 30, | |||||||||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||||||
| Net earnings (loss) | $ | (2,793 | ) | $ | 700 | $ | (6,382 | ) | $ | 1,029 | ||||||||||||||
| Adjustments to reconcile net earnings (loss) | ||||||||||||||||||||||||
| to net cash from operating activities: | ||||||||||||||||||||||||
| Depreciation, depletion and amortization | 814 | 828 | 1,744 | 1,567 | ||||||||||||||||||||
| Asset impairments | 4,168 | - | 9,628 | - | ||||||||||||||||||||
| Gains and losses on asset sales | (1 | ) | (1,057 | ) | (1 | ) | (1,072 | ) | ||||||||||||||||
| Deferred income tax expense (benefit) | (1,593 | ) | 569 | (3,640 | ) | 777 | ||||||||||||||||||
| Derivatives and other financial instruments | 305 | 454 | (125 | ) | 761 | |||||||||||||||||||
| Cash settlements on derivatives and financial instruments | 464 | (191 | ) | 1,183 | (245 | ) | ||||||||||||||||||
| Other noncash charges | 42 | 106 | 267 | 229 | ||||||||||||||||||||
| Net change in working capital | (189 | ) | 622 | 26 | 470 | |||||||||||||||||||
| Change in long-term other assets | 18 | 11 | 159 | (77 | ) | |||||||||||||||||||
| Change in long-term other liabilities | (134 | ) | 7 | (110 | ) | 20 | ||||||||||||||||||
| Net cash from operating activities | 1,101 | 2,049 | 2,749 | 3,459 | ||||||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||||||
| Capital expenditures | (1,432 | ) | (1,758 | ) | (3,149 | ) | (3,341 | ) | ||||||||||||||||
| Acquisitions of property, equipment and businesses | (13 | ) | (289 | ) | (417 | ) | (6,224 | ) | ||||||||||||||||
| Divestitures of property and equipment | 6 | 2,800 | 8 | 2,942 | ||||||||||||||||||||
| Redemptions of long-term investments | - | - | - | 57 | ||||||||||||||||||||
| Other | (8 | ) | 47 | (5 | ) | 84 | ||||||||||||||||||
| Net cash from investing activities | (1,447 | ) | 800 | (3,563 | ) | (6,482 | ) | |||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||||||
| Borrowings of long-term debt, net of issuance costs | 2,094 | 374 | 3,051 | 3,720 | ||||||||||||||||||||
| Net short-term debt repayments | (778 | ) | (1,119 | ) | (763 | ) | (862 | ) | ||||||||||||||||
| Repayments of long-term debt | (1,034 | ) | (2,413 | ) | (1,521 | ) | (3,990 | ) | ||||||||||||||||
| Stock option exercises | 4 | 72 | 4 | 83 | ||||||||||||||||||||
| Sale of subsidiary units | 85 | - | 654 | - | ||||||||||||||||||||
| Issuance of subsidiary units | 2 | 20 | 4 | 20 | ||||||||||||||||||||
| Dividends paid on common stock | (98 | ) | (99 | ) | (197 | ) | (189 | ) | ||||||||||||||||
| Distributions to noncontrolling interests | (65 | ) | (41 | ) | (118 | ) | (141 | ) | ||||||||||||||||
| Other | - | 12 | (12 | ) | 9 | |||||||||||||||||||
| Net cash from financing activities | 210 | (3,194 | ) | 1,102 | (1,350 | ) | ||||||||||||||||||
| Effect of exchange rate changes on cash | 3 | 24 | (43 | ) | 13 | |||||||||||||||||||
| Net change in cash and cash equivalents | (133 | ) | (321 | ) | 245 | (4,360 | ) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 1,858 | 2,027 | 1,480 | 6,066 | ||||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 1,725 | $ | 1,706 | $ | 1,725 | $ | 1,706 | ||||||||||||||||
| CONSOLIDATED BALANCE SHEETS | |||||||||||
| (in millions) | |||||||||||
| June 30, | December 31, | ||||||||||
| Current assets: | 2015 | 2014 | |||||||||
| Cash and cash equivalents | $ | 1,725 | $ | 1,480 | |||||||
| Accounts receivable | 1,602 | 1,959 | |||||||||
| Derivatives, at fair value | 924 | 1,993 | |||||||||
| Income taxes receivable | 9 | 522 | |||||||||
| Other current assets | 470 | 544 | |||||||||
| Total current assets | 4,730 | 6,498 | |||||||||
| Property and equipment, at cost: | |||||||||||
| Oil and gas, based on full cost accounting: | |||||||||||
| Subject to amortization | 77,191 | 75,738 | |||||||||
| Not subject to amortization | 2,685 | 2,752 | |||||||||
| Total oil and gas | 79,876 | 78,490 | |||||||||
| Midstream and other | 10,354 | 9,695 | |||||||||
| Total property and equipment, at cost | 90,230 | 88,185 | |||||||||
| Less accumulated depreciation, depletion and amortization | (62,406 | ) | (51,889 | ) | |||||||
| Property and equipment, net | 27,824 | 36,296 | |||||||||
| Goodwill | 6,349 | 6,303 | |||||||||
| Other long-term assets | 1,703 | 1,540 | |||||||||
| Total assets | $ | 40,606 | $ | 50,637 | |||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 1,035 | $ | 1,400 | |||||||
| Revenues and royalties payable | 1,095 | 1,193 | |||||||||
| Short-term debt | 670 | 1,432 | |||||||||
| Deferred income taxes | 346 | 730 | |||||||||
| Other current liabilities | 852 | 1,180 | |||||||||
| Total current liabilities | 3,998 | 5,935 | |||||||||
| Long-term debt | 11,375 | 9,830 | |||||||||
| Asset retirement obligations | 1,391 | 1,339 | |||||||||
| Other long-term liabilities | 782 | 948 | |||||||||
| Deferred income taxes | 2,909 | 6,244 | |||||||||
| Stockholders' equity: | |||||||||||
| Common stock | 41 | 41 | |||||||||
| Additional paid-in capital | 4,736 | 4,088 | |||||||||
| Retained earnings | 10,018 | 16,631 | |||||||||
| Accumulated other comprehensive earnings | 528 | 779 | |||||||||
| Total stockholders' equity attributable to Devon | 15,323 | 21,539 | |||||||||
| Noncontrolling interests | 4,828 | 4,802 | |||||||||
| Total stockholders' equity | 20,151 | 26,341 | |||||||||
| Total liabilities and stockholders' equity | $ | 40,606 | $ | 50,637 | |||||||
| Common shares outstanding | 411 | 409 | |||||||||
| CONSOLIDATING STATEMENTS OF OPERATIONS | |||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Quarter Ended June 30, 2015 | |||||||||||||||||||||||
|
Devon U.S. |
EnLink | Eliminations | Total | ||||||||||||||||||||
| Oil, gas and NGL sales | $ | 1,587 | $ | - | $ | - | $ | 1,587 | |||||||||||||||
| Oil, gas and NGL derivatives | (282 | ) | - | - | (282 | ) | |||||||||||||||||
| Marketing and midstream revenues | 985 | 1,274 | (171 | ) | 2,088 | ||||||||||||||||||
| Total operating revenues | 2,290 | 1,274 | (171 | ) | 3,393 | ||||||||||||||||||
| Lease operating expenses | 562 | - | - | 562 | |||||||||||||||||||
| Marketing and midstream operating expenses | 970 | 1,064 | (171 | ) | 1,863 | ||||||||||||||||||
| General and administrative expenses | 184 | 28 | - | 212 | |||||||||||||||||||
| Production and property taxes | 104 | 12 | - | 116 | |||||||||||||||||||
| Depreciation, depletion and amortization | 716 | 98 | - | 814 | |||||||||||||||||||
| Asset impairments | 4,168 | - | - | 4,168 | |||||||||||||||||||
| Gains and losses on asset sales | (1 | ) | - | - | (1 | ) | |||||||||||||||||
| Other operating items | 22 | - | - | 22 | |||||||||||||||||||
| Total operating expenses | 6,725 | 1,202 | (171 | ) | 7,756 | ||||||||||||||||||
| Operating income (loss) | (4,435 | ) | 72 | - | (4,363 | ) | |||||||||||||||||
| Net financing costs | 99 | 26 | - | 125 | |||||||||||||||||||
| Other nonoperating items | - | (9 | ) | - | (9 | ) | |||||||||||||||||
| Earnings (loss) before income taxes | (4,534 | ) | 55 | - | (4,479 | ) | |||||||||||||||||
| Income tax expense (benefit) | (1,696 | ) | 10 | - | (1,686 | ) | |||||||||||||||||
| Net earnings (loss) | (2,838 | ) | 45 | - | (2,793 | ) | |||||||||||||||||
| Net earnings attributable to noncontrolling interests | 1 | 22 | - | 23 | |||||||||||||||||||
| Net earnings (loss) attributable to Devon | $ | (2,839 | ) | $ | 23 | $ | - | $ | (2,816 | ) | |||||||||||||
|
OTHER KEY STATISTICS |
|||||||||||||||||||||||
| (in millions) | Quarter Ended June 30, 2015 | ||||||||||||||||||||||
|
Devon U.S. |
EnLink | Eliminations | Total | ||||||||||||||||||||
| Cash flow statement items: | |||||||||||||||||||||||
| Operating cash flow | $ | 995 | $ | 106 | $ | - | $ | 1,101 | |||||||||||||||
| Capital expenditures | $ | (1,243 | ) | $ | (189 | ) | $ | - | $ | (1,432 | ) | ||||||||||||
| Acquisitions of property, equipment and businesses | $ | - | $ | (13 | ) | $ | - | $ | (13 | ) | |||||||||||||
| Sale of subsidiary units | $ | 85 | $ | - | $ | - | $ | 85 | |||||||||||||||
| EnLink distributions received (paid) (1) | $ | 236 | $ | (301 | ) | $ | - | $ | (65 | ) | |||||||||||||
| Balance sheet statement items: | |||||||||||||||||||||||
| Net debt(2) | $ | 7,565 | $ | 2,755 | $ | - | $ | 10,320 | |||||||||||||||
| (1) Includes $171 million for the sale of the Victoria Express Pipeline. | |||||||||||||||||||||||
| (2) Net debt is a Non-GAAP measure. For a reconciliation of the comparable GAAP measure, see "Non-GAAP Financial Measures" later in this release. | |||||||||||||||||||||||
| CAPITAL EXPENDITURES | |||||||||
| (in millions) | |||||||||
| Quarter Ended June 30, 2015 | Six Months Ended June 30, 2015 | ||||||||
| Exploration and development capital | $ | 882 | $ | 2,208 | |||||
| Capitalized G&A and interest | 116 | 223 | |||||||
| Acquisitions | - | 92 | |||||||
| Midstream(1) | 21 | 37 | |||||||
| Corporate and other | 14 | 41 | |||||||
| Devon capital expenditures | $ | 1,033 | $ | 2,601 | |||||
|
(1) Excludes $158 million and $672 million attributable to EnLink for the second quarter and first six months of 2015, respectively. |
|||||||||
NON-GAAP FINANCIAL MEASURES
The United States Securities and Exchange Commission has adopted disclosure requirements for public companies such as Devon concerning Non-GAAP financial measures (GAAP refers to generally accepted accounting principles). The Company must reconcile the Non-GAAP financial measure to related GAAP information.
CORE EARNINGS
(in millions)
Devon’s reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of the Company’s financial results. Accordingly, the Company also uses the measures of core earnings and core earnings per diluted share. Devon believes these non-GAAP measures facilitate comparisons of its performance to earnings estimates published by securities analysts. Devon also believes these non-GAAP measures can facilitate comparisons of its performance between periods and to the performance of its peers. The following table summarizes the effects of these items on second-quarter 2015 earnings.
| Quarter Ended June 30, 2015 | |||||||||
| Before-Tax | After-Tax | ||||||||
| Net loss attributable to Devon (GAAP) | $ | (2,816 | ) | ||||||
| Asset impairments | 4,168 | 2,646 | |||||||
| Fair value changes in financial instruments and foreign currency | 761 | 490 | |||||||
| Core earnings attributable to Devon (Non-GAAP) | $ | 320 | |||||||
| Diluted share count | 414 | ||||||||
| Core diluted earnings per share attributable to Devon (Non-GAAP) | $ | 0.78 | |||||||
NET DEBT
(in millions)
Devon defines net debt as debt less cash and cash equivalents and net debt attributable to the consolidation of EnLink Midstream as presented in the following table. Devon believes that netting these sources of cash against debt and adjusting for EnLink net debt provides a clearer picture of the future demands on cash from Devon to repay debt.
| June 30, 2015 | |||||||||||||||||
| Devon U.S. & Canada | EnLink | Devon Consolidated | |||||||||||||||
| Total debt (GAAP) | $ | 9,218 | $ | 2,827 | $ | 12,045 | |||||||||||
| Less cash and cash equivalents | (1,653 | ) | (72 | ) | (1,725 | ) | |||||||||||
| Net debt (Non-GAAP) | $ | 7,565 | $ | 2,755 | $ | 10,320 | |||||||||||
DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
| PRODUCTION GUIDANCE | Quarter 3 | Full Year | ||||||||||||||||||||||
| Low | High | Low | High | |||||||||||||||||||||
| Oil and bitumen (MBbls/d) | ||||||||||||||||||||||||
| United States | 155 | 165 | 160 | 170 | ||||||||||||||||||||
| Canada | 105 | 115 | 100 | 110 | ||||||||||||||||||||
| Total | 260 | 280 | 260 | 280 | ||||||||||||||||||||
| Natural gas liquids (MBbls/d) | ||||||||||||||||||||||||
| United States | 125 | 135 | 128 | 134 | ||||||||||||||||||||
| Gas (MMcf/d) | ||||||||||||||||||||||||
| United States | 1,500 | 1,550 | 1,550 | 1,600 | ||||||||||||||||||||
| Canada | 15 | 20 | 15 | 20 | ||||||||||||||||||||
| Total | 1,515 | 1,570 | 1,565 | 1,620 | ||||||||||||||||||||
| Oil equivalent (MBoe/d) | ||||||||||||||||||||||||
| United States | 530 | 558 | 546 | 571 | ||||||||||||||||||||
| Canada | 108 | 118 | 103 | 113 | ||||||||||||||||||||
| Total | 638 | 676 | 649 | 684 | ||||||||||||||||||||
| PRICE REALIZATIONS GUIDANCE | Quarter 3 | Full Year | ||||||||||||||||||||||
| Low | High | Low | High | |||||||||||||||||||||
| Oil and bitumen - % of WTI | ||||||||||||||||||||||||
| United States | 84 | % | 94 | % | 85 | % | 95 | % | ||||||||||||||||
| Canada | 58 | % | 68 | % | 53 | % | 63 | % | ||||||||||||||||
| NGL - realized price | $ | 7 | $ | 12 | $ | 6 | $ | 16 | ||||||||||||||||
| Natural gas - % of Henry Hub | 78 | % | 88 | % | 78 | % | 88 | % | ||||||||||||||||
| OTHER GUIDANCE ITEMS | Quarter 3 | Full Year | ||||||||||||||||||||||
| ($ millions, except Boe) | Low | High | Low | High | ||||||||||||||||||||
| Marketing & midstream operating profit | $ | 195 | $ | 225 | $ | 830 | $ | 890 | ||||||||||||||||
| Lease operating expenses per Boe | $ | 8.90 | $ | 9.40 | $ | 8.80 | $ | 9.30 | ||||||||||||||||
| General & administrative expenses per Boe | $ | 3.40 | $ | 3.70 | $ | 3.40 | $ | 3.90 | ||||||||||||||||
| Production and property taxes as % of upstream sales | 6.7 | % | 7.7 | % | 6.7 | % | 7.7 | % | ||||||||||||||||
| Depreciation, depletion and amortization per Boe | $ | 12.50 | $ | 13.50 | $ | 13.00 | $ | 14.00 | ||||||||||||||||
| Other operating items | $ | 15 | $ | 20 | $ | 60 | $ | 80 | ||||||||||||||||
| Net financing costs | $ | 130 | $ | 140 | $ | 480 | $ | 540 | ||||||||||||||||
| Current income tax rate | 0.0 | % | 5.0 | % | 0.0 | % | 5.0 | % | ||||||||||||||||
| Deferred income tax rate | 30.0 | % | 35.0 | % | 30.0 | % | 35.0 | % | ||||||||||||||||
| Total income tax rate | 30.0 | % | 40.0 | % | 30.0 | % | 40.0 | % | ||||||||||||||||
| Net earnings attributable to noncontrolling interests | $ | 10 | $ | 30 | $ | 50 | $ | 100 | ||||||||||||||||
| CAPITAL EXPENDITURES GUIDANCE | Quarter 3 | Full Year | ||||||||||||||||||||||
| (in millions) | Low | High | Low | High | ||||||||||||||||||||
| Exploration and development | $ | 900 | $ | 1,000 | $ | 3,900 | $ | 4,100 | ||||||||||||||||
| Capitalized G&A and interest | 100 | 120 | 380 | 480 | ||||||||||||||||||||
| Midstream(1) | 10 | 20 | 70 | 120 | ||||||||||||||||||||
| Corporate and other | 15 | 25 | 60 | 110 | ||||||||||||||||||||
| Devon capital expenditures | $ | 1,025 | $ | 1,165 | $ |
4,410 |
$ |
4,810 |
||||||||||||||||
| (1) Excludes capital expenditures related to EnLink. | ||||||||||||||||||||||||
| COMMODITY HEDGES | |||||||||||||||||||||||||||
| Oil Commodity Hedges | |||||||||||||||||||||||||||
| Price Swaps | Price Collars | Call Options Sold | |||||||||||||||||||||||||
| Period | Volume (Bbls/d) | Weighted Average Price ($/Bbl) | Volume (Bbls/d) | Weighted Average Floor Price ($/Bbl) | Weighted Average Ceiling Price ($/Bbl) | Volume (Bbls/d) | Weighted Average Price ($/Bbl) | ||||||||||||||||||||
| Q3-Q4 2015 | 106,000 | $90.85 | 42,000 | $82.40 | $89.78 | 28,000 | $116.43 | ||||||||||||||||||||
| Oil Basis Swaps | |||||||||||||||||||||||||||
| Period | Index | Volume (Bbls/d) | Weighted Average Differential to WTI ($/Bbl) | ||||||||||||||||||||||||
| Q3-Q4 2015 | Western Canadian Select | 40,000 | $(15.79) | ||||||||||||||||||||||||
| Natural Gas Commodity Hedges | |||||||||||||||||||||||||||
| Price Swaps | Price Collars | Call Options Sold | |||||||||||||||||||||||||
| Period | Volume (MMBtu/d) | Weighted Average Price ($/MMBtu) | Volume (MMBtu/d) | Weighted Average Floor Price ($/MMBtu) | Weighted Average Ceiling Price ($/MMBtu) | Volume (MMBtu/d) | Weighted Average Price ($/MMBtu) | ||||||||||||||||||||
| Q3-Q4 2015 | 250,000 | $4.32 | 462,500 | $3.55 | $3.85 | 550,000 | $5.09 | ||||||||||||||||||||
Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price. Devon’s natural gas derivatives settle against the Inside FERC first of the month Henry Hub index.
