Form 8-K DEVON ENERGY CORP/DE For: May 01
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): May 1, 2018
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
| DELAWARE | 001-32318 | 73-1567067 | ||
| (State or Other Jurisdiction of Incorporation) |
(Commission File Number) |
(IRS Employer Identification Number) | ||
| 333 W. SHERIDAN AVE., OKLAHOMA CITY, OKLAHOMA |
73102 | |||
| (Address of Principal Executive Offices) | (Zip Code) | |||
Registrant’s telephone number, including area code: (405) 235-3611
Not Applicable
(Former Name or Former Address, if Changed Since Last Report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instructions A-2. Below):
| ☐ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ☐ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ☐ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ☐ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
| Item 2.02 | Results of Operations and Financial Condition. |
On May 1, 2018, Devon Energy Corporation (the “Company”) issued a press release announcing its financial and operational results for the quarter ended March 31, 2018. In connection with the earnings release, the Company also provided its operations report for the first quarter 2018. Copies of the earnings release and first quarter 2018 operations report are furnished as Exhibits 99.1 and 99.2, respectively, to this report and will be available on the Company’s website at www.devonenergy.com.
The information contained in this report and the exhibits hereto shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as may be expressly set forth by specific reference in such filing.
| Item 7.01 | Regulation FD Disclosure. |
The information in Item 2.02 above is incorporated herein by reference.
| Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits
| Exhibit No. |
Description of Exhibits | |
| 99.1 | Earnings release, dated May 1, 2018. | |
| 99.2 | First quarter 2018 operations report. | |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| DEVON ENERGY CORPORATION | ||
| By: | /s/ Jeffrey L. Ritenour | |
| Jeffrey L. Ritenour | ||
| Executive Vice President and Chief Financial Officer | ||
Date: May 1, 2018
Exhibit 99.1
|
|
Devon Energy Corporation 333 West Sheridan Avenue Oklahoma City, OK 73102-5015 | |||
NEWS RELEASE
Devon Energy Reports First-Quarter 2018 Results
Highlights
| • | Raising full-year 2018 oil production outlook |
| • | High-rate Boundary Raider wells set Delaware Basin record |
| • | STACK Coyote development delivers prolific production rates |
| • | Showboat project online 40 days ahead of plan |
| • | G&A and interest savings to reach $175 million annually |
| • | $1 billion share-repurchase program underway |
OKLAHOMA CITY – May 1, 2018 – Devon Energy Corp. (NYSE: DVN) today reported operational and financial results for the first quarter of 2018. Also included within the release is the company’s guidance outlook for the second quarter and full-year 2018.
“Devon delivered oil production at the high end of guidance and accelerated efficiency gains across the portfolio in the first quarter,” said Dave Hager, president and CEO. “Our performance was highlighted by commencing production on the highest-rate wells in the 100-year history of the Delaware Basin and efficiencies at our STACK Showboat project, which resulted in savings of $1.5 million per well and first production 40 days ahead of plan.
“Based on our strong year-to-date results and the confidence we have in our Delaware and STACK focused capital programs, we are raising our full-year oil production outlook,” Hager said. “Importantly, we are delivering this incremental production with lower costs. We expect per-unit lease operating expense to decline 5 to 10 percent by year-end, and we are on pace to reduce G&A and interest costs by $175 million annually.”
Operating Cash Flow Increases 11 Percent
In the first quarter of 2018, Devon’s operating cash flow totaled $804 million, an 11 percent increase from the fourth quarter of 2017. Devon reported a net loss totaling $197 million, or $0.38 per diluted share, in the first quarter. The quarterly loss was attributable to a $312 million charge related to the early retirement of debt. Adjusting for this one-time charge and other items securities analysts typically exclude from their published estimates, the company’s core earnings were $108 million, or $0.20 per diluted share, in the quarter.
Delaware and STACK Driving 2018 Oil Production Guidance Higher
Overall, total production averaged 544,000 oil-equivalent barrels (Boe) per day in the first quarter. Oil accounted for the largest component of the product mix at 46 percent of total volumes.
The majority of Devon’s production was attributable to its U.S. resource plays, which averaged 413,000 Boe per day. The strongest performance in the U.S. was driven by the company’s Delaware and STACK assets, where combined oil production increased 16 percent compared to the prior quarter. This robust growth drove U.S. oil production to the top end of guidance, averaging 122,000 barrels per day for the quarter.
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Based on strong year-to-date results, Devon is raising its 2018 guidance for U.S. oil production. With the production raise, the midpoint of the company’s guidance for 2018 U.S. oil production now represents an estimated growth rate of 16 percent compared to 2017, up from the previous guidance of 14 percent. The improved outlook is driven by a combination of improving well productivity in the Delaware and STACK and efficiency gains compressing cycle times with development projects.
High-Rate Boundary Raider Wells Set Delaware Basin Record
The company’s development programs across its U.S. resource plays had another strong quarter of performance. In the Delaware, new well activity was headlined by two massive Boundary Raider wells that achieved a combined 24-hour initial production rate of approximately 24,000 Boe per day (80 percent oil). These are the highest-rate wells brought online in the history of the Delaware Basin.
In the STACK, Devon commenced production on 12 high-rate wells that averaged initial 30-day rates of 3,500 Boe per day (55 percent oil). The most prolific STACK wells for the quarter belonged to the four wells from the Coyote development that delivered average 30-day rates of 4,400 Boe per day.
For additional details on well results and other information about Devon’s E&P operations, please refer to the company’s first-quarter 2018 operations report at www.devonenergy.com.
Showboat Project Online 40 Days Ahead of Plan
Devon’s upstream capital was $664 million in the first quarter, 2 percent above the guidance range. This variance was driven primarily by efficiencies achieved at the company’s STACK Showboat project, where first production was achieved approximately 40 days ahead of plan, resulting in an acceleration of capital spend.
The efficiencies at Showboat were driven by a 30 percent improvement in drilling time and the doubling of completion stages per day compared to prior activity in the area. Overall, these operating improvements delivered cost savings of $1.5 million per well at Showboat.
With the better than expected efficiencies compressing cycle times across development projects and pulling forward activity, Devon now expects its capital to trend toward the high end of its 2018 guidance of $2.2 billion to $2.4 billion. The accelerated activity due to efficiencies will benefit both the 2018 and 2019 production profile.
Upstream Revenue in U.S. Advances and EnLink Profitability Expands
The company’s upstream revenue in the U.S. totaled $1.0 billion in the first quarter, a 36 percent improvement compared to the fourth quarter of 2017. Contributing factors to the strong revenue growth were higher commodity price realizations and growth in higher-margin, light-oil production.
In Canada, upstream revenues totaled $302 million in the first quarter. The company benefitted from Western Canadian Select (WCS) basis swaps on approximately 50 percent of its estimated Canadian oil production in the first quarter, generating cash settlements of $97 million.
2
Devon’s midstream business generated operating profits of $277 million in the first quarter, increasing 42 percent year over year. This growth was driven by the company’s investment in EnLink Midstream. Devon has a 64 percent ownership interest in EnLink’s general partner (NYSE: ENLC) and a 23 percent interest in the limited partner (NYSE: ENLK). In aggregate, the company’s ownership in EnLink has a market value of approximately $3 billion and is projected to generate cash distributions of $270 million in 2018.
Regional Basis Swaps Provide Price Protection
The company currently has about 60 percent of its expected oil and gas production protected for the remainder of 2018. These contracts consist of collars and swaps based off the West Texas Intermediate (WTI) oil benchmark and the Henry Hub natural gas index. Additionally, Devon has entered into regional basis swaps in an effort to protect price realizations across its portfolio in the U.S. and Canada, including attractive WCS and Midland basis oil hedges. The volume and pricing details associated with the company’s hedges are provided in the tables within this release.
Per-Unit Production Expense to Improve Throughout 2018
Devon’s production expense totaled $543 million, or $11.08 per Boe, in the first quarter, in line with guidance. New revenue recognition accounting rules were implemented in the first quarter, resulting in a $62 million increase to production expense. The new accounting rules changed the way certain processing fees are presented for natural gas and natural gas liquids. These fees were historically presented as reductions to revenue but are now recorded to production expense. This change had no impact on earnings or cash flow.
With growth in high-margin and low-cost production in the Delaware and STACK, per-unit production expense is projected to decline 5 to 10 percent by year-end 2018.
G&A and Interest Savings to Reach $175 Million Annually
The company’s general and administrative expenses (G&A) totaled $226 million in the first quarter. Subsequent to quarter-end, with workforce and non-personnel related cost reduction initiatives ongoing, the company expects G&A expense to decline by 15 percent in the second quarter. On an annualized run-rate basis, the company expects G&A savings of approximately $110 million.
Net financing costs totaled $431 million in the first quarter. Excluding the $312 million charge attributable to the early retirement of debt, net financing costs for the first quarter were $119 million. With the retirement of high-coupon debt in the first quarter, the company expects to reduce net financing costs by approximately $64 million on an annual basis.
In aggregate, these G&A and interest-reduction initiatives position Devon to lower its costs by approximately $175 million annually.
Successful Tender Activity Reduces Upstream Debt
Devon’s financial position remains exceptionally strong, with investment-grade credit ratings and excellent liquidity. The company exited the first quarter with $1.4 billion of cash on hand. In March, the company successfully repurchased $807 million of debt, reducing the company’s consolidated debt to $10.0 billion. Excluding non-recourse EnLink obligations, Devon’s stand-alone net debt is $4.7 billion.
Share Repurchase Program Reaches $204 Million; Dividend Increased 33 Percent
In the first quarter, Devon announced that its board of directors authorized a $1.0 billion share-repurchase program of the company’s common stock. As of the end of April, Devon had repurchased 6.2 million shares under the program at a total cost of $204 million, with an average share purchase price of $33. Devon expects to complete the stock repurchase program by the end of 2018.
3
The company’s board of directors also recently approved a 33 percent increase to its quarterly common stock dividend to $0.08 per share, compared to the prior rate of $0.06 per share. The new quarterly dividend rate is effective in the second quarter of 2018.
Divestiture Program Achieves $1.1 Billion of Asset Sales
To further focus its resource-rich portfolio, Devon is targeting asset divestiture proceeds in excess of $5 billion. In March, Devon advanced this divestiture goal by announcing the sale of its Johnson County asset in the southern portion of the Barnett Shale position for $553 million. The transaction is expected to close during the second quarter.
In a separate transaction within the Barnett, the company formed a partnership with DowDupont (“Dow”) in April. Under this arrangement, Devon will monetize half its working interest across 116 gross undrilled locations for an approximate $75 million payment from Dow spread over the next five years. With this agreement, Devon will also drill and operate up to 24 wells per year, with volumes dedicated to the EnLink gathering and processing infrastructure.
Overall, these two Barnett transactions, combined with other recent asset sales, have increased total divestiture proceeds over the past year to $1.1 billion.
Non-GAAP Reconciliations
Pursuant to regulatory disclosure requirements, Devon is required to reconcile non-GAAP (generally accepted accounting principles) financial measures to the related GAAP information. Core earnings and core earnings per share and other items referenced within the commentary of this release are non-GAAP financial measures. Reconciliations of these and other non-GAAP measures are provided within the tables of this release.
Conference Call Webcast and Supplemental Earnings Materials
Also provided with today’s release is the company’s detailed operations report that is available on the company’s website at www.devonenergy.com. The company’s first-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, May 2, 2018, and will serve primarily as a forum for analyst and investor questions and answers.
Forward-Looking Statements
This 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 “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “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 our business and operations 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, gas and NGL prices; uncertainties inherent in estimating oil, gas and NGL reserves; the extent to which we are successful in acquiring and discovering additional reserves; the
4
uncertainties, costs and risks involved in oil and gas operations; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate our oil and gas properties; midstream capacity constraints and potential interruptions in production; the extent to which insurance covers any losses we may experience; competition for leases, materials, people and capital; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties 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 release are made as of the date of this 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, potential locations, risked and unrisked locations, estimated ultimate recovery (or EUR), exploration target size and other similar terms. 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 achieving strong returns and capital-efficient cash flow growth. For more information, please visit www.devonenergy.com.
| Investor Contacts | Media Contact | |||
| Scott Coody, 405-552-4735 | John Porretto, 405-228-7506 | |||
| Chris Carr, 405-228-2496 |
5
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
PRODUCTION NET OF ROYALTIES
| Quarter Ended | ||||
| March 31, 2018 | ||||
| Oil and bitumen (MBbls/d) |
||||
| U. S. |
122 | |||
| Heavy Oil |
129 | |||
|
|
|
|||
| Retained assets |
251 | |||
| Divested assets |
— | |||
|
|
|
|||
| Total |
251 | |||
|
|
|
|||
| Natural gas liquids (MBbls/d) |
||||
| U. S. |
91 | |||
| Divested assets |
6 | |||
|
|
|
|||
| Total |
97 | |||
|
|
|
|||
| Gas (MMcf/d) |
||||
| U. S. |
1,002 | |||
| Heavy Oil |
12 | |||
|
|
|
|||
| Retained assets |
1,014 | |||
| Divested assets |
163 | |||
|
|
|
|||
| Total |
1,177 | |||
|
|
|
|||
| Total oil equivalent (MBoe/d) |
||||
| U. S. |
380 | |||
| Heavy Oil |
131 | |||
|
|
|
|||
| Retained assets |
511 | |||
| Divested assets |
33 | |||
|
|
|
|||
| Total |
544 | |||
|
|
|
|||
6
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
PRODUCTION TREND
| 2017 | 2018 | |||||||||||||||||||
| Quarter 1 | Quarter 2 | Quarter 3 | Quarter 4 | Quarter 1 | ||||||||||||||||
| Oil and bitumen (MBbls/d) |
||||||||||||||||||||
| STACK |
21 | 25 | 27 | 30 | 35 | |||||||||||||||
| Delaware Basin |
30 | 30 | 31 | 32 | 36 | |||||||||||||||
| Rockies Oil |
13 | 13 | 12 | 15 | 18 | |||||||||||||||
| Heavy Oil |
137 | 122 | 121 | 132 | 129 | |||||||||||||||
| Eagle Ford |
46 | 34 | 28 | 27 | 23 | |||||||||||||||
| Barnett Shale |
1 | 1 | 1 | 1 | 1 | |||||||||||||||
| Other |
11 | 10 | 11 | 9 | 9 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Retained assets |
259 | 235 | 231 | 246 | 251 | |||||||||||||||
| Divested assets |
2 | 3 | 2 | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
261 | 238 | 233 | 246 | 251 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Natural gas liquids (MBbls/d) |
||||||||||||||||||||
| STACK |
26 | 31 | 32 | 34 | 37 | |||||||||||||||
| Delaware Basin |
10 | 10 | 11 | 13 | 11 | |||||||||||||||
| Rockies Oil |
1 | 1 | 1 | 1 | 2 | |||||||||||||||
| Eagle Ford |
15 | 10 | 12 | 13 | 8 | |||||||||||||||
| Barnett Shale |
36 | 35 | 29 | 36 | 31 | |||||||||||||||
| Other |
2 | 3 | 2 | 3 | 2 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Retained assets |
90 | 90 | 87 | 100 | 91 | |||||||||||||||
| Divested assets |
8 | 7 | 7 | 6 | 6 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
98 | 97 | 94 | 106 | 97 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Gas (MMcf/d) |
||||||||||||||||||||
| STACK |
287 | 298 | 313 | 316 | 344 | |||||||||||||||
| Delaware Basin |
87 | 94 | 90 | 89 | 97 | |||||||||||||||
| Rockies Oil |
15 | 17 | 13 | 14 | 18 | |||||||||||||||
| Heavy Oil |
23 | 14 | 16 | 15 | 12 | |||||||||||||||
| Eagle Ford |
115 | 92 | 86 | 87 | 63 | |||||||||||||||
| Barnett Shale |
498 | 496 | 498 | 466 | 470 | |||||||||||||||
| Other |
12 | 13 | 10 | 13 | 10 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Retained assets |
1,037 | 1,024 | 1,026 | 1,000 | 1,014 | |||||||||||||||
| Divested assets |
191 | 184 | 175 | 175 | 163 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
1,228 | 1,208 | 1,201 | 1,175 | 1,177 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total oil equivalent (MBoe/d) |
||||||||||||||||||||
| STACK |
95 | 105 | 111 | 117 | 129 | |||||||||||||||
| Delaware Basin |
54 | 55 | 57 | 60 | 64 | |||||||||||||||
| Rockies Oil |
17 | 17 | 16 | 19 | 23 | |||||||||||||||
| Heavy Oil |
141 | 124 | 124 | 134 | 131 | |||||||||||||||
| Eagle Ford |
80 | 60 | 54 | 55 | 41 | |||||||||||||||
| Barnett Shale |
120 | 118 | 113 | 114 | 110 | |||||||||||||||
| Other |
14 | 16 | 14 | 13 | 13 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Retained assets |
521 | 495 | 489 | 512 | 511 | |||||||||||||||
| Divested assets |
42 | 41 | 38 | 36 | 33 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
563 | 536 | 527 | 548 | 544 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
7
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
BENCHMARK PRICES
| (average prices) | Quarter 1 | |||||||
| 2018 | 2017 | |||||||
| Oil ($/Bbl) - West Texas Intermediate (Cushing) |
$ | 62.93 | $ | 52.00 | ||||
| Natural Gas ($/Mcf) - Henry Hub |
$ | 3.01 | $ | 3.32 | ||||
REALIZED PRICES
| Quarter Ended March 31, 2018 | ||||||||||||||||
| Oil /Bitumen (Per Bbl) |
NGL (Per Bbl) |
Gas (Per Mcf) |
Total (Per Boe) |
|||||||||||||
| United States |
$ | 61.79 | $ | 22.56 | $ | 2.41 | $ | 30.39 | ||||||||
| Canada |
$ | 19.74 | N/M | N/M | $ | 19.45 | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Realized price without hedges |
$ | 40.15 | $ | 22.56 | $ | 2.41 | $ | 27.75 | ||||||||
| Cash settlements |
$ | (0.10 | ) | $ | (0.53 | ) | $ | 0.17 | $ | 0.23 | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Realized price, including cash settlements |
$ | 40.05 | $ | 22.03 | $ | 2.58 | $ | 27.98 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Quarter Ended March 31, 2017 | ||||||||||||||||
| Oil /Bitumen | NGL | Gas | Total | |||||||||||||
| (Per Bbl) | (Per Bbl) | (Per Mcf) | (Per Boe) | |||||||||||||
| United States |
$ | 49.65 | $ | 15.46 | $ | 2.68 | $ | 25.86 | ||||||||
| Canada |
$ | 26.30 | N/M | N/M | $ | 25.73 | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Realized price without hedges |
$ | 37.33 | $ | 15.46 | $ | 2.68 | $ | 25.82 | ||||||||
| Cash settlements |
$ | 0.50 | $ | — | $ | (0.03 | ) | $ | 0.15 | |||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Realized price, including cash settlements |
$ | 37.83 | $ | 15.46 | $ | 2.65 | $ | 25.97 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
8
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
CONSOLIDATED STATEMENTS OF EARNINGS
| (in millions, except per share amounts) | Quarter Ended March 31, |
|||||||
| 2018 | 2017 | |||||||
| Upstream revenues (1) |
$ | 1,319 | $ | 1,541 | ||||
| Marketing and midstream revenues |
2,491 | 2,010 | ||||||
|
|
|
|
|
|||||
| Total revenues |
3,810 | 3,551 | ||||||
|
|
|
|
|
|||||
| Production expenses (2) |
543 | 457 | ||||||
| Exploration expenses |
33 | 95 | ||||||
| Marketing and midstream expenses |
2,214 | 1,814 | ||||||
| Depreciation, depletion and amortization |
537 | 528 | ||||||
| Asset impairments |
— | 7 | ||||||
| Asset dispositions |
(12 | ) | (3 | ) | ||||
| General and administrative expenses |
226 | 231 | ||||||
| Financing costs, net |
431 | 128 | ||||||
| Other expenses |
19 | (31 | ) | |||||
|
|
|
|
|
|||||
| Total expenses |
3,991 | 3,226 | ||||||
|
|
|
|
|
|||||
| Earnings (loss) before income taxes |
(181 | ) | 325 | |||||
| Income tax expense (benefit) |
(28 | ) | 8 | |||||
|
|
|
|
|
|||||
| Net earnings (loss) |
(153 | ) | 317 | |||||
| Net earnings attributable to noncontrolling interests |
44 | 14 | ||||||
|
|
|
|
|
|||||
| Net earnings (loss) attributable to Devon |
$ | (197 | ) | $ | 303 | |||
|
|
|
|
|
|||||
| Net earnings (loss) per share attributable to Devon: |
||||||||
| Basic |
$ | (0.38 | ) | $ | 0.58 | |||
| Diluted |
$ | (0.38 | ) | $ | 0.58 | |||
| Weighted average common shares outstanding: |
||||||||
| Basic |
527 | 525 | ||||||
| Diluted |
527 | 528 | ||||||
(1) UPSTREAM REVENUES
| (in millions) | Quarter Ended March 31, |
|||||||
| 2018 | 2017 | |||||||
| Oil, gas and NGL sales |
$ | 1,360 | $ | 1,309 | ||||
| Derivative cash settlements |
11 | 8 | ||||||
| Derivative valuation changes |
(52 | ) | 224 | |||||
|
|
|
|
|
|||||
| Upstream revenues |
$ | 1,319 | $ | 1,541 | ||||
|
|
|
|
|
|||||
(2) PRODUCTION EXPENSES
| (in millions) | Quarter Ended March 31, |
|||||||
| 2018 | 2017 | |||||||
| Lease operating expense |
$ | 241 | $ | 223 | ||||
| Gathering, processing & transportation (see page 10) |
228 | 163 | ||||||
| Production taxes |
59 | 55 | ||||||
| Property taxes |
15 | 16 | ||||||
|
|
|
|
|
|||||
| Production expense |
$ | 543 | $ | 457 | ||||
|
|
|
|
|
|||||
9
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
REVENUE RECOGNITION – PRESENTATION CHANGE ONLY
In January 2018, we adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) and changed our accounting for certain gathering, processing and transportation costs on a prospective basis. The changes impact total revenues and total expenses by equal offsetting amounts with no impact to net earnings. As a result of the adoption of ASC 606 in the first quarter of 2018, our upstream revenues and production expenses both increased $62 million. To facilitate comparisons of our 2018 and 2017 upstream revenues and production expenses, the following tables provide pro forma results, assuming ASC 606 had been applied beginning in January 2017.
| (in millions) | Quarter Ended March 31, 2017 | |||||||||||
| As Reported | Pro Forma | Change | ||||||||||
| Upstream revenues |
$ | 1,541 | $ | 1,604 | $ | 63 | ||||||
| Production expenses |
457 | 520 | 63 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net effect |
$ | 1,084 | $ | 1,084 | $ | — | ||||||
|
|
|
|
|
|
|
|||||||
| (in millions) | Quarter Ended June 30, 2017 | |||||||||||
| As Reported | Pro Forma | Change | ||||||||||
| Upstream revenues |
$ | 1,332 | $ | 1,395 | $ | 63 | ||||||
| Production expenses |
455 | 518 | 63 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net effect |
$ | 877 | $ | 877 | $ | — | ||||||
|
|
|
|
|
|
|
|||||||
| (in millions) | Quarter Ended September 30, 2017 | |||||||||||
| As Reported | Pro Forma | Change | ||||||||||
| Upstream revenues |
$ | 1,101 | $ | 1,167 | $ | 66 | ||||||
| Production expenses |
448 | 514 | 66 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net effect |
$ | 653 | $ | 653 | $ | — | ||||||
|
|
|
|
|
|
|
|||||||
| (in millions) | Quarter Ended December 31, 2017 | |||||||||||
| As Reported | Pro Forma | Change | ||||||||||
| Upstream revenues |
$ | 1,333 | $ | 1,396 | $ | 63 | ||||||
| Production expenses |
463 | 526 | 63 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net effect |
$ | 870 | $ | 870 | $ | — | ||||||
|
|
|
|
|
|
|
|||||||
| (in millions) | Year Ended December 31, 2017 | |||||||||||
| As Reported | Pro Forma | Change | ||||||||||
| Upstream revenues |
$ | 5,307 | $ | 5,562 | $ | 255 | ||||||
| Production expenses |
1,823 | 2,078 | 255 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net effect |
$ | 3,484 | $ | 3,484 | $ | — | ||||||
|
|
|
|
|
|
|
|||||||
10
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
| (in millions) | Quarter Ended | |||||||
| March 31, | ||||||||
| 2018 | 2017 | |||||||
| Cash flows from operating activities: |
||||||||
| Net earnings (loss) |
$ | (153 | ) | $ | 317 | |||
| Adjustments to reconcile net earnings to net cash from operating activities: |
||||||||
| Depreciation, depletion and amortization |
537 | 528 | ||||||
| Asset impairments |
— | 7 | ||||||
| Leasehold impairments |
8 | 42 | ||||||
| Accretion on discounted liabilities |
16 | 24 | ||||||
| Total (gains) losses on commodity derivatives |
41 | (232 | ) | |||||
| Cash settlements on commodity derivatives |
11 | 8 | ||||||
| Gain on asset dispositions |
(12 | ) | (3 | ) | ||||
| Deferred income taxes |
(32 | ) | (12 | ) | ||||
| Share-based compensation |
44 | 55 | ||||||
| Early retirement of debt |
312 | — | ||||||
| Other |
26 | (24 | ) | |||||
| Changes in assets and liabilities, net |
6 | 36 | ||||||
|
|
|
|
|
|||||
| Net cash from operating activities |
804 | 746 | ||||||
|
|
|
|
|
|||||
| Cash flows from investing activities: |
||||||||
| Capital expenditures |
(832 | ) | (653 | ) | ||||
| Acquisitions of property and equipment |
(6 | ) | (20 | ) | ||||
| Divestitures of property and equipment |
48 | 32 | ||||||
| Proceeds from sale of investment |
— | 190 | ||||||
| Other |
— | (3 | ) | |||||
|
|
|
|
|
|||||
| Net cash from investing activities |
(790 | ) | (454 | ) | ||||
|
|
|
|
|
|||||
| Cash flows from financing activities: |
||||||||
| Borrowings of long-term debt, net of issuance costs |
801 | 813 | ||||||
| Repayments of long-term debt |
(1,236 | ) | (587 | ) | ||||
| Payment of installment payable |
(250 | ) | (250 | ) | ||||
| Early retirement of debt |
(304 | ) | — | |||||
| Issuance of subsidiary units |
1 | 55 | ||||||
| Repurchases of common stock |
(71 | ) | — | |||||
| Dividends paid on common stock |
(32 | ) | (32 | ) | ||||
| Contributions from noncontrolling interests |
23 | 21 | ||||||
| Distributions to noncontrolling interests |
(102 | ) | (81 | ) | ||||
| Shares exchanged for tax withholdings |
(43 | ) | (61 | ) | ||||
| Other |
— | (2 | ) | |||||
|
|
|
|
|
|||||
| Net cash from financing activities |
(1,213 | ) | (124 | ) | ||||
|
|
|
|
|
|||||
| Effect of exchange rate changes on cash |
(15 | ) | (8 | ) | ||||
|
|
|
|
|
|||||
| Net change in cash, cash equivalents and restricted cash |
(1,214 | ) | 160 | |||||
| Cash, cash equivalents and restricted cash at beginning of period |
2,684 | 1,959 | ||||||
|
|
|
|
|
|||||
| Cash, cash equivalents and restricted cash at end of period |
$ | 1,470 | $ | 2,119 | ||||
|
|
|
|
|
|||||
| Reconciliation of cash, cash equivalents and restricted cash: |
||||||||
| Cash and cash equivalents |
$ | 1,424 | $ | 2,119 | ||||
| Restricted cash included in other current assets |
46 | — | ||||||
|
|
|
|
|
|||||
| Total cash, cash equivalents and restricted cash |
$ | 1,470 | $ | 2,119 | ||||
|
|
|
|
|
|||||
11
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
CONSOLIDATED BALANCE SHEETS
| (in millions) | March 31, | December 31, | ||||||
| 2018 | 2017 | |||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 1,424 | $ | 2,673 | ||||
| Accounts receivable |
1,695 | 1,670 | ||||||
| Other current assets |
516 | 448 | ||||||
|
|
|
|
|
|||||
| Total current assets |
3,635 | 4,791 | ||||||
| Oil and gas property and equipment, based on successful efforts accounting, net |
13,475 | 13,318 | ||||||
| Midstream and other property and equipment, net |
7,908 | 7,853 | ||||||
|
|
|
|
|
|||||
| Total property and equipment, net |
21,383 | 21,171 | ||||||
| Goodwill |
2,383 | 2,383 | ||||||
| Other long-term assets |
1,915 | 1,896 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 29,316 | $ | 30,241 | ||||
|
|
|
|
|
|||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 862 | $ | 819 | ||||
| Revenues and royalties payable |
1,269 | 1,180 | ||||||
| Short-term debt |
354 | 115 | ||||||
| Other current liabilities |
997 | 1,201 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
3,482 | 3,315 | ||||||
|
|
|
|
|
|||||
| Long-term debt |
9,628 | 10,291 | ||||||
| Asset retirement obligations |
1,141 | 1,113 | ||||||
| Other long-term liabilities |
567 | 583 | ||||||
| Deferred income taxes |
773 | 835 | ||||||
| Equity: |
||||||||
| Common stock |
53 | 53 | ||||||
| Treasury stock, at cost |
(12 | ) | — | |||||
| Additional paid-in capital |
7,269 | 7,333 | ||||||
| Retained earnings |
473 | 702 | ||||||
| Accumulated other comprehensive earnings |
1,122 | 1,166 | ||||||
|
|
|
|
|
|||||
| Total stockholders’ equity attributable to Devon |
8,905 | 9,254 | ||||||
| Noncontrolling interests |
4,820 | 4,850 | ||||||
|
|
|
|
|
|||||
| Total equity |
13,725 | 14,104 | ||||||
|
|
|
|
|
|||||
| Total liabilities and equity |
$ | 29,316 | $ | 30,241 | ||||
|
|
|
|
|
|||||
| Common shares outstanding |
526 | 525 | ||||||
12
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
CONSOLIDATING STATEMENTS OF OPERATIONS
| (in millions) | Quarter Ended March 31, 2018 | |||||||||||||||
| Devon U.S. & Canada |
EnLink | Eliminations | Total | |||||||||||||
| Upstream revenues |
$ | 1,319 | $ | — | $ | — | $ | 1,319 | ||||||||
| Marketing and midstream revenues |
879 | 1,761 | (149 | ) | 2,491 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total revenues |
2,198 | 1,761 | (149 | ) | 3,810 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Production expenses |
543 | — | — | 543 | ||||||||||||
| Exploration expenses |
33 | — | — | 33 | ||||||||||||
| Marketing and midstream expenses |
873 | 1,490 | (149 | ) | 2,214 | |||||||||||
| Depreciation, depletion and amortization |
399 | 138 | — | 537 | ||||||||||||
| Asset dispositions |
(12 | ) | — | — | (12 | ) | ||||||||||
| General and administrative expenses |
199 | 27 | — | 226 | ||||||||||||
| Financing costs, net |
387 | 44 | — | 431 | ||||||||||||
| Other expenses |
21 | (2 | ) | — | 19 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total expenses |
2,443 | 1,697 | (149 | ) | 3,991 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Earnings (loss) before income taxes |
(245 | ) | 64 | — | (181 | ) | ||||||||||
| Income tax expense (benefit) |
(34 | ) | 6 | — | (28 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net earnings (loss) |
(211 | ) | 58 | — | (153 | ) | ||||||||||
| Net earnings attributable to noncontrolling interests |
— | 44 | — | 44 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net earnings (loss) attributable to Devon |
$ | (211 | ) | $ | 14 | $ | — | $ | (197 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
OTHER KEY STATISTICS
| (in millions) | Quarter Ended March 31, 2018 | |||||||||||||||
| Devon U.S. & Canada |
EnLink | Eliminations | Total | |||||||||||||
| Cash flow statement related items: |
||||||||||||||||
| Operating cash flow |
$ | 610 | $ | 194 | $ | — | $ | 804 | ||||||||
| Divestitures of property and equipment |
$ | 47 | $ | 1 | $ | — | $ | 48 | ||||||||
| Capital expenditures |
$ | (651 | ) | $ | (181 | ) | $ | — | $ | (832 | ) | |||||
| Debt activity, net |
$ | (1,111 | ) | $ | 122 | $ | — | $ | (989 | ) | ||||||
| EnLink distributions received (paid) |
$ | 67 | $ | (169 | ) | $ | — | $ | (102 | ) | ||||||
| Balance sheet statement items: |
||||||||||||||||
| Net debt (1) |
$ | 4,659 | $ | 3,899 | $ | — | $ | 8,558 | ||||||||
| (1) | 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 | |||
| March 31, 2018 | ||||
| Upstream capital |
$ | 664 | ||
| Land and other acquisitions |
6 | |||
|
|
|
|||
| Exploration and production (E&P) capital |
670 | |||
| Capitalized interest |
18 | |||
| Other |
13 | |||
|
|
|
|||
| Devon capital expenditures (1) |
$ | 701 | ||
|
|
|
|||
| (1) | Excludes $181 million attributable to EnLink for the first quarter of 2018. |
13
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
NON-GAAP FINANCIAL MEASURES
This press release includes non-GAAP financial measures. These non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of the non-GAAP measures used in this press release, including reconciliations to their most directly comparable GAAP measure.
CORE EARNINGS
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 share attributable to Devon. 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 first-quarter 2018 earnings.
| (in millions, except per share amounts) | Quarter Ended March 31, 2018 | |||||||||||||||
| Before-tax | After-tax | After Noncontrolling Interests |
Per Diluted Share |
|||||||||||||
| Loss attributable to Devon (GAAP) |
$ | (181 | ) | $ | (153 | ) | $ | (197 | ) | $ | (0.38 | ) | ||||
| Adjustments: |
||||||||||||||||
| Asset dispositions |
(12 | ) | (9 | ) | (9 | ) | (0.02 | ) | ||||||||
| Asset and exploration impairments |
10 | 7 | 7 | 0.01 | ||||||||||||
| Deferred tax asset valuation allowance |
— | 6 | 6 | 0.01 | ||||||||||||
| Fair value changes in financial instruments and foreign currency |
63 | 62 | 61 | 0.12 | ||||||||||||
| Early retirement of debt |
312 | 240 | 240 | 0.46 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Core earnings attributable to Devon (Non-GAAP) |
$ | 192 | $ | 153 | $ | 108 | $ | 0.20 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
NET DEBT
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.
| (in millions) | March 31, 2018 | |||||||||||
| Devon U.S. & Canada | EnLink | Devon Consolidated | ||||||||||
| Total debt (GAAP) |
$ | 6,066 | $ | 3,916 | $ | 9,982 | ||||||
| Less cash and cash equivalents |
(1,407 | ) | (17 | ) | (1,424 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Net debt (Non-GAAP) |
$ | 4,659 | $ | 3,899 | $ | 8,558 | ||||||
|
|
|
|
|
|
|
|||||||
14
DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
PRODUCTION GUIDANCE
| Quarter 2 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Oil and bitumen (MBbls/d) |
||||||||||||||||
| U.S. |
129 | 134 | 130 | 135 | ||||||||||||
| Heavy Oil |
110 | 115 | 125 | 130 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Retained assets |
239 | 249 | 255 | 265 | ||||||||||||
| Divested assets |
— | — | — | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
239 | 249 | 255 | 265 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Natural gas liquids (MBbls/d) |
||||||||||||||||
| Retained assets |
97 | 100 | 99 | 102 | ||||||||||||
| Divested assets |
3 | 5 | 2 | 4 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
100 | 105 | 101 | 106 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Gas (MMcf/d) |
||||||||||||||||
| U.S. |
990 | 1,040 | 1,000 | 1,050 | ||||||||||||
| Heavy Oil |
11 | 13 | 11 | 13 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Retained assets |
1,001 | 1,053 | 1,011 | 1,063 | ||||||||||||
| Divested assets |
105 | 115 | 65 | 70 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
1,106 | 1,168 | 1,076 | 1,133 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total oil equivalent (MBoe/d) |
||||||||||||||||
| U.S. |
391 | 408 | 396 | 412 | ||||||||||||
| Heavy Oil |
112 | 117 | 127 | 132 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Retained assets |
503 | 525 | 523 | 544 | ||||||||||||
| Divested assets |
21 | 24 | 13 | 16 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
524 | 549 | 536 | 560 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| PRICE REALIZATIONS GUIDANCE | ||||||||||||||||
| Quarter 2 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Oil and bitumen - % of WTI |
||||||||||||||||
| U.S. |
95 | % | 100 | % | 95 | % | 100 | % | ||||||||
| Canada |
35 | % | 55 | % | 35 | % | 50 | % | ||||||||
| NGL - realized price |
$ | 20 | $ | 24 | $ | 20 | $ | 24 | ||||||||
| Natural gas - % of Henry Hub |
73 | % | 83 | % | 73 | % | 83 | % | ||||||||
15
DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
| OTHER GUIDANCE ITEMS | ||||||||||||||||
| Quarter 2 | Full Year | |||||||||||||||
| ($ millions, except %) | Low | High | Low | High | ||||||||||||
| Marketing & midstream operating profit |
$ | 250 | $ | 270 | $ | 1,050 | $ | 1,150 | ||||||||
| Production expenses |
$ | 530 | $ | 580 | $ | 2,100 | $ | 2,200 | ||||||||
| Exploration expenses |
$ | 25 | $ | 35 | $ | 90 | $ | 100 | ||||||||
| Depreciation, depletion and amortization |
$ | 560 | $ | 610 | $ | 2,300 | $ | 2,400 | ||||||||
| General & administrative expenses |
$ | 180 | $ | 200 | $ | 775 | $ | 825 | ||||||||
| Financing costs, net |
$ | 105 | $ | 115 | $ | 440 | $ | 470 | ||||||||
| Other expenses |
$ | 15 | $ | 20 | $ | 60 | $ | 80 | ||||||||
| Current income tax rate |
0 | % | 5 | % | 0 | % | 5 | % | ||||||||
| Deferred income tax rate |
20 | % | 25 | % | 20 | % | 25 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total income tax rate |
20 | % | 30 | % | 20 | % | 30 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net earnings attributable to noncontrolling interests |
$ | 30 | $ | 50 | $ | 185 | $ | 205 | ||||||||
| CAPITAL EXPENDITURES GUIDANCE
|
||||||||||||||||
| Quarter 2 | Full Year | |||||||||||||||
| (in millions) | Low | High | Low | High | ||||||||||||
| Upstream capital |
$ | 550 | $ | 650 | $ | 2,200 | $ | 2,400 | ||||||||
| Capitalized interest |
15 | 20 | 50 | 80 | ||||||||||||
| Other |
20 | 30 | 50 | 70 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Devon capital expenditures (1) |
$ | 585 | $ | 700 | $ | 2,300 | $ | 2,550 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Excludes capital expenditures related to EnLink. |
16
DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
Oil Commodity Hedges As of April 27, 2018
| Price Swaps |
Price Collars | |||||||||
| Period |
Volume (Bbls/d) |
Weighted Average Price ($/Bbl) |
Volume (Bbls/d) |
Weighted Average Floor Price ($/Bbl) |
Weighted Average ($/Bbl) | |||||
| Q2-Q4 2018 |
75,631 | $56.25 | 92,858 | $51.02 | $61.45 | |||||
| Q1-Q4 2019 |
40,130 | $58.08 | 54,790 | $51.72 | $61.72 | |||||
Oil Basis Swaps As of April 27, 2018
| Oil Basis Swaps |
Oil Basis Collars | |||||||||||
| Period |
Index |
Volume (Bbls/d) |
Weighted Average WTI ($/Bbl) |
Volume (Bbls/d) |
Weighted Average Floor WTI ($/Bbl) |
Weighted Average Ceiling WTI ($/Bbl) | ||||||
| Q2-Q4 2018 |
Midland Sweet | 20,491 | $(1.02) | — | $— | $— | ||||||
| Q2-Q4 2018 |
Argus LLS | 10,691 | $3.95 | — | $— | $— | ||||||
| Q2-Q4 2018 |
Argus MEH | 4,669 | 2.49 | — | $— | $— | ||||||
| Q2-Q4 2018 |
Western Canadian Select | 69,018 | $(14.91) | 1,775 | $(15.50) | $(13.93) | ||||||
| Q1-Q4 2019 |
Midland Sweet | 28,000 | $(0.46) | — | $— | $— | ||||||
| Q1-Q4 2019 |
Argus MEH | 6,000 | 2.49 | — | $— | $— | ||||||
Natural Gas Commodity Hedges - Henry Hub As of April 27, 2018
| Price Swaps |
Price Collars | |||||||||
| Period |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Floor Price ($/MMBtu) |
Weighted Average ($/MMBtu) | |||||
| Q2-Q4 2018 |
357,393 | $2.96 | 194,795 | $2.77 | $3.10 | |||||
| Q1-Q4 2019 |
118,588 | $2.83 | 87,844 | $2.69 | $3.06 | |||||
Natural Gas Basis Swaps As of April 27, 2018
| Period |
Index |
Volume (MMBtu/d) |
Weighted Average Differential to Henry Hub ($/MMBtu) | |||
| Q2-Q4 2018 |
Panhandle Eastern Pipe Line | 93,545 | $(0.48) | |||
| Q2-Q4 2018 |
El Paso Natural Gas | 53,455 | $(1.17) | |||
| Q2-Q4 2018 |
Houston Ship Channel | 66,818 | $0.00 | |||
| Q2-Q4 2018 |
Transco Zone 4 | 10,036 | $(0.03) | |||
| Q1-Q4 2019 |
Panhandle Eastern Pipe Line | 4,959 | $(0.81) | |||
| Q1-Q4 2019 |
El Paso Natural Gas | 60,000 | $(1.58) | |||
| Q1-Q4 2019 |
Houston Ship Channel | 72,500 | $(0.01) | |||
| Q1-Q4 2019 |
Transco Zone 4 | 7,397 | $(0.03) |
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. Commodity hedge positions are shown as of April 27, 2018.
17
Q1 2018 Operations Report Key Messages 2 Modeling Stats 3 Q1 Results 4 Outlook 5 Delaware Basin 9 STACK15 Rockies 21 Heavy Oil 22 Eagle Ford 23 Barnett Shale 24 NYSE: DVN devonenergy.com Exhibit 99.2
Executing the 2020 Vision Raising U.S. oil production guidance for 2018 Q1 production at high end of guide Record-setting well productivity driving strong returns Executing multi-zone projects ahead of plan Marketing & supply chain provides certainty of execution Services and supplies secured at competitive pricing Firm transport and basis swaps protect regional pricing Cash flow & margins positioned to expand Driven by U.S. oil growth and improved WCS pricing G&A and interest savings to reach ~$175 MM annually Shareholder-friendly initiatives underway $1 billion share-repurchase program Quarterly dividend raised 33% Divestiture program brings forward value in the Barnett Focus on capital efficiency Portfolio simplification Improve financial strength Return cash to shareholders Maximize cash flow Devon’s 2020 Vision
KEY METRICS Q1 ACTUALS(1) Q1 GUIDANCE U.S. oil (MBbls/d) 122 117 - 122 Canada oil (MBbls/d) 129 125 - 130 NGLs (MBbls/d) 97 98 - 103 Gas (MMcf/d) 1,177 1,139 - 1,191 Total (MBoe/d) 544 530 - 554 Production expenses ($MM) $543 $500 - $550 General & administrative expenses ($MM) $226 $210 - $230 Financing costs, net ($MM)(2) $119 $115 - $125 Upstream capital ($MM) $664 $550 - $650 Q1 2018 - ASSET DETAIL DELAWARE STACK ROCKIES EAGLE FORD BARNETT(1) HEAVY OIL PRODUCTION Oil (MBbl/d) 36 35 18 23 1 129 NGL (MBbl/d) 11 37 2 8 37 0 Gas (MMcf/d) 97 344 18 63 633 12 Total (MBoe/d) 64 129 23 41 143 131 ASSET MARGIN (per Boe) Realized price $41.95 $29.57 $51.76 $46.68 $16.50 $27.68(4) Lease operating expenses ($6.09) ($2.54) ($10.45) ($3.00) ($2.66) ($7.92) Gathering, processing & transportation ($2.59) ($4.93) ($1.15) ($6.06) ($6.51) ($3.94) Production & property taxes ($3.37) ($0.95) ($6.27) ($2.48) ($0.76) ($0.65) Cash margin $29.90 $21.15 $33.89 $35.14 $6.57 $15.17 CAPITAL ACTIVTY (Q1 avg.) Upstream capital ($MM) $192 $230 $41 $78 $12 $71 Operated development rigs 8 9 2 n/a 0.5 Operated frac crews 2 3.5 0.5 n/a 0.5 Operated spuds 20 30 7 n/a 1 Operated wells tied-in 26 20 6 n/a 2 Average lateral length 7,800’ 9,000’ 9,700’ n/a 3,200’ UPDATED GUIDANCE Q2 2018e FY 2018e U.S. oil (MBbls/d) 129 - 134 130 - 135 Canada oil (MBbls/d) 110 - 115 125 - 130 NGLs - retained (MBbls/d) 97 - 100 99 - 102 Gas - retained (MMcf/d) 1,001 - 1,053 1,011 - 1,063 Total retained (MBoe/d) 503 - 525 523 - 544 Divested assets (MBoe/d)(3) 21 - 24 13 - 16 Total (MBoe/d) 524 - 549 536 - 560 Production expenses ($MM) $530 - $580 $2,100 - $2,200 General & administrative expenses ($MM) $180 - $200 $775 - $825 Financing costs, net ($MM) $105 - $115 $440 - $470 Upstream capital ($MM) $550 - $650 $2,200 - $2,400 Corporate capital ($MM) $20 - $30 $50 - $70 Capitalized interest ($MM) $15 - $20 $50 - $80 Key Modeling Stats Q1 2018 actuals include recently announced Johnson County divestiture. Excludes $312 million one-time charge for early retirement of debt. Divested assets represents production for recently announced Johnson County sale through May 2018. Cash settlements related to regional basis hedges in Canada were $97 million, or $8.23 per Boe. Note: Items in bold with italics have updated full-year guidance ranges.
Q1 2018 Results U.S. oil production at top end of guidance Delaware & STACK deliver strong growth Delaware March oil production 30% higher vs. Q4 2017 STACK oil production increases 20% vs. Q4 2017 Massive record-setting wells brought online Two Boundary Raider wells IP24: 24 MBOED (~80% oil) Coyote development: avg. IP30 ~4,400 BOED per well Executing multi-zone projects ahead of plan Drove capital 2% above guidance in Q1 Showboat online ~40 days ahead of plan Record drill times set at Boomslang & Seawolf 32 41 30 35 Delaware oil growth MBOD STACK oil growth MBOD 30% GROWTH IP24: 12,868 BOED (82% oil) Boundary Raider 6-7 Com 212H Boundary Raider 6-7 Com 213H BEST WELLS IN DELAWARE BASIN HISTORY IP24: 11,149 BOED (76% oil)
2018 Outlook Raising 2018 U.S. oil production guidance Expect 16% growth vs. 2017 (~30% exit-rate growth) Guidance increased by ~200 basis points Cost structure to improve throughout 2018 G&A and interest savings: ~$175 MM annually (~65% of 2020 Vision target) Per-unit LOE to decline 5% to 10% by year end Positioned for significant cash flow expansion Canadian WCS pricing improving Eagle Ford volumes to grow from Q1 levels Firm transport and basis swaps protect cash flow Efficiencies expected to pull forward capital activity Benefits 2018 & 2019 production profile Capital trending toward top half of guidance Improving 2018 oil production outlook U.S. oil production (retained assets) (MBOD) 129 - 134 145 - 150 ~30% EXIT-RATE INCREASE VS. 2017 114 122 (1) Represents Devon upstream cash flow. Assumes $65 WTI & $2.75 Henry Hub for Q2 – Q4 2018. Growing upstream cash flow(1) ($MM) ~35% GROWTH
2020 Vision: Driving Significant Cash Flow Growth G&A Op. Cost Interest Cost savings to expand margins Upstream Per-Unit Cash Cost ($/BOE) Growing higher-value production U.S. Oil Production (MBOD) MID-TEENS CAGR DRIVEN BY >25% CAGR IN DELAWARE & STACK 15% COST SAVINGS $2.2 CAGR >25% Driving upstream cash flow expansion $ Billions ($60 WTI & $2.75 HH) Significant free cash flow generation Through 2020 ($60 WTI & $2.75 HH) Note: 2017 operating costs been restated under the current accounting methodology. CUMULATIVE FREE CASH FLOW 2.5 Billion
$1 billion share-repurchase program underway $204 million repurchased to date (6.2 million shares) Average price: $33 per share Expect to be completed by year end Raised quarterly dividend by 33% New quarterly rate: $0.08 per share (effective Q2 2018) Target cash flow payout ratio: 5% - 10% Positioned for sustainable annual dividend growth Successfully tendered $807 million of debt in Q1 Reduces interest by $64 million annually Plan to retire $277 million of maturing upstream debt (next 9 months) Shareholder-Friendly Initiatives $1 Billion share repurchase program initiated KEY INITIATIVES UNDERWAY 33% Increase in quarterly cash dividend $1 Billion debt reduction plan
Portfolio Simplification Strategy Resource quality & depth allows for high-grading of portfolio Potential for >$5 billion of asset disposals Divest proceeds to date: $1.1 billion Committed to bringing forward appropriate value as market conditions allow Optionality to monetize oil or gas Multiple initiatives underway to further focus portfolio footprint Actively pursuing larger asset transactions Concurrently marketing ~$1 billion of non-core asset packages across U.S. (high-multiple properties) POTENTIAL ASSET SALE PROCEEDS Portfolio Simplification >$5 Billion STACK Delaware Basin Rockies Heavy Oil Barnett Eagle Ford
Delaware Basin – Q1 2018 Results March production averages 73 MBOED Oil volumes 30% higher vs. Q4 2017 Driven by focused development program Generating best returns in portfolio Two Boundary Raider wells achieve highest flow rates in Delaware Basin history B. Raider 212H - IP24: 12,868 BOED (82% oil) B. Raider 213H - IP24: 11,149 BOED (76% oil) Landed in 2nd Bone Spring interval (Todd area) 25 wells planned in sweet spot over next 18 months Cash margin expands 27% YoY ($30 per BOE) Oil increases to 56% of mix (54% in prior qtr.) Per-unit operating costs to decline by >10% in 2018 High-returning production growth (MBOED) DELAWARE BASIN Q1 18 Q4 17 Net production (MBOED) 64 60 Upstream capital ($MM) $192 $153 Operated rigs / Frac crews (average) 8/2 8/2 Operated spuds / Wells tied-in 20/26 22/20 Average lateral length 7,800’ 9,000’ 35% GROWTH YEAR OVER YEAR
Initial Multi-Zone Projects Delivering Strong Results Frac efficiencies reaching up to 15 stages/day Anaconda project savings: $1 MM per well Average well cost declined to ~$5.5 million Project EUR trending toward 8 MMBOE Boomslang project attains 1st production 11 wells across 3 intervals (Leonard & Bone Spring) Avg. IP30: ~1,400 BOED (represents 7 of 11 wells) Record drill time: 1,350 ft/day Project cycle time: ~6 months New play type derisked at Boomslang/Thistle area Two 2nd Bone Siltstone wells (Avg. IP24: ~1,700 BOED) Potential across state-line area 1,350 1,200 1,050 6.0 5.8 THISTLE/GAUCHO Lea Eddy ANACONDA: $1 MM SAVINGS PER WELL Drilling Completions Facilities 25% 50% 25% Feet Drilled Per Day Short Cycle Times Spud to first production (months) Anaconda 10 wells online Avg. IP-30: 1,600 BOED Boomslang 11 wells flowing back Peak rates in Q2 2018
World-Class Rattlesnake Developments Advancing Completion work underway at Seawolf project 12 wells targeting multiple Wolfcamp intervals Drilling efficiency improved 67% vs. prior activity Avg. drilling savings: ~$800,000 per well Fighting Okra infill drilling program progressing Developing 9 Wolfcamp wells Key contributor to production growth in 1H 2019 BONE SPRING 3rd WOLFCAMP XY A UPPER MIDDLE LOWER Seawolf Development - Rattlesnake Area Initial Development Future Potential Fighting Okra Drilling 9 wells Peak rates: 1H 2019 Seawolf Completing 12 wells Peak rates: Q4 2018 RATTLESNAKE Condor 9 wells Avg. IP-30: 2,000 BOED Endurance 2 wells Avg. IP-30: 1,925 BOED Calm Breeze 4 wells Avg. IP-30: 2,500 BOED PROLIFIC WOLFCAMP RESULTS ACROSS RATTLESNAKE AREA Devon Activity Industry Activity Audacious 4 wells Avg. IP-30: 3,225 BOED Whirling Wind 4 wells Avg. IP-30: 3,900 BOED Lomas Rojas 8 wells Avg. IP-30: 2,000 BOED
Q1-2018a Q2-2018e Q3-2018e Q4-2018e Boomslang (11 well pattern across 3 intervals in the Leonard and Bone Spring) Drilling Completion Production Drilling Completion Production Drilling Completion Fighting Okra (9 well pattern across 3 intervals in the Wolfcamp) Completion Production Production Seawolf (12 well pattern across 4 Wolfcamp intervals ) Lusitano (6 well pattern across multiple intervals in the Leonard, Bone Spring and Wolfcamp) Drilling Completion Medusa (12 well pattern across 3 intervals in the Leonard Shale and Bone Spring) Production North Thistle 34 (7 well pattern across 1 interval of the Leonard Shale) Drilling Completion DEVELOPMENT STRATEGY BUILDING MOMENTUM DELAWARE BASIN DEVELOPMENT ACTIVITY Current Developments Future Projects (Timing TBD) Seawolf Completing Fighting Okra Drilling Van Doo Dah Potato Basin Tomb Raider Cobra Flagler Lusitano Completing Boomslang Flowing back Anaconda 10 wells online Medusa Drilling North Thistle 34 2018 spud Snapping Delaware Development Projects Advancing on Plan 70% of 2018 capital activity associated with multi-zone developments 6 multi-zone projects expected to contribute to 1st production by YE 2018
Firm transport and basis swaps protect price realizations Midland basis swaps protect ~50% of oil production ~40% of oil delivered on firm transport to Gulf Coast Term gas sales in place to flow to West Coast (avoids WAHA hub) Gas basis swaps protect ~40% of production Field-level infrastructure in place to support growth plans >90% of produced water piped to disposal wells or recycling facilities ~80% of total water used in operations is recycled (DVN: 8 facilities) >80% of oil gathering on pipe by 2H 2018 Excess gas processing capacity projected through 2022 Services and supplies requirements secured through 2019 Rig requirements secured to complete current program (~8 rigs) Dedicated frac crews secured to execute capital plans (~2.5 crews) 30% savings on self-sourced regional sand Houston ~40% of 2018 Delaware volumes transported on Longhorn Protecting Price & Flow Assurance Longhorn (Firm transport) In-basin sales protected by basis swaps OIL BASIS SWAPS PROTECT PRICE 2018 2019 Midland oil swaps (MBbls/d) 23 28 Avg. differential to WTI ($/Bbl) ($1.02) ($0.46) Delaware Basin – Certainty of Execution
Delaware Basin – Outlook Significant resource opportunity (~300,000 net surface acres with >15 development targets) >15% sequential quarter production growth expected in Q2 Capital spending on track with 2018 budget (~$725 million) Production exit-rate growth: >40% by year end Franchise asset provides multi-decade oil growth opportunity ~300k net surface acres (>15 different development targets) >1.3 million net effective acres Production forecast on track (MBOED) >40% EXIT RATE GROWTH
STACK – Q1 2018 Results Oil production increases 68% from Q1 17 Coyote development delivering record flow rates Top wells average IP30 of ~3,500 BOED Field-level cash flow expands 60% year over year Liquids volumes account for ~80% of revenue Per-unit operating costs to decline >10% by Q4 2018 Showboat project online ~40 days ahead of plan Efficiencies accelerated capital spend in Q1 (33% of budget) 8 Bonsai IP 30: 3,900 BOED Coyote 1X IP 30: 3,800 BOED Cottontail IP 30: 4,400 BOED 1 2 3 4 Chipmunk IP 30: 5,900 BOED Sonoyta 2HX IP 30: 3,500 BOED Otter IP 30: 3,400 BOED Coyote 3HX IP 30: 4,400 BOED 5 6 7 Coyote 2HX IP 30: 3,400 BOED 10 Sonoyta 3HX IP 30: 3,500 BOED Hydra IP 30: 2,150 BOED 9 11 Grizzly IP 30: 2,000 BOED 12 Rhino IP 30: 2,100 BOED RECORD-SETTING STACK WELL PRODUCTIVITY Blaine 5 6 11 8 7 10 9 12 ~3,500 Q1 2018 KEY WELLS BOED 30-DAY IPs Canadian Kingfisher Coyote Development 68% OIL GROWTH 1 2 3 4 YEAR-OVER-YEAR KEY STATS Q1 18 Q4 17 Net production (MBOED) 129 117 Upstream capital ($MM) $230 $230 Operated rigs / Frac crews (average) 9/3.5 10/3.5 Operated spuds / Wells tied-in 30/20 32/24 Average lateral length 9,000’ 8,600’
Next 3 projects designed to inform future infill decisions Testing 9, 10 & 12 Meramec wells per drilling unit Program to deliver attractive returns (Showboat/Horsefly/Bernhardt) Burdened wellhead IRRs projected at ~40%(1) (at strip pricing) Low-risk appraisal objectives (testing spacing & secondary targets) Conservatively risked performance within our 2018 outlook Infill projects to deliver improved capital efficiency Projected IRRs superior to historical appraisal drilling results Driven by optimized subsurface planning, significantly lower capital costs and improved LOE costs per well Positioned for significant resource & inventory upside 130k surface acres in over-pressured oil window Economic core of play with up to 5 different landing zones Infill spacing to de-risk upside (currently risked at 6 wells/section) STACK – Infill Development Strategy Drilling Unit Current Projects Showboat 12 wells per drilling unit Flowing back Current Projects to Inform Future Infill Decisions MERAMEC RESOURCE Over-pressured oil acreage 130,000 net surface acres Stacked-pay opportunity 5 Meramec landing zones Risked inventory 6 wells per surface section Infill spacing tests 9 to 12 wells per surface section (1) Returns are burdened for corporate overhead costs Bernhardt 9 wells per drilling unit Drilling Horsefly 10 wells per drilling unit Completing
STACK Development Activity Progressing 60% of capital activity in 2018 associated with multi-zone developments 4 multi-zone projects expected to contribute to 1st production by YE 2018 DEVELOPMENT STRATEGY BUILDING MOMENTUM STACK DEVELOPMENT ACTIVITY Kingfisher Canadian Dewey Custer Blaine 2018 Developments Coyote 4 of 7 wells online Avg. 30-Day IP 4,400 BOED Showboat Flowing back 12 wells per unit Kraken 2018 spud Geis 2018 spud Bernhardt Drilling 9 wells per unit Horsefly Completing 10 wells per unit ML Block 2018 spud Cascade 2018 spud Q1-2018a Q2-2018e Q3-2018e Q4-2018e Coyote (7 well development in the Meramec) Completion Production Drilling Completion Production Drilling Completion Geis (7 wells per drilling unit across 2 intervals in the Meramec) Completion Production Showboat (Testing 12 wells per drilling unit across 3 intervals in the Meramec and 1 Woodford zone) Horsefly (Testing 10 wells per drilling unit across 3 Meramec intervals) Drilling Completion Bernhardt (Testing 9 wells per drilling unit across 3 Meramec intervals) Production Kraken (7 wells per drilling unit across 3 intervals in the Meramec and 1 Woodford zone) Drilling Completion
STACK Infill Projects Delivering Efficiencies Record flow rates achieved at Coyote project Project developing Lower Meramec sweet spot Average IP30: 4,400 BOED (4 of 7 wells online) Drilling time improved by up to 25% vs. offsetting Faith Marie well ($1 MM savings per well) Completion costs reduced by ~10% vs. previous activity Showboat cost savings: ~$1.5 million per well 30% drilling efficiencies ($500k savings per well) 2x improvement in frac stages per day 1st production achieved in April (~40 days ahead of plan) Well tie-ins staggered over next two months Peak project rates expected by mid-year Spud-to-1st production cycle time: ~7 months Faith Marie Parent Well Online Q4 17 IP30: 4,700 BOED Cottontail Parent Well Online Q1 18 IP30: 4,400 BOED Coyote Project 4 of 7 wells online Avg. 30-day IP: 4,400 BOED Online in 2018 Flowing Back 16N 12W 17N 12W Coyote Area: A Lower Meramec Sweet Spot $1.5 MM Savings Per Well Drilling Completions Facilities Cost Savings By Area Frac Stages Per Day
STACK – Certainty of Execution Improved oil takeaway infrastructure boosts pricing (~$1/Bbl uplift) Majority of oil planned to be connected to gathering systems (Black Coyote online in April) Reliable and cost-effective pipeline access to Cushing (see map) Gas flow assurance: Devon holds firm transportation Covers vast majority of estimated STACK gas production Access to premium pricing outside of Mid-Con (covers 1/3 of volumes) Basis swaps protect ~25% of gas production (~$0.45 off HH) Sufficient gas processing capacity to support growth plans Thunderbird plant increases EnLink capacity to 1.2 BCFD Services and supplies requirements secured through 2019 Rig requirements secured to complete current program (~8 rigs) Dedicated frac crews secured to execute capital plans (~3 crews) 30% savings on self-sourced regional sand Protecting Price and Flow Assurance Cushing BASIS SWAPS PROTECT PRICE REALIZATIONS 2018 MidCon basis swaps (MMBtu/d) 94,370 Avg. differential to Henry Hub ($/MMBtu) ($0.45) Basis swaps protect 25% of in-basin gas pricing Navigator Glass Mountain Pipeline Firm gas transportation moves 1/3 of volumes to premium markets
STACK – Outlook Activity concentrated in over-pressured oil window (best returns in play) >100 new operated wells online in 2018 Targeting higher-return Meramec formation Accelerated capital spend in Q1 due to completion efficiencies (32% of budget) 2018 production plan on track Q2 oil volumes flat due to timing of development projects Multi-zone projects to accelerate production growth in 2H 2018 Year-end 2018 exit rates: >40% oil growth Activity shifting to economic core >95% WOODFORD 2018 E&P ACTIVITY MERAMEC ACTIVITY High-returning production growth Production (MBOED) >140 (>40% oil growth) 117 129
Rockies Oil production increased 17% vs. Q4 2017 Parkman/Teapot activity drives growth Low costs drive strong returns (~$5 MM per well) Testing Niobrara potential (~400k prospective acres) Initial well flowing back Completion work underway at 2nd appraisal well “Super Mario” Turner activity accelerating ~10 wells scheduled for remainder of 2018 KEY POWDER RIVER BASIN ACTIVITY Q1 2018 Activity Key Wells to Date Upcoming Turner Wells T Cosner Fed 29-1XPH Parkman 30-Day IP: 1,850 BOED T Cosner Fed 29-3XPH Parkman 30-Day IP: 2,400 BOED T Cosner Fed 29-4XPH Parkman 30-Day IP: 2,550 BOED T Cosner Fed 29-2XPH Parkman 30-Day IP: 2,100 BOED Super Mario Area Turner 4-well test Avg. 30-Day IP: 2,100 BOED/well 1st Niobrara Test Flowing back 2nd Niobrara Test Completing 4 Parkman Wells Avg. 30-Day IP: 1,200 BOED/well Avg. well cost: ~$5mm Teapot Well Avg. 30-Day IP: 1,700 BOED Well cost: ~$5mm Moore Land Trust 21 1TH Teapot 30-Day IP: 2,500 BOED Moore Land Trust 21 2TH Teapot 30-Day IP: 2,300 BOED KEY STATS Q1 18 Q4 17 Net production (MBOED) 23 19 Upstream capital ($MM) $41 $66 Operated rigs / Frac crews (average) 2/0.5 3/0.5 Operated spuds / Wells tied in 7/6 7/11 Average lateral length 9,700’ 8,000’
Heavy Oil Oil production at high end of guidance in Q1 Q2 volumes impacted by turnaround and royalties Jackfish turnaround impact: ~15 MBOD Higher royalties: ~3 MBOD WCS hedges protecting cash flow in 2018 ~50% hedged at $15 off WTI Free cash flow in 2018: $550 million(1) Heavy Oil 2018e Free Cash Flow ($MM) $550 ($275) ($650) $250 $1,225 (1) Assumes $65 WTI & $25 differential for remainder of 2018. Q1 PRODUCTION GROSS NET Jackfish 1 (MBOD) 35.0 31.8 Jackfish 2 (MBOD) 41.7 40.3 Jackfish 3 (MBOD) 40.0 38.7 Lloydminster (MBOED) 21.8 20.3 Total Heavy Oil (MBOED) 138.5 131.1 SAGD Sweet Spot 1 $ INCREASE IN WCS PER BBL FOR EVERY INCREMENTAL 40 MM $ ANNUALIZED CASH FLOW
Stabilizing High-Margin Production Eagle Ford Strong production growth in Q2 (chart below) Two frac crews currently on site 25 wells to be tied-in Plan in place to stabilize production 35 to 40 new wells online in 2H 2018 Free cash flow in 2018: >$400 million(1) 10 Staggered laterals Lower Eagle Ford Tied In: Q2 2018 15 Staggered laterals Lower Eagle Ford Tied In: Q2 2018 EAGLE FORD HIGHLIGHTS Two Completion Crews 25 Wells Expected Online in Q2 ~30% GROWTH (1) Assumes $65 WTI & $2.75 Henry Hub for remainder of 2018. KEY STATS Q1 18 Q4 17 Net production (MBOED) 41 55 Upstream capital ($MM) $78 $41
Barnett Shale Johnson County divestiture announced Proceeds: $553 million (closing late May) Q1 production: 33 MBOED (18% liquids) Partnership formed with DowDupont Selling ½ working interest in 116 locations Devon to receive ~$75 million over 5 yrs Drilling commitment of up to 24 wells/year No restrictions on exiting Barnett ~50 horizontal refracs planned in 2018 Capital program to stabilize production for retained Barnett assets (table right) 2018 BARNETT SHALE ACTIVITY OUTLOOK Dow JV Acreage 2018e activity: ~20 wells drilled Refrac Focus Area 2018e activity: ~50 horizontal refracs PRODUCTION (MBOED) Q1 18 Q2 18e 2H 18e Retained Barnett assets 110 105 - 115 110- 115 Johnson County divestiture 33 22 0 Total Barnett production 143 127 - 137 110 - 115
Investor Contacts & Notices Investor Relations Contacts Scott CoodyChris Carr VP, Investor RelationsSupervisor, Investor Relations 405-552-4735405-228-2496 Email: [email protected] Forward-Looking Statements This presentation includes "forward-looking statements" as defined by the Securities and Exchange Commission (the “SEC”). Such statements include those concerning strategic plans, expectations and objectives for future operations, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this presentation 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 our business and operations 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, gas and NGL prices; uncertainties inherent in estimating oil, gas and NGL reserves; the extent to which we are successful in acquiring and discovering Investor Notices additional reserves; the uncertainties, costs and risks involved in oil and gas operations; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate our oil and gas properties; midstream capacity constraints and potential interruptions in production; the extent to which insurance covers any losses we may experience; competition for leases, materials, people and capital; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties 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 presentation are made as of the date of this presentation, 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. Use of Non-GAAP Information This presentation may include non-GAAP financial measures. Such non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. For additional disclosure regarding such non-GAAP measures, including reconciliations to their most directly comparable GAAP measure, please refer to Devon’s first-quarter 2018 earnings release at www.devonenergy.com. Cautionary Note to Investors 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 presentation may contain certain terms, such as resource potential, potential locations, risked and unrisked locations, estimated ultimate recovery (EUR), exploration target size and other similar terms. 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.