UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
CURRENT REPORT
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| Item 2.02 | Results of Operations and Financial Condition. |
On August 4, 2020, Devon Energy Corporation (the “Company”) announced its financial and operational results for the quarter ended June 30, 2020. In connection with this announcement, the Company provided an earnings release, its earnings presentation for the second quarter of 2020 and certain supplemental financial information (including guidance and hedging information). Copies of these documents are furnished as Exhibits 99.1, 99.2 and 99.3, 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 9.01 | Financial Statements and Exhibits. |
(d) Exhibits
| Exhibit No. |
Description of Exhibits | |
| 99.1 | Earnings release, dated August 4, 2020. | |
| 99.2 | Second quarter 2020 earnings presentation. | |
| 99.3 | Supplemental financial information (including guidance and hedging information). | |
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). | |
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: August 4, 2020
Exhibit 99.1
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Devon Energy Corporation 333 West Sheridan Avenue Oklahoma City, OK 73102-5015
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Devon Energy Reports Second-Quarter 2020 Financial and Operational Results
OKLAHOMA CITY – Aug. 4, 2020 – Devon Energy Corp. (NYSE: DVN) today reported financial and operational results for the second-quarter 2020. Supplemental financial tables for second-quarter results along with updated 2020 guidance are available on the company’s website at www.devonenergy.com.
KEY FINANCIAL AND OPERATIONAL HIGHLIGHTS
| • | Efficiency gains drove capital expenditures 10 percent below guidance to $203 million in the quarter |
| • | Second-quarter oil production totaled 153,000 barrels per day, exceeding midpoint guidance by 3,000 barrels per day |
| • | Operating costs were below guidance, declining 14 percent year-over-year |
| • | Exited second quarter with $4.7 billion of liquidity, including $1.7 billion of cash, with no debt maturities until 2025 |
| • | Accelerating Barnett Shale closing to Oct. 1, 2020, from previously scheduled date of Dec. 31, 2020 |
| • | Board of directors declares a $100 million special dividend in conjunction with Barnett closing |
| • | Expect to achieve $300 million of sustainable cash cost savings by year end |
| • | Plan to use cash on hand to repurchase up to $1.5 billion of additional debt |
“As we navigate through the challenges presented by the COVID-19 crisis, our top priority continues to be the safety and well-being of our employees and the communities in which we operate,” said Dave Hager, president and CEO. “I want to commend our workforce for rapidly adjusting to difficult industry conditions. Our strong second-quarter operational results demonstrate the professionalism of our employees to safely execute our business plan and protect shareholder value.”
“In a separate release issued today, we announced the next phase of our strategic plan to accelerate value creation for shareholders,” Hager said. “These actions include initiatives to reduce cash costs by $300 million annually, reduce debt balances by up to $1.5 billion and return cash to shareholders in the form of a $100 million special dividend. These shareholder-friendly initiatives demonstrate our commitment to a new E&P business model, which moderates growth, emphasizes capital efficiencies, generates free cash flow and returns increasing amounts of cash directly to our shareholders.”
OPERATING RESULTS
Second-quarter oil production averaged 153,000 barrels per day, a 6 percent increase from the year-ago period. This result exceeded the company’s midpoint guidance by 3,000 barrels per day, resulting from better-than-expected base production performance in the Eagle Ford and Anadarko Basin. Due to low oil prices in the quarter, Devon elected to voluntarily curtail 10,000 barrels per day. As oil prices have stabilized and begun to recover, the company has no plans to curtail production in the second half of 2020.
The company’s operating costs, which consists of production expenses, general and administrative (G&A) expenses and financing costs, totaled $13.92 per oil-equivalent barrel (Boe), a 14 percent improvement compared to the second quarter of 2019. Costs in several categories were lower than guidance, most notably Devon’s G&A expense, which declined 31 percent year over year.
Capital spending in the second quarter was $203 million, or 10 percent below midpoint guidance. This positive variance was attributable to efficiency gains in the Delaware Basin and improvements in service-cost pricing. Devon exited the second quarter running nine operated drilling rigs and one completion crew.
Delaware Basin: Net production averaged 149,000 Boe per day, a 24 percent increase compared to the year-ago period. In the second quarter, Devon’s Wolfcamp-oriented capital program brought 22 operated wells online across Southeast New Mexico. Completed well costs for activity targeting the Wolfcamp formation improved to a new record of $700 per foot. In addition to capital efficiencies, the company continued to lower its operating costs, with production expenses declining 20 percent year over year to $7.58 per Boe.
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Powder River Basin: Production averaged 24,000 Boe per day, of which 76 percent was oil. During the quarter, Devon dropped its drilling rigs in the basin and limited activity to bringing 4 new wells online. The average completed well cost for this activity, targeting the Parkman and Turner formations, was $5.9 million. For the remainder of 2020, the capital program is focused on appraisal work in the emerging Niobrara oil play. A key upcoming project is the Steinle pad, a 3-well spacing test targeting the Niobrara “B” interval. The Steinle pad is expected to commence production in the third quarter.
Eagle Ford: Second-quarter net production averaged 53,000 Boe per day, an 8 percent increase compared to the second quarter 2019. The company brought online 13 development wells in the quarter, averaging 30-day rates of 2,300 Boe per day. Completed well costs for this activity averaged $6.6 million. Devon and its partner are not currently operating drilling rigs or completion crews in the play. The partnership has 22 high-impact uncompleted wells in its inventory and expects to resume capital activity around year-end.
Anadarko Basin: Net production averaged 90,000 Boe per day. The company’s operational focus during the quarter was concentrated on optimizing base production and reducing controllable downtime across the field. Devon does not currently operate drilling rigs or completion crews in the basin.
FINANCIAL RESULTS
Devon reported a net loss of $670 million, or $1.78 per diluted share, in the second quarter. The quarterly result was negatively impacted by a $593 million unrealized change in the fair value of the company’s derivative position due to higher futures commodity pricing. Adjusting for items analysts typically exclude from estimates, Devon had a core loss of $66 million, or $0.18 per diluted share. The company’s operating cash flow in the second quarter totaled $150 million, with EBITDAX reaching $325 million.
Devon’s financial position continues to remain exceptionally strong with excellent liquidity and low leverage. The company exited the second quarter with $1.7 billion of cash (inclusive of restricted cash) and an undrawn credit facility of $3 billion. At the end of the quarter, Devon had an outstanding debt balance of $4.3 billion with no outstanding debt maturities occurring until late 2025.
STRATEGIC INITIATIVES UPDATE
In a separate press release issued today, Devon announced the accelerated closing of its Barnett Shale divestiture to Oct. 1, 2020, from the previously anticipated date of Dec. 31, 2020. The company also provided details on the next phase of its strategic plan. These strategic initiatives include the board declaring a $100 million special dividend and a plan to reduce G&A and other cash costs by $300 million annually. In addition, Devon intends to use surplus cash to repurchase up to $1.5 billion of debt.
UPDATED 2020 GUIDANCE
Devon is lowering its full-year 2020 E&P capital expenditure guidance to a range of $950 million to $1 billion, a $25 million reduction compared to prior midpoint expectations. This improvement is driven by capital efficiency gains in the Delaware Basin. For the third quarter of 2020, the company expects to invest approximately $175 million to $225 million of upstream capital.
In conjunction with the improved full-year capital spending outlook, Devon is raising its full-year oil production forecast in 2020 to a range of 148,000 to 152,000 barrels per day due to strong base production performance across its diversified asset portfolio. In the third quarter, due to timing of completion activity, the company expects oil production to decline to a range of 138,000 to 143,000 barrels per day.
Additionally, the company is lowering its 2020 expense outlook across most cash cost categories. The improved cost structure is driven by expectations of lower production costs coupled with further reductions in G&A expense. The details of Devon’s updated forward-looking guidance for the third quarter and full-year 2020 are available on the company’s website at www.devonenergy.com.
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CONFERENCE CALL WEBCAST AND SUPPLEMENTAL EARNINGS MATERIALS
Also provided with today’s release is the company’s detailed earnings presentation that is available on the company’s website at www.devonenergy.com. The company’s second-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, Aug. 5, 2020, and will serve primarily as a forum for analyst and investor questions and answers.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE
Devon strives to deliver results that balance economic growth, environmental stewardship, strong governance and social responsibility. For access to Devon’s sustainability report, please visit www.devonenergy.com/sustainability. This report highlights the company’s commitment to operating a responsible, safe and ethical business while providing transparent reporting to all stakeholders.
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. with an emphasis on achieving strong corporate-level returns and capital-efficient cash-flow growth.
| Investor Contacts | Media Contact | |||
| Scott Coody, 405-552-4735 | John Porretto, 405-228-7506 | |||
| Chris Carr, 405-228-2496 |
FORWARD-LOOKING STATEMENTS AND NON-GAAP DISCLOSURES
This press release includes non-GAAP (generally accepted accounting principles) 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 results as reported under GAAP. Reconciliations of these non-GAAP measures and other disclosures are provided within the supplemental financial tables that are available on the company’s website and in our related Form 10-Q.
This press release includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases such as “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “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 Devon 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 our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to those, identified below.
The COVID-19 pandemic and its related repercussions have created significant volatility, uncertainty and turmoil in the global economy and our industry. This turmoil has included an unprecedented supply-and-demand imbalance for oil and other commodities, resulting in a swift and material decline in commodity prices in early 2020. Our future actual results could differ materially from the forward-looking statements in this press release due to the COVID-19 pandemic and related impacts, including, by, among other things: contributing to a sustained or further deterioration in commodity prices; causing takeaway capacity constraints for production, resulting in further production shut-ins and additional downward pressure on impacted regional pricing differentials; limiting our ability to access sources of capital due to disruptions in financial markets; increasing the risk of a downgrade from credit rating agencies; exacerbating counterparty credit risks and the risk of supply chain interruptions; and increasing the risk of operational disruptions due to social distancing measures and other changes to business practices.
In addition to the risks associated with the COVID-19 pandemic and its related impacts, our actual future results could differ materially from our expectations due to other factors, including, among other things: 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 uncertainties, costs and risks involved in our operations, including as a result of employee misconduct; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks related to regulatory, social and market efforts to address climate change; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate some of 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 assets, materials, people and capital; risks related to investors attempting to effect change; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties discussed in our 2019 Annual Report on Form 10-K and our other filings with the SEC.
All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.
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August 4, 2020 Q2 2020 Earnings Presentation Exhibit 99.2
Key Takeaways From Our Earnings Presentation Q2 operating results drive improved 2020 outlook Barnett Shale closing accelerated to Oct. 1 2021 maintenance capital improved by ~15% Cash cost reductions of $300MM by year end Plan to repurchase up to $1.5 billion of debt Board declares $100MM special dividend POWDER RIVER BASIN ANADARKO BASIN EAGLE FORD DELAWARE BASIN 24 MBOED (76% OIL) 149 MBOED (53% OIL) 90 MBOED (52% LIQUIDS) 53 MBOED (51% OIL) KEY DEVON ATTRIBUTES oil weighted: 78% of revenue (2020 YTD) strong liquidity: $4.7 billion (6/30/20) top-tier esg performance (pg. 16) #1 #2 #3 #4 #5 #6
Our Approach to Managing the Business PROGRESSIVE GROWTH STRATEGY moderated oil growth targets: up to 5% annually Expand margins through operational & corporate cost reductions REDUCED REINVESTMENT RATES Targeting 70%-80% of operating cash flow (at mid-cycle pricing) Disciplined returns-driven strategy to generate higher free cash flow MAINTAIN LOW LEVERAGE Targeting net debt-to-EBITDAX ratio: 0.5x – 1.0x Strong liquidity & hedging program provide margin of safety PRIORITIZE CASH RETURNS Deploying free cash flow to dividends & opportunistic buybacks Board approves Devon’s initial special dividend (pg. 14) PURSUE ESG EXCELLENCE Committed to delivering industry-leading ESG results ESG initiatives incorporated into compensation structure “The fundamental changes that underpin our transition to a cash-return business model will transform Devon from a highly-efficient oil and gas operator to a prominent and consistent builder of economic value through the cycle.” Dave Hager President & CEO
Q2 2020 – Operating Highlights Curtailments limited oil volumes by ~10,000 BOD in Q2 No plans to restrict production in second-half of 2020 Delaware capital efficiencies continue to accelerate (pg. 10) Regional oil realizations recovering in Q3 Key Messages UPDATED 2020 OUTLOOK SEE PAGE 6 FOR DETAILS G&A EXPENSES CAPITAL INVESTMENT OIL PRODUCTION $203 million RESILIENT PRODUCTION $79 million CAPITAL EFFICIENCIES IMPROVED COSTS 3 MBOD ABOVE GUIDANCE 10% BELOW GUIDANCE 31% YEAR-OVER-YEAR 153 MBOD
Q2 2020 – Asset-Level Highlights Exited quarter with 9 rigs & 1 frac crew running Industry-leading Wolfcamp efficiencies accelerate (pg. 10) Per-unit production expense improved 20% vs. last year POWDER RIVER EAGLE FORD ANADARKO BASIN MULTI-BASIN PORTFOLIO DELIVERING STRONG RESULTS DELAWARE BASIN Niobrara appraisal program continues to progress 3-well Niobrara spacing test online in early Q3 Targeted Niobrara D&C costs: <$7 million by year-end Production increased 8% year-over-year to 53 MBOED 13 development wells brought online – IP30: 2,300 BOED Successful redevelopment appraisal confirms resource upside $100 million Dow drilling carry to enhance returns Dow to fund ~65% of capital on 133 undrilled locations competitive economics at >$2.50 Henry Hub pricing Q2 OUTPERFORMANCE DRIVES IMPROVED OUTLOOK (SEE PAGE 6 FOR DETAILS) See appendix for more asset-level details
Strong Execution Driving Improved 2020 Outlook Raising 2020 oil outlook due to base production performance Anadarko MVC expirations to provide $65MM benefit in 2021 Improving G&A expense outlook for 2nd time in 2020 Cost savings achieved year-to-date driving per-unit costs lower Higher oil production expected in Q4 vs. Q3 (timing of completions) Expect to bring online 65 to 70 wells in 2H 2020 (~60% in Q4) Driven by improvements in Delaware Basin costs & cycle times Scaled operations to generate free cash flow in 2H 2020 Barnett divestiture to close earlier than planned (pg. 7) Updated Guidance vs. Prior Guidance Key Messages Annual run-rate to reach $250 million by year-end (pg. 12) Excess cash flow represents operating cash flow plus remaining proceeds expected from Barnett divestiture less capital expenditures. Oil production LOE & GP&T G&A Upstream capital Excess cash flow $950 – $1,000 ($ in millions) 148 – 152 (MBOD) $7.95 – $8.15 (per BOE) $315 – $335 ($ in millions) Improvement $0.15 Million $25 Per BOE Improvement Improvement Million $35 2,500 BOD Improvement Improvement $0.1 Billion (1) $0.5 billion (in 2H 2020)
Accelerating Barnett Shale Closing Date Generating excess cash flow in second half of 2020 ($ in billions) $1.6 B $0.8 B $0.4 B $0.5 B Assumes >$300 million of net proceeds from Barnett sale closing after purchase price adjustments. Includes severance and income tax refunds. Excess cash flow represents operating cash flow plus remaining proceeds expected from Barnett divestiture less capital expenditures. DIVEST PROCEEDS UPSTREAM REVENUES 2H 2020e Cash Inflows Upstream Capital Cash Operating Costs 2H 2020e Excess Cash Flow (1) ASSUMES $40 WTI FOR REMAINDER OF 2020 $0.1 B Other (2) Accelerated closing to October 1st (previously YE20) Received $170 million deposit in Q2 >$300 million due at closing after adjustments Potential for $260 million of contingent payments BARNETT SHALE DIVESTITURE (Closing date: Oct. 1, 2020) UPDATE Barnett divestiture bolsters liquidity (3)
Significant Financial Strength & Liquidity $73 Strong liquidity with no near-term debt maturities Outstanding debt maturities ($MM) $4,700 Liquidity CREDIT FACILITY $3,000 $1,700 CASH $485 >5 YEARS UNTIL INITIAL MATURITY (DUE 12/15/2025) (as of 6/30/20) PEER AVERAGE Source: DVN & FactSet Balance sheet strength provides competitive advantage Net debt to 2020e EBITDAX Industry Peers TOP-QUARTILE LEVERAGE PROFILE ADVANTAGED POSITION VS. PEERS (1) Net debt and EBITDAX are non-GAAP measures. Non-GAAP reconciliations are provided in Q2 earnings release materials. Excellent liquidity ($4.7 billion) No near-term debt maturities $1.5B debt reduction program (pg.14) ü ü ü SIGNIFICANT FINANCIAL STRENGTH (1) Notes: Liquidity does not include free cash flow expected in 2H of 2020 or >$300 million of remaining Barnett proceeds. $2.8 billion of the credit facility matures in Oct. 2024, with the balance maturing in Oct. 2023.
Investment Concentrated in the Delaware Basin Eddy New Mexico Lea POTATO BASIN THISTLE/GAUCHO RATTLESNAKE COTTON DRAW TODD Q2 RESULTS – RATES RESTRICTED DUE TO MARKET CONDITIONS SUSTAINABLE RESOURCE OPPORTUNITY >200,000 NET ACRES WITH STACKED PAY DEVELOPMENT EFFICIENCIES CONTINUE TO ACCELERATE (pg. 10) Todd (7,300’ laterals) 8 Wolfcamp & Bone Spring wells Avg. IP30: 1,900 BOED/well WOLFCAMP & bone SPRING CO-DEVELOPMENT IN TODD Red Bull (10,100’ laterals) 4 Bone Spring wells Avg. IP30: 1,400 BOED/well VALIDATES 3RD Bone Spring POTENTIAL Chincoteague (11,400’ laterals) 4 Leonard wells Avg. IP30: 2,600 BOED/well successful Leonard development activity Green Wave (9,700’ laterals) 6 Wolfcamp wells Avg. IP30: 1,700 BOED/well STRONG RESULTS FROM WOLFCAMP DEVELOPMENT Core Development Area Key Q2 2020 Projects Upcoming Projects ALLOCATED TO DELAWARE BASIN 75% Powder River Basin Delaware Basin Eagle Ford Anadarko Basin ~ Efficiencies driving improved outlook 2020e E&P capital ($MM) $950 - $1,000 (¯$25 MM REDUCTION)
Operational Efficiencies Continue to Accelerate Delivering best-in-class capital efficiency… Drilled and completed feet per day (Wolfcamp formation) 1,190 950 625 820 PEER AVERAGE Source: Enverus, J.P. Morgan North America Equity Research While achieving superior well results Average cumulative 6-month oil production per foot, MBO (2019) Top Delaware Basin Producers Top Delaware Basin Producers SUPERIOR WELL RESULTS >50% VS. PEER AVG. 820 (1) Compared to 2018 average. Cost excludes facilities. (2) Includes Leonard, Bone Spring & Wolfcamp formations. 1,190 1,300 1,700 Drilling (feet per day) Completions (feet per day) D&C COSTS IMPROVE 42% Q2 AVG. $700/FT. (1) ALL ZONES: $650/FT. (2)
Efficiencies Drive Maintenance Capital Improvements Preserving productive capacity into 2021 Oil production (MBOD) Wolfcamp success driving capital efficiency gains Maintenance capital ($ millions) $1,300 2021e “Stay-Flat” Capital $950 $150 MILLION REDUCTION (VS. PRIOR TARGET) NEW 138-143 DUC INVENTORY PROVIDES OPTIONALITY (~100 DUCs AT YE 2020) 141-146 THIRD FRAC CREW IN DELAWARE DRIVES HIGHER ACTIVITY (~40 NEW WELLS) TIMING OF COMPLETIONS TO LIMIT Q3 OIL VOLUMES (~30 NEW WELLS) $750 OPTIONALITY TO LOWER CAPITAL REQUIREMENTS ASSUMES NO DRAWDOWN OF DUC INVENTORY ASSUMES DRAWDOWN OF DUC INVENTORY 2019-2020 Average 2021e Maintenance Capital Maintenance capital is defined as investment required to keep oil production flat on an annualized basis. Improvement in maintenance capital is driven by capital efficiency gains, service cost deflation and improvements in base production results. “Stay-Flat” capital is the minimal amount of capital required to keep 2021 production flat. This scenario differs from maintenance capital and would result in declines in future years. (3) (2) (1)
Sustainable Improvements to Cash Cost Structure Note: Represents reported amounts, which includes upstream results in discontinued operations, but excludes EnLink. Cash cost reductions by year-end 2020 Cost savings by category vs. Q2 2020 annual run-rate ($MM) $300 ANNUAL COST SAVINGS BY YEAR-END 2020 $100 G&A FINANCING COSTS LOE & GP&T MILLION MILLION $125 MILLION $75 MILLION PV-10 OF SAVINGS (OVER NEXT 5 YEARS): >$1 BILLION Committed to driving corporate costs lower Annual G&A & financing costs ($MM) $932 Financing Costs G&A $450 VS. 2018 IMPROVEMENT >50% NEW
Operations Scaled to Generate Free Cash Flow Substantial improvements to breakeven funding 2021e pro forma capital & cost efficiencies (per Boe) Note: Free cash flow represents 2021e operating cash flow less maintenance capital requirements of $950 million (see page 11) before dividends. Assumes $2.50 Henry Hub & Mt. Belvieu is 35% of WTI. Calculation also assumes cost savings are fully realized at the beginning of 2021 and market capitalization as of 7/31/2020. $45 WTI $50 WTI Free cash flow yield at maintenance capital 2021e free cash flow yield sensitivities $55 WTI 10% FREE CASH FLOW YIELD 16% FREE CASH FLOW YIELD 21% FREE CASH FLOW YIELD MAINTENANCE CAPITAL SCENARIO $950 MILLION Production Expenses Maintenance Capital General & Administrative Financing Costs 2021e All-In Sustaining Cash Costs Note: Assumes pro forma cash costs are fully realized at the beginning of 2021 and a maintenance capital program of $950 million. (1) $35 WTI funding level is before quarterly dividend. $35 WTI FUNDED AT (1) $7 SEE PAGES 11 & 12 IMPROVEMENT PER BBL NEW
Free Cash Flow Priorities Committed to low financial leverage Resuming debt reduction program (up to $1.5 billion) Targeting net debt-to-EBITDAX ratio: 0.5x – 1.0x Maintain quarterly dividends Current quarterly dividend $0.11 per share Target payout: up to 10% of cash flow (mid-cycle pricing) Potential to increase payout as base declines moderate Initial special dividend approved Effective tool to disburse excess cash to shareholders Board approved $100 million special dividend Payable Oct. 1st in conjunction with Barnett closing Evaluate opportunistic share repurchases Repurchased 28% of shares outstanding since 2018 NEW NEW >$2 Billion $0.2B $1.5B $0.5B DIVIDENDS QUARTERLY & SPECIAL DISTRIBUTIONS Represents cash balance as of 6/30/20 plus expected excess cash flow in 2H 2020. (1) UP TO DEBT REDUCTION ENHANCING FINANCIAL STRENGTH RETAINED CASH ON-HAND PROVIDES WORKING CAPITAL FLEXIBILITY FUNDING ALL PRIORITIES WITH CASH ON-HAND 2H 2020 Cash Priorities
Diversified Portfolio Provides Optionality Federal acreage limited to 20% of total leasehold >50% of acreage in Delaware & Powder River No exposure in Eagle Ford & Anadarko Basin Risk management strategy for next presidential term Actively building a deep inventory of federal permits Expect to have >550 federal permits approved by this fall Permits cover >75% of desired activity over next 4 years significant optionality on high-quality, non-federal land Industry an important economic driver in community Revenue from federal lands shared with states New Mexico derives ~40% of revenue from industry Activity supports local jobs and economic opportunity NET ACREAGE FEDERAL LEASEHOLD % 2020e SPUDS FEDERAL PERMITS Delaware Basin >200,000 55% 120 400 Powder River Basin >300,000 60% 15 >150 Eagle Ford 40,000 0% 10 N/A Anadarko Basin 400,000 0% 0 N/A TARGETED Capital ALLOCATION 70% DELAWARE BASIN 30% OTHER ASSETS $950 Million Maintenance Capital (Next Presidential Term) REPRESENTS 2021e MAINTENANCE CAPITAL LEVELS (SEE PG. 11) 75% FEDERAL PERMITS APPROVED BY YE 2020 > (1) Including acreage outside core area, ~40% of Delaware is federal leasehold. (1)
Highly-Regarded ESG Performance top-quartile vs. peers top-half vs. peers 15 consecutive years of CDP reporting top-decile vs. peers ENVIRONMENT SOCIAL & SAFETY GOVERNANCE On track to meet our methane intensity target of 0.28% or lower by 2025 U.S. recycled water increased >300% since 2016 Reduced methane emissions by ~20% over the last three years Provided STEM resources across our communities, impacting 17,000 students 88% of operational spending is with our highest safety-rated contractors Total recordable incident rate (TRIR) improved 10% year-over-year ESG metrics incorporated in compensation structure Board independence and tenure in-line with S&P 500 averages Diverse board consisting of 27% women board members For additional information please refer to Devon Energy’s 2019 Sustainability Report #1 environmental DELIVERING TOP-TIER ESG RATINGS performer vs. peers
Why Own Devon? Premier multi-basin portfolio Significant financial strength & liquidity Disciplined returns-driven strategy Delivering top-tier operating results Committed to returning cash to shareholders POWDER RIVER BASIN ANADARKO BASIN EAGLE FORD DELAWARE BASIN 24 MBOED (76% OIL) 149 MBOED (53% OIL) 90 MBOED (52% LIQUIDS) 53 MBOED (51% OIL) KEY DEVON ATTRIBUTES oil weighted: 78% of revenue (2020 YTD) strong liquidity: $4.7 billion (6/30/20) top-tier esg performance (pg. 16)
Appendix
Q2 2020 - ASSET DETAIL DEVON DELAWARE POWDER RIVER EAGLE FORD ANADARKO OTHER PRODUCTION Oil (MBbl/d) 153 79 18 27 21 8 NGL (MBbl/d) 69 29 2 12 25 1 Gas (MMcf/d) 614 241 20 87 262 4 Total (MBoe/d) 325 149 24 53 90 9 ASSET MARGIN (per Boe) Realized price $14.37 $15.39 $20.80 $12.90 $10.98 $22.95 Lease operating expenses ($3.69) ($3.56) ($6.60) ($2.59) ($2.42) ($17.40) Gathering, processing & transportation ($4.16) ($2.88) ($2.71) ($4.96) ($6.57) ($0.34) Production & property taxes ($1.07) ($1.14) ($2.40) ($0.85) ($0.32) ($5.11) Field-level cash margin $5.45 $7.81 $9.09 $4.50 $1.67 $0.10 CAPITAL INVESTMENT ($MM) Operated capital $192 $142 $38 $10 $2 – Non-operated capital $11 $6 $1 – $1 $3 Total capital investment $203 $148 $39 $10 $3 $3 . CAPITAL ACTIVITY Operated development rigs (avg.) 10 9 1 – – – Operated frac crews (avg.) 1 1 – – – – Gross operated spuds 27 27 – – – – Gross operated wells tied-in 39 22 4 13(1) – – Net operated wells tied-in 29 18 4 7 – – Average lateral length (based on wells tied-in) 7,900’ 9,100’ 8,100’ 5,900’ – – Q2 2020 – Asset-Level Modeling Stats For additional modeling stats and guidance see our Q2 earnings release tables Does not Include 4-well Sandy redevelopment brought online in late Q1, but reached 30-day peak rates in Q2.
Delaware – Development Projects Advancing on Plan POTATO BASIN TODD COTTON DRAW THISTLE/GAUCHO RATTLESNAKE Eddy Lea New Mexico DELAWARE BASIN UPCOMING ACTIVITY Activity transitioning to Wolfcamp formation % of Delaware Basin drilling activity 24% 45% 70% 2018 2019 2020e VanMar 2.0 4 Bone Spring wells Blue Krait 7 Wolfcamp wells Bell Lake 2.0 7 Wolfcamp wells Purrito 5 Bone Spring wells Belloq 2.0 5 Wolfcamp & Bone Spring wells Papas Fritas 8 Wolfcamp & Bone Spring wells Mustang 4 Bone Spring wells Q2-2020a Q3-2020e Q4-2020e Q1-2021e Drilling Purrito (5 Bone Spring wells) Completion Drilling Belloq 2.0 (5 wells in the Wolfcamp & Bone Spring) Completion Papa Fritas (8 wells in the Wolfcamp & Bone Spring) Drilling Completion Completion Bell Lake 2.0 (7 Wolfcamp wells) Production Production VanMar 2.0 (4 Bone Spring wells) Completion Production Mustang (4 Bone Spring wells) Completion Production Q3 2020e Projects Online Blue Krait (7 Wolfcamp wells) Drilling Completion Production Production Production Diversified capital program across core development areas Upcoming developments in second-half of 2020 1 2 3 4 5 6 1 2 3 4 5 6 7 7
Powder River Basin – Advancing Niobrara Appraisal NIOBRARATYPE LOG 200 ft. Potential landing zones C B A 100 ft. Q2 production averaged 24 MBOED Light-oil volumes >75% of production mix Production expense improved 11% vs. Q1 2020 stacked-pay position in oil fairway (>300k acres) Niobrara appraisal activity continues to progress >10 operated wells online (avg. IP30: 1,300; 87% oil) Delivering highest rate oil wells in the basin next catalyst: 3-well Steinle spacing test in Q3 Targeted D&C cost: <$7 mm per well(1) Moderating activity in current environment Second-half 2020e capital spend: ~$30 million Remaining activity focused on niobrara appraisal Minimal leasehold drilling obligations Target by year-end 2020 for a development well, excluding facilities. NIOBRARA APPRAISAL ACTIVITY CONTINUES STACKED PAY POSITION IN OIL FAIRWAY Converse ATLAS WEST ATLAS EAST Steinle Pad (9,600’ laterals) Niobrara Spacing Test (3 wells) Online in Q3 3-WELL NIOBRARA SPACING TEST NIOBRARA DELINEATION ACTIVITY NIOBRARA APPRAISAL PROGRAM 10 WELLS AVG. IP30: 1,300 BOED (87% OIL) ONLINE-TO-DATE > Upcoming Activity Prior Activity
Eagle Ford – Expanding Resource Opportunity Q2 production averaged 53 MBOED (51% oil) 13 new lower Eagle Ford wells online in Q2 (see map) Net production increased 7% vs. prior quarter Production expenses decline 23% vs. year-ago quarter Successful appraisal activity unlocks resource 2nd redevelopment spacing test brought online in Q2 Sandy project: avg. IP30 of 1,250 BOED (4-well project) Flowback rates restricted due to market conditions EUR’s expected to average >500,000 MBOE Deferring capital activity in 2H 2020 due to low prices Partnership released all rigs & frac crews in Q2 Uncompleted well inventory: 22 wells (at 6/30/20) Expect to restart D&C activity around year end EAGLE FORD ACTIVITY Dewitt Karnes UPPER EAGLE FORD LOWER EAGLE FORD 440’ Confirms redevelopment spacing up to 12 wells/section Existing development spacing at 12 wells/section Sandy (4,700’ laterals) 4 Eagle Ford Redevelopment wells Avg. IP30: 1,250 BOED/well(1) 440’ 440’ 2nd redevelopment spacing tesT Jordan Unit (5,900’ laterals) 13 Lower Eagle Ford wells Avg. IP30: 2,300 BOED/well(1) SUCCESSFUL Eagle FORD DEVELOPMENT project Production rates reflect restricted flowback methodology due to current market conditions. NET PRODUCTION 53 MBOED Q2 2020 SANDY REDEVELOPMENT
Anadarko Basin – Optimizing Base Production Results Base production efforts improve decline profile Q2 net production: 90 MBOED (52% liquids) outperformed plan 7% year-to-date Driven by well workovers and reduced downtime MVC expirations provide $65 million benefit in 2021 Drilling partnership formed with Dow (NYSE: DOW) Sold ½ working interest in 133 undrilled locations drilling carry of ~$100 million over next 4 years Dow to fund 65% of partnership capital requirements Potential to commence drilling operations in early 2021 Combo play with exposure to rising gas prices Economics competitive at >$2.50 Henry Hub pricing Significant inventory provides long-term optionality ANADARKO BASIN RECENT ACTIVITY Blaine Canadian Kingfisher Future Dow Activity DELAYING DOW DRILLING PARTNERSHIP ACTIVITY FUTURE DOW FOCUS AREA Jacobs Row (2 DSUs) 18 Woodford wells 10,000’ laterals Project timing TBD Recent Results Privott (9,800’ laterals) 4 Meramac wells Avg. IP30: 1,200 BOED/well(1) INFILL DEVELOPMENT (ACTIVITY NOT RELATED TO DOW) INITIAL DOW JV ACTIVITY (DRILLING partnership) FOCUSED ON OPTIMIZING CASH FLOW GENERATION Production rates reflect restricted flowback methodology due to current market conditions. DOW DRILLING JV ~ MILLION CARRY OVER NEXT 4 YEARS $100
Investor Contacts & Notices Investor Relations Contacts Scott CoodyChris Carr VP, Investor RelationsManager, Investor Relations 405-552-4735405-228-2496 Email: [email protected] Forward-Looking Statements This presentation includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases such as “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “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 Devon 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 our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to those, identified below. The COVID-19 pandemic and its related repercussions have created significant volatility, uncertainty and turmoil in the global economy and our industry. This turmoil has included an unprecedented supply-and-demand imbalance for oil and other commodities, resulting in a swift and material decline in commodity prices in early 2020. Our future actual results could Investor Notices differ materially from the forward-looking statements in this presentation due to the COVID-19 pandemic and related impacts, including, by, among other things: contributing to a sustained or further deterioration in commodity prices; causing takeaway capacity constraints for production, resulting in further production shut-ins and additional downward pressure on impacted regional pricing differentials; limiting our ability to access sources of capital due to disruptions in financial markets; increasing the risk of a downgrade from credit rating agencies; exacerbating counterparty credit risks and the risk of supply chain interruptions; and increasing the risk of operational disruptions due to social distancing measures and other changes to business practices. In addition to the risks associated with the COVID-19 pandemic and its related impacts, our actual future results could differ materially from our expectations due to other factors, including, among other things: 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 uncertainties, costs and risks involved in our operations, including as a result of employee misconduct; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks related to regulatory, social and market efforts to address climate change; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate some of 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 assets, materials, people and capital; risks related to investors attempting to effect change; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties discussed in our 2019 Annual Report on Form 10-K and our other filings with the SEC. All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on 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 second-quarter 2020 earnings materials at www.devonenergy.com and Form 10-Q filed with the SEC. 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 high-return inventory, 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. Investors are urged to consider closely the disclosure in our Form 10-K, available at www.devonenergy.com or the SEC’s website.
Exhibit 99.3
Devon Energy Second-Quarter 2020
Supplemental Tables
| TABLE OF CONTENTS: | PAGE: | |||
| Income Statement |
2 | |||
| Cash Flow Statement |
3 | |||
| Balance Sheet |
4 | |||
| Production by Asset |
5 | |||
| Capital and Well Activity by Asset |
6 | |||
| Realized Price by Asset |
7 | |||
| Per-Unit Cash Margin by Asset |
8 | |||
| Non-GAAP Core Earnings (Loss) |
9 | |||
| Non-GAAP EBITDAX, Net Debt and Net Debt-to-EBITDAX |
10 | |||
| CONSOLIDATED STATEMENTS OF EARNINGS |
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| (in millions, except per share amounts) | 2020 | 2019 | ||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Oil, gas and NGL sales |
$ | 424 | $ | 807 | $ | 1,035 | $ | 919 | $ | 936 | ||||||||||
| Oil, gas and NGL derivatives (1) |
(361 | ) | 720 | (116 | ) | 127 | 140 | |||||||||||||
| Marketing and midstream revenues |
331 | 560 | 670 | 700 | 730 | |||||||||||||||
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| Total revenues |
394 | 2,087 | 1,589 | 1,746 | 1,806 | |||||||||||||||
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| Production expenses (2) |
263 | 318 | 324 | 294 | 296 | |||||||||||||||
| Exploration expenses |
12 | 112 | 29 | 18 | 7 | |||||||||||||||
| Marketing and midstream expenses |
339 | 578 | 665 | 684 | 713 | |||||||||||||||
| Depreciation, depletion and amortization |
299 | 401 | 382 | 381 | 374 | |||||||||||||||
| Asset impairments |
— | 2,666 | — | — | — | |||||||||||||||
| Asset dispositions |
— | — | — | (1 | ) | (2 | ) | |||||||||||||
| General and administrative expenses |
79 | 102 | 119 | 107 | 114 | |||||||||||||||
| Financing costs, net |
69 | 65 | 64 | 60 | 66 | |||||||||||||||
| Restructuring and transaction costs |
— | — | 11 | 10 | 12 | |||||||||||||||
| Other expenses |
13 | (48 | ) | 16 | 3 | 7 | ||||||||||||||
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| Total expenses |
1,074 | 4,194 | 1,610 | 1,556 | 1,587 | |||||||||||||||
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| Earnings (loss) from continuing operations before income taxes |
(680 | ) | (2,107 | ) | (21 | ) | 190 | 219 | ||||||||||||
| Income tax expense (benefit) |
(3 | ) | (417 | ) | (33 | ) | 54 | 68 | ||||||||||||
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| Net earnings (loss) from continuing operations |
(677 | ) | (1,690 | ) | 12 | 136 | 151 | |||||||||||||
| Net earnings (loss) from discontinued operations, net of taxes |
9 | (125 | ) | (652 | ) | (27 | ) | 344 | ||||||||||||
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| Net earnings (loss) |
(668 | ) | (1,815 | ) | (640 | ) | 109 | 495 | ||||||||||||
| Net earnings attributable to noncontrolling interests |
2 | 1 | 2 | — | — | |||||||||||||||
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| Net earnings (loss) attributable to Devon |
$ | (670 | ) | $ | (1,816 | ) | $ | (642 | ) | $ | 109 | $ | 495 | |||||||
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| Basic net earnings (loss) per share: |
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| Continuing operations |
$ | (1.80 | ) | $ | (4.48 | ) | $ | 0.03 | $ | 0.34 | $ | 0.37 | ||||||||
| Discontinued operations |
0.02 | (0.34 | ) | (1.73 | ) | (0.07 | ) | 0.83 | ||||||||||||
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| Basic net earnings (loss) per share |
$ | (1.78 | ) | $ | (4.82 | ) | $ | (1.70 | ) | $ | 0.27 | $ | 1.20 | |||||||
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| Diluted net earnings (loss) per share: |
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| Continuing operations |
$ | (1.80 | ) | $ | (4.48 | ) | $ | 0.03 | $ | 0.34 | $ | 0.37 | ||||||||
| Discontinued operations |
0.02 | (0.34 | ) | (1.73 | ) | (0.07 | ) | 0.82 | ||||||||||||
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| Diluted net earnings (loss) per share |
$ | (1.78 | ) | $ | (4.82 | ) | $ | (1.70 | ) | $ | 0.27 | $ | 1.19 | |||||||
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| Weighted average common shares outstanding: |
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| Basic |
383 | 383 | 383 | 397 | 415 | |||||||||||||||
| Diluted |
383 | 383 | 385 | 399 | 417 | |||||||||||||||
| (1) OIL, GAS AND NGL DERIVATIVES |
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| (in millions) | 2020 | 2019 | ||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Derivative cash settlements |
$ | 232 | $ | 101 | $ | 42 | $ | 71 | $ | 23 | ||||||||||
| Derivative valuation changes |
(593 | ) | 619 | (158 | ) | 56 | 117 | |||||||||||||
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| Oil, gas and NGL derivatives |
$ | (361 | ) | $ | 720 | $ | (116 | ) | $ | 127 | $ | 140 | ||||||||
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| (2) PRODUCTION EXPENSES |
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| (in millions) | 2020 | 2019 | ||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Lease operating expense |
$ | 108 | $ | 126 | $ | 120 | $ | 118 | $ | 114 | ||||||||||
| Gathering, processing & transportation |
123 | 130 | 131 | 112 | 111 | |||||||||||||||
| Production taxes |
25 | 56 | 69 | 58 | 64 | |||||||||||||||
| Property taxes |
7 | 6 | 4 | 6 | 7 | |||||||||||||||
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| Production expenses |
$ | 263 | $ | 318 | $ | 324 | $ | 294 | $ | 296 | ||||||||||
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2
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
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| (in millions) | 2020 | 2019 | ||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Cash flows from operating activities: |
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| Net earnings (loss) |
$ | (668 | ) | $ | (1,815 | ) | $ | (640 | ) | $ | 109 | $ | 495 | |||||||
| Adjustments to reconcile net earnings (loss) to net cash from operating activities: |
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| Net (earnings) loss from discontinued operations, net of income taxes |
(9 | ) | 125 | 652 | 27 | (344 | ) | |||||||||||||
| Depreciation, depletion and amortization |
299 | 401 | 382 | 381 | 374 | |||||||||||||||
| Asset impairments |
— | 2,666 | — | — | — | |||||||||||||||
| Leasehold impairments |
3 | 110 | 3 | 13 | 1 | |||||||||||||||
| Accretion on discounted liabilities |
8 | 8 | 8 | 8 | 8 | |||||||||||||||
| Total (gains) losses on commodity derivatives |
361 | (720 | ) | 116 | (127 | ) | (140 | ) | ||||||||||||
| Cash settlements on commodity derivatives |
232 | 101 | 41 | 71 | 23 | |||||||||||||||
| Gains on asset dispositions |
— | — | — | (1 | ) | (2 | ) | |||||||||||||
| Deferred income tax expense (benefit) |
— | (311 | ) | (27 | ) | 52 | 65 | |||||||||||||
| Share-based compensation |
19 | 20 | 23 | 23 | 25 | |||||||||||||||
| Other |
4 | — | 2 | 3 | 2 | |||||||||||||||
| Changes in assets and liabilities, net |
(99 | ) | (56 | ) | 18 | 36 | (75 | ) | ||||||||||||
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| Net cash from operating activities - continuing operations |
150 | 529 | 578 | 595 | 432 | |||||||||||||||
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| Cash flows from investing activities: |
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| Capital expenditures |
(307 | ) | (425 | ) | (408 | ) | (526 | ) | (486 | ) | ||||||||||
| Acquisitions of property and equipment |
(1 | ) | (4 | ) | (3 | ) | (5 | ) | (13 | ) | ||||||||||
| Divestitures of property and equipment |
3 | 25 | 43 | 9 | 28 | |||||||||||||||
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| Net cash from investing activities - continuing operations |
(305 | ) | (404 | ) | (368 | ) | (522 | ) | (471 | ) | ||||||||||
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| Cash flows from financing activities: |
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| Repayments of long-term debt |
— | — | — | — | — | |||||||||||||||
| Repurchases of common stock |
— | (38 | ) | (103 | ) | (560 | ) | (187 | ) | |||||||||||
| Dividends paid on common stock |
(42 | ) | (34 | ) | (34 | ) | (35 | ) | (37 | ) | ||||||||||
| Contributions from noncontrolling interests |
6 | 5 | 116 | — | — | |||||||||||||||
| Distributions to noncontrolling interest |
(3 | ) | (3 | ) | — | — | — | |||||||||||||
| Shares exchanged for tax withholdings and other |
— | (17 | ) | (2 | ) | (1 | ) | (3 | ) | |||||||||||
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| Net cash from financing activities - continuing operations |
(39 | ) | (87 | ) | (23 | ) | (596 | ) | (227 | ) | ||||||||||
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| Net change in cash, cash equivalents and restricted cash of continuing operations |
(194 | ) | 38 | 187 | (523 | ) | (266 | ) | ||||||||||||
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| Cash flows from discontinued operations: |
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| Operating activities |
(43 | ) | (131 | ) | (9 | ) | (94 | ) | 191 | |||||||||||
| Investing activities |
171 | (1 | ) | — | (5 | ) | 2,536 | |||||||||||||
| Financing activities |
— | — | — | (1,572 | ) | — | ||||||||||||||
| Effect of exchange rate changes on cash |
8 | (23 | ) | 10 | (3 | ) | 37 | |||||||||||||
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| Net change in cash, cash equivalents and restricted cash of discontinued operations |
136 | (155 | ) | 1 | (1,674 | ) | 2,764 | |||||||||||||
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| Net change in cash, cash equivalents and restricted cash |
(58 | ) | (117 | ) | 188 | (2,197 | ) | 2,498 | ||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period |
1,727 | 1,844 | 1,656 | 3,853 | 1,355 | |||||||||||||||
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| Cash, cash equivalents and restricted cash at end of period |
$ | 1,669 | $ | 1,727 | $ | 1,844 | $ | 1,656 | $ | 3,853 | ||||||||||
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| Reconciliation of cash, cash equivalents and restricted cash: |
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| Cash and cash equivalents |
$ | 1,474 | $ | 1,527 | $ | 1,464 | $ | 1,375 | $ | 3,470 | ||||||||||
| Cash restricted for discontinued operations |
195 | 200 | 380 | 280 | 370 | |||||||||||||||
| Restricted cash included in other current assets |
— | — | — | 1 | 13 | |||||||||||||||
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| Total cash, cash equivalents and restricted cash |
$ | 1,669 | $ | 1,727 | $ | 1,844 | $ | 1,656 | $ | 3,853 | ||||||||||
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3
| CONSOLIDATED BALANCE SHEETS |
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| (in millions) | June 30, | December 31, | ||||||
| 2020 | 2019 | |||||||
| Current assets: |
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| Cash and cash equivalents |
$ | 1,474 | $ | 1,464 | ||||
| Cash restricted for discontinued operations |
195 | 380 | ||||||
| Accounts receivable |
515 | 832 | ||||||
| Current assets associated with discontinued operations |
748 | 896 | ||||||
| Other current assets |
446 | 279 | ||||||
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| Total current assets |
3,378 | 3,851 | ||||||
| Oil and gas property and equipment, based on successful efforts accounting, net |
4,673 | 7,558 | ||||||
| Other property and equipment, net |
1,013 | 1,035 | ||||||
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| Total property and equipment, net |
5,686 | 8,593 | ||||||
| Goodwill |
753 | 753 | ||||||
| Right-of-use assets |
231 | 243 | ||||||
| Other long-term assets |
227 | 196 | ||||||
| Long-term assets associated with discontinued operations |
82 | 81 | ||||||
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| Total assets |
$ | 10,357 | $ | 13,717 | ||||
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| Current liabilities: |
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| Accounts payable |
$ | 309 | $ | 428 | ||||
| Revenues and royalties payable |
473 | 730 | ||||||
| Current liabilities associated with discontinued operations |
441 | 459 | ||||||
| Other current liabilities |
229 | 310 | ||||||
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| Total current liabilities |
1,452 | 1,927 | ||||||
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| Long-term debt |
4,296 | 4,294 | ||||||
| Lease liabilities |
245 | 244 | ||||||
| Asset retirement obligations |
391 | 380 | ||||||
| Other long-term liabilities |
458 | 426 | ||||||
| Long-term liabilities associated with discontinued operations |
162 | 185 | ||||||
| Deferred income taxes |
— | 341 | ||||||
| Stockholders’ equity: |
||||||||
| Common stock |
38 | 38 | ||||||
| Additional paid-in capital |
2,720 | 2,735 | ||||||
| Retained earnings |
586 | 3,148 | ||||||
| Accumulated other comprehensive loss |
(117 | ) | (119 | ) | ||||
|
|
|
|
|
|||||
| Total stockholders’ equity attributable to Devon |
3,227 | 5,802 | ||||||
| Noncontrolling interests |
126 | 118 | ||||||
|
|
|
|
|
|||||
| Total equity |
3,353 | 5,920 | ||||||
|
|
|
|
|
|||||
| Total liabilities and equity |
$ | 10,357 | $ | 13,717 | ||||
|
|
|
|
|
|||||
| Common shares outstanding |
383 | 382 | ||||||
4
| PRODUCTION TREND |
||||||||||||||||||||
| 2020 | 2019 | |||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Oil (MBbls/d) |
||||||||||||||||||||
| Delaware Basin |
79 | 84 | 84 | 70 | 67 | |||||||||||||||
| Powder River Basin |
18 | 21 | 20 | 18 | 15 | |||||||||||||||
| Eagle Ford |
27 | 26 | 23 | 22 | 23 | |||||||||||||||
| Anadarko Basin |
21 | 24 | 27 | 32 | 31 | |||||||||||||||
| Other |
8 | 8 | 9 | 9 | 8 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
153 | 163 | 163 | 151 | 144 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Natural gas liquids (MBbls/d) |
||||||||||||||||||||
| Delaware Basin |
29 | 37 | 32 | 28 | 27 | |||||||||||||||
| Powder River Basin |
2 | 3 | 2 | 2 | 2 | |||||||||||||||
| Eagle Ford |
12 | 9 | 9 | 11 | 12 | |||||||||||||||
| Anadarko Basin |
25 | 30 | 30 | 37 | 40 | |||||||||||||||
| Other |
1 | 1 | 1 | 1 | 1 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
69 | 80 | 74 | 79 | 82 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Gas (MMcf/d) |
||||||||||||||||||||
| Delaware Basin |
241 | 244 | 234 | 167 | 158 | |||||||||||||||
| Powder River Basin |
20 | 29 | 28 | 28 | 22 | |||||||||||||||
| Eagle Ford |
87 | 86 | 76 | 75 | 81 | |||||||||||||||
| Anadarko Basin |
262 | 272 | 295 | 317 | 313 | |||||||||||||||
| Other |
4 | 3 | 4 | 4 | 4 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
614 | 634 | 637 | 591 | 578 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total oil equivalent (MBoe/d) |
||||||||||||||||||||
| Delaware Basin |
149 | 162 | 154 | 127 | 120 | |||||||||||||||
| Powder River Basin |
24 | 29 | 27 | 25 | 21 | |||||||||||||||
| Eagle Ford |
53 | 50 | 45 | 45 | 49 | |||||||||||||||
| Anadarko Basin |
90 | 98 | 107 | 121 | 124 | |||||||||||||||
| Other |
9 | 9 | 10 | 10 | 10 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
325 | 348 | 343 | 328 | 324 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| 2020 | 2019 | |||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Barnett divest assets (discontinued operations) |
||||||||||||||||||||
| Oil (MBbls/d) |
— | — | — | — | 1 | |||||||||||||||
| Natural gas liquids (MBbls/d) |
28 | 31 | 30 | 30 | 30 | |||||||||||||||
| Gas (MMcf/d) |
401 | 408 | 408 | 414 | 420 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total oil equivalent (MBoe/d) |
95 | 99 | 98 | 100 | 100 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
5
| UPSTREAM CAPITAL EXPENDITURES |
||||||||||||||||||||
| (in millions) | 2020 | 2019 | ||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Delaware Basin |
$ | 148 | $ | 220 | $ | 170 | $ | 262 | $ | 235 | ||||||||||
| Powder River Basin |
39 | 90 | 89 | 89 | 87 | |||||||||||||||
| Eagle Ford |
10 | 70 | 65 | 90 | 53 | |||||||||||||||
| Anadarko Basin |
3 | 4 | 38 | 67 | 94 | |||||||||||||||
| Other |
3 | 7 | 12 | 12 | 12 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total upstream capital |
$ | 203 | $ | 391 | $ | 374 | $ | 520 | $ | 481 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
GROSS OPERATED SPUDS
| 2020 | 2019 | |||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Delaware Basin |
27 | 38 | 24 | 38 | 23 | |||||||||||||||
| Powder River Basin |
— | 12 | 19 | 14 | 17 | |||||||||||||||
| Eagle Ford |
— | 10 | 25 | 18 | 31 | |||||||||||||||
| Anadarko Basin |
— | — | — | 4 | 16 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
27 | 60 | 68 | 74 | 87 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
GROSS OPERATED WELLS TIED-IN
| 2020 | 2019 | |||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Delaware Basin |
22 | 32 | 36 | 34 | 28 | |||||||||||||||
| Powder River Basin |
4 | 14 | 19 | 18 | 6 | |||||||||||||||
| Eagle Ford |
13 | 30 | 21 | — | 9 | |||||||||||||||
| Anadarko Basin |
— | 4 | 9 | 16 | 21 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
39 | 80 | 85 | 68 | 64 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
NET OPERATED WELLS TIED-IN
| 2020 | 2019 | |||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Delaware Basin |
18 | 25 | 25 | 30 | 24 | |||||||||||||||
| Powder River Basin |
4 | 10 | 15 | 13 | 5 | |||||||||||||||
| Eagle Ford |
7 | 14 | 11 | — | 4 | |||||||||||||||
| Anadarko Basin |
— | 3 | 7 | 7 | 14 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
29 | 52 | 58 | 50 | 47 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
AVERAGE LATERAL LENGTH
| (based on wells tied-in) | 2020 | 2019 | ||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Delaware Basin |
9,100 | ' | 8,000 | ' | 8,000 | ' | 9,700 | ' | 7,500 | ' | ||||||||||
| Powder River Basin |
8,100 | ' | 9,100 | ' | 9,700 | ' | 9,500 | ' | 9,500 | ' | ||||||||||
| Eagle Ford |
5,900 | ' | 5,400 | ' | 6,600 | ' | N/A | 6,000 | ' | |||||||||||
| Anadarko Basin |
— | 9,800 | ' | 11,200 | ' | 9,600 | ' | 9,000 | ' | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
7,900 | ' | 7,300 | ' | 8,400 | ' | 9,600 | ' | 8,000 | ' | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
6
| BENCHMARK PRICES |
||||||||||||||||||||
| (average prices) | 2020 | 2019 | ||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Oil ($/Bbl) - West Texas Intermediate (Cushing) |
$ | 28.42 | $ | 46.44 | $ | 57.02 | $ | 56.34 | $ | 59.85 | ||||||||||
| Natural Gas ($/Mcf) - Henry Hub |
$ | 1.71 | $ | 1.95 | $ | 2.50 | $ | 2.23 | $ | 2.64 | ||||||||||
| NGL ($/Bbl) - Mont Belvieu Blended |
$ | 12.57 | $ | 14.39 | $ | 18.69 | $ | 16.18 | $ | 19.05 | ||||||||||
| REALIZED PRICES |
||||||||||||||||||||
| 2020 | 2019 | |||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Oil (Per Bbl) |
||||||||||||||||||||
| Delaware Basin |
$ | 22.70 | $ | 45.18 | $ | 56.23 | $ | 53.85 | $ | 55.54 | ||||||||||
| Powder River Basin |
24.03 | 41.14 | 52.02 | 52.50 | 56.79 | |||||||||||||||
| Eagle Ford |
15.30 | 44.90 | 55.11 | 57.77 | 61.60 | |||||||||||||||
| Anadarko Basin |
19.52 | 45.32 | 55.71 | 54.47 | 57.67 | |||||||||||||||
| Other |
25.45 | 44.53 | 55.14 | 54.02 | 55.31 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Realized price without hedges |
21.25 | 44.59 | 55.41 | 54.40 | 57.11 | |||||||||||||||
| Cash settlements |
15.25 | 5.14 | 1.48 | 2.18 | (0.41 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Realized price, including cash settlements |
$ | 36.50 | $ | 49.73 | $ | 56.89 | $ | 56.58 | $ | 56.70 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Natural gas liquids (Per Bbl) |
||||||||||||||||||||
| Delaware Basin |
$ | 7.94 | $ | 8.36 | $ | 13.30 | $ | 10.27 | $ | 13.77 | ||||||||||
| Powder River Basin |
10.07 | 15.86 | 17.36 | 15.01 | 17.74 | |||||||||||||||
| Eagle Ford |
10.02 | 14.77 | 18.84 | 13.77 | 15.84 | |||||||||||||||
| Anadarko Basin |
9.31 | 10.90 | 17.47 | 12.61 | 15.55 | |||||||||||||||
| Other |
10.19 | 15.82 | 13.62 | 12.76 | 10.69 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Realized price without hedges |
8.89 | 10.40 | 15.79 | 12.02 | 15.00 | |||||||||||||||
| Cash settlements |
0.51 | 0.61 | 1.75 | 2.55 | 1.40 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Realized price, including cash settlements |
$ | 9.40 | $ | 11.01 | $ | 17.54 | $ | 14.57 | $ | 16.40 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Gas (Per Mcf) |
||||||||||||||||||||
| Delaware Basin |
$ | 1.05 | $ | 0.58 | $ | 1.22 | $ | 0.90 | $ | (0.05 | ) | |||||||||
| Powder River Basin |
1.80 | 1.71 | 2.51 | 1.96 | 2.16 | |||||||||||||||
| Eagle Ford |
1.79 | 2.05 | 2.52 | 2.26 | 2.56 | |||||||||||||||
| Anadarko Basin |
1.31 | 1.45 | 1.81 | 1.54 | 1.74 | |||||||||||||||
| Other |
1.32 | 1.69 | 0.43 | 2.18 | 1.72 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Realized price without hedges |
1.29 | 1.21 | 1.70 | 1.47 | 1.38 | |||||||||||||||
| Cash settlements |
0.28 | 0.36 | 0.13 | 0.41 | 0.34 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Realized price, including cash settlements |
$ | 1.57 | $ | 1.57 | $ | 1.83 | $ | 1.88 | $ | 1.72 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total oil equivalent (Per Boe) |
||||||||||||||||||||
| Delaware Basin |
$ | 15.39 | $ | 26.19 | $ | 35.05 | $ | 33.48 | $ | 33.94 | ||||||||||
| Powder River Basin |
20.80 | 33.65 | 42.45 | 41.20 | 45.44 | |||||||||||||||
| Eagle Ford |
12.90 | 29.94 | 36.51 | 35.10 | 37.50 | |||||||||||||||
| Anadarko Basin |
10.98 | 18.14 | 24.28 | 22.07 | 23.96 | |||||||||||||||
| Other |
22.95 | 39.15 | 46.49 | 46.08 | 46.70 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Realized price without hedges |
14.37 | 25.43 | 32.82 | 30.47 | 31.79 | |||||||||||||||
| Cash settlements |
7.83 | 3.20 | 1.32 | 2.34 | 0.79 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Realized price, including cash settlements |
$ | 22.20 | $ | 28.63 | $ | 34.14 | $ | 32.81 | $ | 32.58 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
7
| BENCHMARK PRICES |
||||||||||||||||||||
| (average prices) | 2020 | 2019 | ||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Oil ($/Bbl) - West Texas Intermediate (Cushing) |
$ | 28.42 | $ | 46.44 | $ | 57.02 | $ | 56.34 | $ | 59.85 | ||||||||||
| Natural Gas ($/Mcf) - Henry Hub |
$ | 1.71 | $ | 1.95 | $ | 2.50 | $ | 2.23 | $ | 2.64 | ||||||||||
| NGL ($/Bbl) - Mont Belvieu Blended |
$ | 12.57 | $ | 14.39 | $ | 18.69 | $ | 16.18 | $ | 19.05 | ||||||||||
| FIELD-LEVEL CASH MARGIN (per Boe) |
||||||||||||||||||||
| 2020 | 2019 | |||||||||||||||||||
| Quarter 2 | Quarter 1 | Quarter 4 | Quarter 3 | Quarter 2 | ||||||||||||||||
| Delaware Basin |
||||||||||||||||||||
| Realized price |
$ | 15.39 | $ | 26.19 | $ | 35.05 | $ | 33.48 | $ | 33.94 | ||||||||||
| Lease operating expenses |
(3.56 | ) | (3.61 | ) | (3.36 | ) | (4.17 | ) | (4.33 | ) | ||||||||||
| Gathering, processing & transportation |
(2.88 | ) | (2.71 | ) | (2.59 | ) | (2.20 | ) | (2.31 | ) | ||||||||||
| Production & property taxes |
(1.14 | ) | (2.15 | ) | (2.80 | ) | (2.69 | ) | (2.84 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Field-level cash margin |
$ | 7.81 | $ | 17.72 | $ | 26.30 | $ | 24.42 | $ | 24.46 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Powder River Basin |
||||||||||||||||||||
| Realized price |
$ | 20.80 | $ | 33.65 | $ | 42.45 | $ | 41.20 | $ | 45.44 | ||||||||||
| Lease operating expenses |
(6.60 | ) | (6.65 | ) | (5.00 | ) | (7.28 | ) | (6.95 | ) | ||||||||||
| Gathering, processing & transportation |
(2.71 | ) | (2.32 | ) | (3.40 | ) | (2.07 | ) | (1.71 | ) | ||||||||||
| Production & property taxes |
(2.40 | ) | (4.20 | ) | (5.19 | ) | (4.73 | ) | (4.99 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Field-level cash margin |
$ | 9.09 | $ | 20.48 | $ | 28.86 | $ | 27.12 | $ | 31.79 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Eagle Ford |
||||||||||||||||||||
| Realized price |
$ | 12.90 | $ | 29.94 | $ | 36.51 | $ | 35.10 | $ | 37.50 | ||||||||||
| Lease operating expenses |
(2.59 | ) | (2.93 | ) | (4.52 | ) | (3.20 | ) | (2.85 | ) | ||||||||||
| Gathering, processing & transportation |
(4.96 | ) | (5.96 | ) | (6.52 | ) | (5.93 | ) | (5.59 | ) | ||||||||||
| Production & property taxes |
(0.85 | ) | (1.85 | ) | (1.75 | ) | (1.95 | ) | (2.43 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Field-level cash margin |
$ | 4.50 | $ | 19.20 | $ | 23.72 | $ | 24.02 | $ | 26.63 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Anadarko Basin |
||||||||||||||||||||
| Realized price |
$ | 10.98 | $ | 18.14 | $ | 24.28 | $ | 22.07 | $ | 23.96 | ||||||||||
| Lease operating expenses |
(2.42 | ) | (2.79 | ) | (2.24 | ) | (2.08 | ) | (1.84 | ) | ||||||||||
| Gathering, processing & transportation |
(6.57 | ) | (6.36 | ) | (5.98 | ) | (5.05 | ) | (5.10 | ) | ||||||||||
| Production & property taxes |
(0.32 | ) | (0.77 | ) | (1.00 | ) | (0.86 | ) | (1.25 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Field-level cash margin |
$ | 1.67 | $ | 8.22 | $ | 15.06 | $ | 14.08 | $ | 15.77 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Other |
||||||||||||||||||||
| Realized price |
$ | 22.95 | $ | 39.15 | $ | 46.49 | $ | 46.08 | $ | 46.70 | ||||||||||
| Lease operating expenses |
(17.40 | ) | (18.95 | ) | (20.04 | ) | (17.22 | ) | (22.29 | ) | ||||||||||
| Gathering, processing & transportation |
(0.34 | ) | (0.31 | ) | (0.34 | ) | (0.45 | ) | (0.22 | ) | ||||||||||
| Production & property taxes |
(5.11 | ) | (4.34 | ) | (3.78 | ) | (4.50 | ) | (5.26 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Field-level cash margin |
$ | 0.10 | $ | 15.55 | $ | 22.33 | $ | 23.91 | $ | 18.93 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Devon - Total |
||||||||||||||||||||
| Realized price |
$ | 14.37 | $ | 25.43 | $ | 32.82 | $ | 30.47 | $ | 31.79 | ||||||||||
| Lease operating expenses |
(3.69 | ) | (3.96 | ) | (3.79 | ) | (3.90 | ) | (3.85 | ) | ||||||||||
| Gathering, processing & transportation |
(4.16 | ) | (4.11 | ) | (4.16 | ) | (3.71 | ) | (3.78 | ) | ||||||||||
| Production & property taxes |
(1.07 | ) | (1.95 | ) | (2.32 | ) | (2.13 | ) | (2.38 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Field-level cash margin |
$ | 5.45 | $ | 15.41 | $ | 22.55 | $ | 20.73 | $ | 21.78 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
8
NON-GAAP FINANCIAL MEASURES
(all monetary values in millions, except per share amounts)
The earnings materials include 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 the earnings materials, including reconciliations to their most directly comparable GAAP measure. Additional information regarding our non-GAAP measures can also be found in our corresponding periodic report filed with the SEC.
CORE EARNINGS (LOSS)
Devon’s reported net earnings (loss) 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 (loss) and core earnings (loss) 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 second-quarter 2020 earnings.
| Quarter Ended June 30, 2020 | ||||||||||||||||
| Before-tax | After-tax | After Noncontrolling Interests |
Per Diluted Share |
|||||||||||||
| Continuing Operations |
||||||||||||||||
| Loss (GAAP) |
$ | (680 | ) | $ | (677 | ) | $ | (679 | ) | $ | (1.80 | ) | ||||
| Adjustments: |
||||||||||||||||
| Asset and exploration impairments |
4 | 3 | 3 | 0.01 | ||||||||||||
| Deferred tax asset valuation allowance |
— | 149 | 149 | 0.39 | ||||||||||||
| Fair value changes in financial instruments |
593 | 459 | 459 | 1.22 | ||||||||||||
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| Core loss (Non-GAAP) |
$ | (83 | ) | $ | (66 | ) | $ | (68 | ) | $ | (0.18 | ) | ||||
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| Discontinued Operations |
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| Earnings (GAAP) |
$ | 9 | $ | 9 | $ | 9 | $ | 0.02 | ||||||||
| Adjustments: |
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| Asset dispositions |
(2 | ) | (1 | ) | (1 | ) | (0.00 | ) | ||||||||
| Fair value changes in foreign currency and other |
(5 | ) | (6 | ) | (6 | ) | (0.02 | ) | ||||||||
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| Core earnings (Non-GAAP) |
$ | 2 | $ | 2 | $ | 2 | $ | 0.00 | ||||||||
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| Total |
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| Loss (GAAP) |
$ | (671 | ) | $ | (668 | ) | $ | (670 | ) | $ | (1.78 | ) | ||||
| Adjustments: |
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| Continuing Operations |
597 | 611 | 611 | 1.62 | ||||||||||||
| Discontinued Operations |
(7 | ) | (7 | ) | (7 | ) | (0.02 | ) | ||||||||
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| Core loss (Non-GAAP) |
$ | (81 | ) | $ | (64 | ) | $ | (66 | ) | $ | (0.18 | ) | ||||
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9
EBITDAX
Devon believes EBITDAX provides information useful in assessing operating and financial performance across periods. Devon computes EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; depreciation, depletion and amortization; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to normal operations. EBITDAX as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.
| Q2 ’20 | Q1 ’20 | Q4’19 | Q3’19 | TTM | Q2’19 | |||||||||||||||||||
| Net earnings (loss) (GAAP) |
$ | (668 | ) | $ | (1,815 | ) | $ | (640 | ) | $ | 109 | $ | (3,014 | ) | $ | 495 | ||||||||
| Net (earnings) loss from discontinued operations, net of tax |
(9 | ) | 125 | 652 | 27 | 795 | (344 | ) | ||||||||||||||||
| Financing costs, net |
69 | 65 | 64 | 60 | 258 | 66 | ||||||||||||||||||
| Income tax expense (benefit) |
(3 | ) | (417 | ) | (33 | ) | 54 | (399 | ) | 68 | ||||||||||||||
| Exploration expenses |
12 | 112 | 29 | 18 | 171 | 7 | ||||||||||||||||||
| Depreciation, depletion and amortization |
299 | 401 | 382 | 381 | 1,463 | 374 | ||||||||||||||||||
| Asset impairments |
— | 2,666 | — | — | 2,666 | — | ||||||||||||||||||
| Asset dispositions |
— | — | — | (1 | ) | (1 | ) | (2 | ) | |||||||||||||||
| Share-based compensation |
19 | 20 | 19 | 20 | 78 | 21 | ||||||||||||||||||
| Derivative and financial instrument non-cash valuation changes |
593 | (619 | ) | 159 | (57 | ) | 76 | (117 | ) | |||||||||||||||
| Restructuring and transaction costs |
— | — | 11 | 10 | 21 | 12 | ||||||||||||||||||
| Accretion on discounted liabilities and other |
13 | (48 | ) | 14 | 5 | (16 | ) | 8 | ||||||||||||||||
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| EBITDAX (Non-GAAP) |
$ | 325 | $ | 490 | $ | 657 | $ | 626 | $ | 2,098 | $ | 588 | ||||||||||||
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NET DEBT
Devon defines net debt as debt less cash, cash equivalents and cash restricted for discontinued operations. Devon believes that netting these sources of cash against debt provides a clearer picture of the future demands on cash from Devon to repay debt.
| June 30, 2020 |
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| Total debt (GAAP) |
$ | 4,296 | ||
| Less: |
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| Cash and cash equivalents |
(1,474 | ) | ||
| Cash restricted for discontinued operations |
(195 | ) | ||
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| Net debt (Non-GAAP) |
$ | 2,627 | ||
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NET DEBT-TO-EBITDAX
Devon defines net debt-to-EBITDAX as net debt divided by trailing twelve months EBITDAX.
| June 30, 2020 |
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| Net debt (Non-GAAP) |
$ | 2,627 | ||
| EBITDAX (trailing 12 months) (Non-GAAP) |
2,098 | |||
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| Net debt-to-EBITDAX (Non-GAAP) |
1.3 | |||
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10
GUIDANCE
THIRD-QUARTER AND FULL-YEAR 2020
PRODUCTION GUIDANCE
| Quarter 3 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Oil (MBbls/d) |
138 | 143 | 148 | 152 | ||||||||||||
| Natural gas liquids (MBbls/d) |
73 | 78 | 73 | 77 | ||||||||||||
| Gas (MMcf/d) |
540 | 580 | 560 | 610 | ||||||||||||
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| Total oil equivalent (MBoe/d) |
301 | 318 | 314 | 331 | ||||||||||||
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PRICE REALIZATIONS GUIDANCE
| Quarter 3 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Oil - % of WTI |
90 | % | 100 | % | 88 | % | 92 | % | ||||||||
| NGL - realized price |
$ | 10.00 | $ | 13.00 | $ | 10.00 | $ | 12.00 | ||||||||
| Natural gas - % of Henry Hub |
70 | % | 80 | % | 70 | % | 75 | % | ||||||||
CAPITAL EXPENDITURES GUIDANCE
| Quarter 3 | Full Year | |||||||||||||||
| (in millions) | Low | High | Low | High | ||||||||||||
| Total upstream capital |
$ | 175 | $ | 225 | $ | 950 | $ | 1,000 | ||||||||
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OTHER GUIDANCE ITEMS
| Quarter 3 | Full Year | |||||||||||||||
| ($ millions, except Boe and %) | Low | High | Low | High | ||||||||||||
| Marketing & midstream operating profit |
$ | (10 | ) | $ | — | $ | (35 | ) | $ | (25 | ) | |||||
| LOE & GP&T per BOE(1) |
$ | 8.05 | (1) | $ | 8.25 | (1) | $ | 7.95 | (1) | $ | 8.15 | (1) | ||||
| Production & property taxes as % of upstream sales |
7.4 | % | 7.6 | % | 7.4 | % | 7.6 | % | ||||||||
| Exploration expenses |
$ | — | $ | 5 | $ | 10 | $ | 20 | ||||||||
| Depreciation, depletion and amortization |
$ | 265 | $ | 305 | $ | 1,225 | $ | 1,325 | ||||||||
| General & administrative expenses |
$ | 75 | $ | 85 | $ | 315 | $ | 335 | ||||||||
| Restructuring expenses(2) |
$ | 25 | (2) | $ | 50 | (2) | $ | 25 | (2) | $ | 50 | (2) | ||||
| Financing costs, net |
$ | 60 | $ | 70 | $ | 260 | $ | 270 | ||||||||
| Other expenses |
$ | — | $ | 10 | $ | — | $ | 20 | ||||||||
| Current income tax rate from continuing operations |
0 | % | 0 | % | 0 | % | 0 | % | ||||||||
| Deferred income tax rate from continuing operations |
20 | % | 30 | % | 20 | % | 30 | % | ||||||||
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| Total income tax rate from continuing operations |
20 | % | 30 | % | 20 | % | 30 | % | ||||||||
| (1) | In the third quarter 2020 and full-year 2020, Devon expects to incur approximately $20 million and $65 million of minimum volume commitments related to the Anadarko Basin. These commitments are expected to impact GP&T rates by approximately $0.55 per Boe in 2020. These commitments will expire at the end of 2020. |
| (2) | Approximately one-third of the estimated restructuring expenses are non-cash. |
1
| Oil Commodity Hedges | ||||||||||||||||||||
| Price Swaps | Price Collars | |||||||||||||||||||
| Period |
Volume (Bbls/d) | Weighted Average Price ($/Bbl) |
Volume (Bbls/d) |
Weighted Average Floor Price ($/Bbl) |
Weighted Average Ceiling Price ($/Bbl) |
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| Q3 2020 |
87,500 | $ | 37.02 | 47,500 | $ | 50.98 | $ | 60.98 | ||||||||||||
| Q4 2020 |
88,000 | $ | 36.28 | 39,500 | $ | 50.93 | $ | 60.93 | ||||||||||||
| Q1 2021 |
47,500 | $ | 35.74 | 20,000 | $ | 49.20 | $ | 59.20 | ||||||||||||
| Q2 2021 |
46,500 | $ | 35.22 | 21,000 | $ | 42.46 | $ | 52.46 | ||||||||||||
| Q3 2021 |
1,000 | $ | 55.35 | 14,500 | $ | 36.16 | $ | 46.16 | ||||||||||||
| Q4 2021 |
— | — | 9,500 | $ | 29.56 | $ | 39.56 | |||||||||||||
Oil Basis Swaps
| Period |
Index |
Volume (Bbls/d) | Weighted Average Differential to WTI ($/Bbl) |
|||||||
| Q3 2020 |
Argus MEH | 55,000 | $ | 0.37 | ||||||
| Q3 2020 |
Midland Sweet | 32,000 | $ | (1.23 | ) | |||||
| Q3 2020 |
NYMEX Roll | 54,000 | $ | 0.38 | ||||||
| Q4 2020 |
Argus MEH | 50,000 | $ | 0.47 | ||||||
| Q4 2020 |
Midland Sweet | 32,000 | $ | (1.23 | ) | |||||
| Q4 2020 |
NYMEX Roll | 54,000 | $ | 0.38 | ||||||
| Q1-Q4 2021 |
Midland Sweet | 7,000 | $ | 1.27 | ||||||
| Natural Gas Commodity Hedges - Henry Hub |
|
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| Price Swaps | Price Collars | |||||||||||||||||||
| Period |
Volume (MMBtu/d) | Weighted Average Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Floor Price ($/MMBtu) |
Weighted Average Ceiling Price ($/MMBtu) |
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| Q3 2020 |
63,300 | $ | 2.72 | 255,000 | $ | 1.83 | $ | 2.32 | ||||||||||||
| Q4 2020 |
55,000 | $ | 2.66 | 118,000 | $ | 2.29 | $ | 2.79 | ||||||||||||
| Q1 2021 |
25,000 | $ | 2.69 | 143,000 | $ | 2.31 | $ | 2.81 | ||||||||||||
| Q2 2021 |
25,000 | $ | 2.69 | 143,000 | $ | 2.31 | $ | 2.81 | ||||||||||||
| Q3 2021 |
25,000 | $ | 2.69 | 143,000 | $ | 2.31 | $ | 2.81 | ||||||||||||
| Q4 2021 |
— | — | 48,000 | $ | 2.40 | $ | 2.90 | |||||||||||||
Natural Gas Basis Swaps
| Period |
Index |
Volume (MMBtu/d) | Weighted Average Differential to Henry Hub ($/MMBtu) |
|||||||
| Q3 2020 |
Panhandle Eastern Pipe Line | 30,000 | $ | (0.47 | ) | |||||
| Q3 2020 |
El Paso Natural Gas | 65,000 | $ | (0.78 | ) | |||||
| Q3 2020 |
Houston Ship Channel | 30,000 | $ | (0.02 | ) | |||||
| Q4 2020 |
Panhandle Eastern Pipe Line | 30,000 | $ | (0.47 | ) | |||||
| Q4 2020 |
El Paso Natural Gas | 65,000 | $ | (0.78 | ) | |||||
| Q4 2020 |
Houston Ship Channel | 30,000 | $ | (0.02 | ) | |||||
| Q1-Q4 2021 |
El Paso Natural Gas | 35,000 | $ | (0.92 | ) | |||||
NGL Commodity Hedges
| Price Swaps | ||||||||||
| Period |
Product |
Volume (Bbls/d) | Weighted Average Price ($/Bbl) |
|||||||
| Q3 2020 |
Ethane | 15,000 | $ | 5.62 | ||||||
| Q3 2020 |
Natural Gasoline | 1,000 | $ | 44.84 | ||||||
| Q3 2020 |
Normal Butane | 1,500 | $ | 23.56 | ||||||
| Q3 2020 |
Propane | 4,500 | $ | 25.18 | ||||||
| Q4 2020 |
Natural Gasoline | 1,000 | $ | 44.84 | ||||||
| Q4 2020 |
Normal Butane | 1,500 | $ | 23.56 | ||||||
| Q4 2020 |
Propane | 4,500 | $ | 25.18 | ||||||
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. Devon’s NGL derivatives settle against the average of the prompt month OPIS Mont Belvieu, Texas index. Commodity hedge positions are shown as of July 31, 2020.
2
