OKLAHOMA CITY, Feb. 15, 2018 /PRNewswire/ --
2017 Preliminary Results:
- Production of 286,985 barrels of oil equivalent (Boe) per day in fourth quarter 2017, up 37% year-over-year from fourth quarter 2016
- Oil represented 59% of production in fourth quarter 2017, compared to 55% in fourth quarter 2016
- Production of 242,637 Boe per day for full-year 2017, up 12% from full-year 2016
- Lowered debt by $261 million in fourth quarter 2017 and by an additional $95 million in January 2018
2018 Projected Capital Budget and Guidance:
- $2.3 billion capital expenditures
- Estimate $3.0 to $3.2 billion of cash flow from operations and $800 to $900 million of free cash flow (non-GAAP) at $60 per barrel WTI and $3.00 per Mcf Henry Hub
- Budget expected to be cash neutral in the low-to-mid-$40's WTI
- 17% to 24% year-over-year production growth to 285,000 to 300,000 Boe per day
- 10% to 15% projected return on capital employed (ROCE)
Continued Improvement in 2018 Differentials and Operating Expenses Expected:
- ($3.50) to ($4.50) per Bo oil differential
- $0.00 to +$0.50 per Mcf natural gas premium
- $3.00 to $3.50 per Boe production expense
- $1.70 to $2.30 per Boe total G&A
Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced a 2018 capital expenditures budget of $2.3 billion, which is focused on both strong free cash flow generation and strong annual production growth to approximately 285,000 to 300,000 Boe per day, with a 2018 exit rate of 305,000 to 315,000 Boe per day. Crude oil is projected to range between 57% and 60% of production throughout 2018, varying through the year due to the timing of large pad projects coming online.
The 2018 capital budget is projected to generate $3.0 to $3.2 billion of cash flow from operations and $800 to $900 million of free cash flow for full-year 2018 at $60 WTI and $3.00 Henry Hub. There are currently no oil hedges in place, allowing the Company to fully participate in the upside of oil prices. Natural gas is hedged in excess of 80% of production for the remainder of the year at an average price of $2.88. Continental also noted that the capital budget is expected to be cash neutral at a WTI price in the low-to-mid-$40's. A $5 change in WTI is estimated to impact annual cash flow by $250 to $300 million, and a $0.10 change in Henry Hub is estimated to impact annual cash flow by $5 to $10 million. Free cash flow and cash G&A used herein are non-GAAP measures. See "Non-GAAP Measures" and the guidance table at the end of this press release for definitions and reconciliations of these measures to the most comparable U.S. GAAP financial measures.
Of the total $2.3 billion budget, the Company is allocating approximately $2.0 billion to drilling and completion (D&C) activities, with approximately 78% of the D&C budget focusing on the oil-weighted Bakken and SCOOP Springer assets. Approximately $500 million of the 2018 D&C capital reflects activities that will generate first production in 2019. The non-D&C capital is planned to be primarily focused on leasehold, workovers and facilities.
The Company experienced improved differentials and lower production expenses on a per Boe basis in fourth quarter 2017. These trends are projected to continue in 2018. Oil differentials are expected to be in a range of ($3.50) to ($4.50) per Bo, and natural gas differentials are expected to be $0.00 to a positive $0.50 per Mcf. Production expense is expected to be between $3.00 and $3.50 per Boe, and total G&A is expected to be between $1.70 and $2.30 per Boe.
"This year Continental expects to set itself apart by generating up to $900 million of free cash flow while delivering top-tier production growth," said Harold Hamm, Chairman and Chief Executive Officer. "We plan to use the majority of this excess cash to continue paying down debt, further strengthening our balance sheet and increasing shareholder value. We are focused on returns and expect, at a WTI price of $60, that our ROCE will be 10% to 15%, which is expected to be among the industry's best."
Year-End 2017 Update
Fourth quarter 2017 production averaged 286,985 Boe per day, with 59% of the production being oil. Oil production grew 20% compared to third quarter 2017. Full-year 2017 production averaged 242,637 Boe per day, up 12% over full-year 2016. Year-end long-term debt was approximately $6.35 billion, down $261 million from September 30, 2017, reflecting the application of cash flow and divestiture proceeds. As of January 31, 2018, Continental's long-term debt was down another $95 million to $6.26 billion.
As a reminder, the entire fourth quarter and full-year 2017 results will be announced on Wednesday, February 21, 2018 following the close of trading on the New York Stock Exchange with a conference call on Thursday, February 22, 2018 at 12:00 p.m. ET (11:00 a.m. CT). Details can be found at www.CLR.com.
2018 Operating Plan
In the Bakken, the Company plans to average six operated drilling rigs throughout 2018 and drill approximately 142 gross operated wells. The Company has six stimulation crews working currently and plans to average 6.5 crews in 2018, while completing 187 gross (113 net) operated wells.
During the year the Company plans to work down its inventory of drilled but not producing wells, and at year-end 2018, the Company expects to have 120 gross operated Bakken wells in progress in various stages of completion, of which 44 gross wells will have been completed but waiting on first sales. This compares to 165 gross operated wells in progress at year-end 2017. With six drilling rigs and an average pad size of six to seven wells, the projected 2018 year-end level of 120 gross operated wells in progress is considered a normal working backlog.
In Oklahoma, Continental plans to operate an average of 15 drilling rigs during 2018, of which eight rigs will be in STACK targeting the Meramec and Woodford formations, and seven rigs will be in the SCOOP play primarily targeting the Springer and Woodford formations. Five of the SCOOP rigs will be focused on the Springer as the Company begins full-field development of this oil reservoir. The Company expects to complete 118 gross (69 net) operated wells in Oklahoma with first production in 2018, including 72 gross (33 net) operated wells in STACK and other, 31 (26 net) operated wells in SCOOP Springer and 15 gross (10 net) operated wells in SCOOP Woodford/Sycamore. The Company plans to average four to five completion crews in Oklahoma during 2018.
Early Outlook for 2019
For 2019, the Company currently expects production to grow 15% to 20% year over year with a capital budget of $2.5 to $2.8 billion, while generating significant free cash flow comparable to 2018 projections.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2016, and once filed, for the year ending December 31, 2017, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures excluding acquisitions and divestitures. Free cash flow is not a measure of net income (loss) or cash flows as determined by U.S. GAAP. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. This press release includes forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
J. Warren Henry
Vice President, Investor Relations & Research
Senior Vice President, Public Relations
Alyson L. Gilbert
Manager, Investor Relations
2018 Guidance Table
Continental Resources, Inc.
As of February 15, 2018
Full-year average production
285,000 to 300,000 Boe per day
Exit-rate average production
305,000 to 315,000 Boe per day
Capital expenditures (non-acquisition)
Production expense per Boe
$3.00 to $3.50
Production tax (% of oil & gas revenue)
7.6% to 8.0%
Cash G&A expense per Boe(1)
$1.25 to $1.75
Non-cash equity compensation per Boe
$0.45 to $0.55
DD&A per Boe
$17.00 to $19.00
Average Price Differentials:
NYMEX WTI crude oil (per barrel of oil)
($3.50) to ($4.50)
Henry Hub natural gas (per Mcf)
$0.00 to +$0.50
Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.30 per Boe.
Continental Resources, Inc.
2018 Non-Acquisition Capital Expenditures
The following table provides the breakout of non-acquisition capital expenditures:
($ in millions)
Continental Resources, Inc.
2018 Operational Detail
The following table provides additional operational detail for the 2018 budget:
2018 wells with first production
SCOOP Woodford / Sycamore
STACK & Other
1) Represents projected net operated and non-operated wells
SOURCE Continental Resources