Continental Resources Projects 2017 Guidance And Capital Budget Of $1.95 Billion - Cash Neutral At $55 Per Barrel WTI

OKLAHOMA CITY, Jan. 25, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced a 2017 capital expenditures budget of $1.95 billion, which is expected to accelerate production growth in second half 2017 to an exit rate of 250,000 to 260,000 barrels of oil equivalent (Boe) per day. Crude oil is projected to account for approximately 59% of total production by year end, compared with approximately 55% in the fourth quarter 2016. 

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Fourth quarter 2016 production averaged approximately 210,000 Boe per day, reflecting persistent severe weather in North Dakota since late November 2016. The Company expects production to range between 210,000 and 215,000 Boe per day through first half 2017, after which production is expected to significantly accelerate due to the timing of pad completions in the Bakken and six new multi-well density projects in the over-pressured oil window of Oklahoma's STACK play.

Full-year 2017 production is expected to average approximately 220,000 to 230,000 Boe per day, compared with approximately 217,000 Boe per day for 2016.

Of the total $1.95 billion budget, the Company is allocating $1.72 billion to drilling and completion activities, with the remainder planned to be invested in other opportunities including leasehold and facilities.

More than 80% of the drilling and completion budget is focused on completing the Company's deep inventory of uncompleted wells in North Dakota, additional drilling in the Bakken, and further STACK development, which will drive the 2017 increase in crude oil volumes as a percent of total production. Crude oil production is expected to grow to approximately 150,000 barrels of oil (Bo) per day by year-end 2017, a 29% increase compared with approximately 116,500 Bo per day for fourth quarter 2016. Natural gas production is expected to increase to approximately 630 million cubic feet (MMcf) per day at year-end 2017, an approximate 12% increase over fourth quarter 2016.

The capital budget is projected to be cash neutral for full-year 2017 at an average $55 per barrel NYMEX WTI and $3.14 per thousand cubic feet (Mcf) of natural gas Henry Hub. Continental noted that, at a full-year average $60 per barrel WTI price, the Company would expect to generate approximately $200 million in additional cash.

Budgeted completed well costs reflect further enhancements in completion designs and potential increases in service costs, partially offset by drilling efficiencies and lower drilling day rates as long-term rig contracts expire.

Continental intends to adjust the level of spend if necessary to remain cash neutral for the year. It also continues to target reducing long-term debt to $6 billion or lower using proceeds from the potential sale of non-strategic assets.

2017 Operating Plan

Continental plans to operate an average 20 drilling rigs in 2017, an increase of one rig from 2016. The Company expects to complete a total of 280 gross (178 net) operated wells with first production in 2017. The Company also plans to participate in completing 40 net non-operated wells in 2017, 35 of which will be in the Bakken.

The Company plans to complete 131 gross (100 net) operated wells out of its Bakken uncompleted well inventory with first production commencing by year end. In addition, Continental plans to complete with first production approximately 17 gross (8 net) newly drilled Bakken wells in 2017. At year-end 2017, the Company expects to have 140 Bakken wells in inventory, of which 72 gross (40 net) wells will have been completed but waiting on first sales and 68 gross (47 net) operated wells will be waiting on completion.

In Oklahoma, the Company expects to complete 132 gross (70 net) operated wells with first production in 2017, including 98 gross (50 net) operated wells in STACK and 34 gross (20 net) operated wells in SCOOP.

Outlook for 2018 and Beyond

The Company projects its current inventory will support an average annual production growth rate of more than 20% in 2018 to 2020 at $60 to $65 per barrel NYMEX WTI oil prices and remain cash neutral. At these prices the Company expects to deliver a 2018 exit rate of 290,000 to 310,000 Boe per day, which is an increase of approximately 18% over the projected 2017 exit rate (midpoint to midpoint). Continental expects crude oil production will continue increasing at an accelerated rate, accounting for 60% to 65% of total production in years after 2017.

"We are capitalizing on the exceptional performance delivered by our operating teams the last two years," said Harold Hamm, Chairman and Chief Executive Officer. "Our disciplined 2017 budget and growth plan will position the Company for multiple years of double-digit production growth. I've never been more excited by Continental's opportunities to realize the value of our premier assets and to deliver exceptional shareholder value."

Bakken Well Completions Drive Production Increase

Continental expects to grow Bakken production by approximately 26% in 2017, when comparing the 2017 exit rate to the fourth quarter 2016.

Approximately $550 million, or 70%, of the operated Bakken capital investment in 2017 will be focused on completing wells from the Company's uncompleted well inventory. The Company has five stimulation crews working currently and plans to average seven crews for 2017 as a whole.

Continental plans to apply various enhanced stimulation techniques on all Bakken completions in 2017 to define the optimum designs for future completions. This includes larger proppant loads, diverter technology, shorter stage lengths and shorter cluster spacing. The Company is also applying high-rate production lift technology to accelerate fluid recovery and early production rates. Combined, these techniques add an average of approximately $1.4 million to the previous standard enhanced completion cost of $3.5 million.

For the uncompleted well inventory, the average budgeted completion cost for the larger enhanced completion is approximately $4.9 million per well. The incremental investment is budgeted to deliver an average estimated ultimate recovery (EUR) of 980,000 Boe per well, or approximately 15% over the previous average EUR of 850,000 Boe per well. At $55 per barrel WTI, these completions should generate a cost forward average rate of return in excess of 100%.

The Company also plans to maintain four operated drilling rigs in the Bakken throughout 2017 and drill 101 gross (57 net) operated wells, with 17 gross (8 net) of these wells completed in 2017 with first production. The 17 gross wells will have an average budgeted well cost of approximately $7.0 million. The average EUR for wells drilled in 2017 is expected to be 920,000 Boe per well. At a WTI price of $55 per barrel, these wells should generate over a 40% rate of return.

Oklahoma Outlook: New STACK Density Projects

In Oklahoma, strong liquids-weighted production growth in 2017 will be driven by the completion of six density projects in the over-pressured oil window of STACK, where the Company announced several record-production wells in the past year. STACK year-over-year production growth is expected to be approximately 130% in 2017.

Continental plans to operate an average of 16 drilling rigs this year, of which 11 rigs will be in STACK targeting the Meramec and Woodford formations and five rigs will be drilling in the SCOOP play. The Company plans to average four completion crews in Oklahoma. In 2017, the Company will have an expected average working interest in STACK of approximately 57%, versus an average 42% working interest in 2016.

In the STACK over-pressured oil window, the Company's average budgeted completed well cost is approximately $9.0 million. Wells in the SCOOP Woodford condensate window have an average budgeted completed well cost of $10.3 million. STACK Woodford wells completed as part of the joint development agreement with SK E&S of South Korea have an average budgeted completed well cost of $13.0 million. As noted in Continental's newly posted investor presentation on its website (www.clr.com), new wells in its Oklahoma plays typically generate rates of return ranging from 55% to more than 100% at $55 per barrel WTI and $3.50 per Mcf of natural gas.

2017 Guidance Table

Fourth Quarter and Full-Year 2016 Earnings Conference Call

Continental plans to host a conference call to discuss fourth quarter and full-year 2016 results on Thursday, February 23, 2017 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:

A replay of the call will be available for 14 days on the Company's website or by dialing:

Continental plans to publish a fourth quarter and full-year 2016 summary presentation to its website at www.CLR.com prior to the start of its conference call on February 23, 2017.

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 one of the largest producers 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 2017, the Company will celebrate 50 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, 2015, 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.

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.

SOURCE Continental Resources

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