Continental Resources Reports First Quarter 2017 Results

OKLAHOMA CITY, May 3, 2017 /PRNewswire/ --

Bakken Wells Exceed 980 MBoe EUR Type Curve by an Average 65% in First 30 Days

SCOOP Springer Wells Outperform 940 MBoe EUR Type Curve by an Average 60% in First 30 Days

Sycamore Expansion Adds Approximately 300,000 Net Reservoir Acres Under Existing Leasehold in SCOOP

STACK Meramec Wells Flow 1,907 to 3,011 Boe per Day During Initial 24-Hour Tests

Second Quarter 2017 Production Trending Ahead of Forecast; Now Expected to Range from 220,000 to 225,000 Boe per Day 

Continental Resources, Inc. (NYSE: CLR) (the Company) today announced first quarter operating and financial results. Continental reported net income of $0.47 million, or $0.00 per diluted share, for the quarter ended March 31, 2017.

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The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In first quarter 2017, these typically excluded items in aggregate represented $6.3 million, or $0.02 per diluted share, of Continental's reported net income. Adjusted net income for the first quarter was $6.8 million, or $0.02 per diluted share.

Net cash provided by operating activities for first quarter 2017 was $470.2 million. EBITDAX for first quarter 2017 was $482.5 million. Definitions and reconciliations of adjusted net income, adjusted net income per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables at the conclusion of this press release.

"I am very pleased with the performance of our assets and operations so far this year. Relative to 2017 guidance, we are ahead on production, under on CAPEX and expect to be at the top-end or better than our production guidance for the year," said Harold Hamm, Chairman and Chief Executive Officer. "In the Bakken, we have seen industry-wide basin wellhead netbacks strengthen by approximately $2.00 per barrel with new pipeline capacity and additional markets becoming available. This will begin to positively impact our economics over the next several months."

Mr. Hamm noted that Continental continues to expand the strategic scope of its premier assets with the Sycamore reservoir in Oklahoma's SCOOP play. "On top of all of the other great news, we are pleased to announce the addition of approximately 300,000 net reservoir acres in Sycamore, a new reservoir layer within SCOOP. Our world-class asset portfolio continues to expand."

Production Accelerates in March

First quarter 2017 net production totaled 19.2 million barrels of oil equivalent (Boe), or 213,755 Boe per day, up approximately 4,000 Boe per day from fourth quarter 2016. March production averaged approximately 222,500 Boe per day. The Company now expects second quarter 2017 production will be in a range of 220,000 to 225,000 Boe per day. The Company is currently tracking at the top end or better than its annual production guidance, and if warranted, it will update guidance in August.

Total net production for first quarter 2017 included 119,201 barrels of oil (Bo) per day (56% of production) and 567 million cubic feet (MMcf) of natural gas per day (44% of production). Oil as a percentage of total production is expected to continue increasing to approximately 60% at year-end 2017.

The following table provides the Company's average daily production by region for the periods presented.

Bakken: Outperformance Continues as a Result of Optimized Completions

Continental's Bakken net production averaged 108,992 Boe per day in first quarter 2017. The Company had 50 gross (17 net) operated and non-operated Bakken wells with first production during first quarter 2017.

In the first quarter there were 16 gross operated wells with first production, all of which were completed using the Company's optimized completion techniques, which includes tighter stage spacing, increased proppant per foot, diverter technology, more aggressive flowback, and high-capacity lift technology.

Of these, 14 gross operated wells had 30 days or more of production, and all are outperforming the 980 MBoe (thousand Boe) estimated ultimate recovery (EUR) type curve by an average of 65% at 30 days. Based on an average well cost of $7.0 million and $55 WTI, the 14 wells are expected to average approximately a 75% rate of return, almost double the 40% rate of return originally targeted by the 2017 Bakken drilling program.

Included in this group are four wells with record 30-day production rates:

• 1,853 Boe per day (79% oil) from a 9,400-foot lateral (Akron Federal 7-27H);
• 1,833 Boe per day (79% oil) from a 9,700-foot lateral (Radermecher 2-22H1);
• 1,618 Boe per day (78% oil) from a 9,500-foot lateral (Radermecher 4-22H2); and
• 1,543 Boe per day (79% oil) from a 10,100-foot lateral (Charlotte 7X-22H).

Continental previously announced seven optimized Bakken completions in February 2017, and they continue to outperform the Bakken 980 MBoe EUR type curve by an average of 55% at 150 days, compared with 35% outperformance of the type curve model at 90 days.

"Our optimized completions are another game changer for the Bakken," said Jack Stark, President. "This technology is delivering record 30-day production rates and almost doubling the rates of return expected from our previous economic models."

Drilling performance continues to advance year-over-year with first quarter 2017 spud-to-total depth cycle times averaging 12 days, a 16% reduction over full-year 2016. 

Continental has four operated drilling rigs working in the Bakken and plans to maintain that level through year end. The Company also has seven stimulation crews working in the play and plans to be at nine by mid-year.

SCOOP: Springer Delivers Impressive Results

In first quarter 2017, SCOOP net production averaged 62,178 Boe per day (27% oil), or 29% of the Company's total production in first quarter. Continental had 14 gross (5 net) operated and non-operated wells with first production in first quarter 2017. Continental currently has five operated drilling rigs working in SCOOP.

During the quarter, Continental announced three SCOOP Springer wells. All three wells are outperforming the Company's historical 940 MBoe Springer type curve for a 4,500-foot lateral in their first 30-to-60 days on production. The Cash 1-26H well is outperforming the type curve by 75% at 30 days, the Strassle 1-28-33XH is outperforming the type curve by 35% at 60 days, and the Trammel 1-11-14-23XH is outperforming the type curve by 100% at 60 days.

The wells are located in Grady County, Oklahoma and are the first Springer wells completed by the Company since third quarter 2015. The wells were completed using the Company's latest stimulation designs, including increased proppant per foot and tighter stage spacing. 

Initial 24-hour production test rates for these wells are as follows:   

• 1,691 Boe per day (84% oil) from a 4,775-foot lateral (Cash 1-26H);
• 2,300 Boe per day (79% oil) from an 8,300-foot lateral (Trammell 1-11-14-23XH); and
• 1,257 Boe per day (89% oil) from a 5,800-foot lateral (Strassle 1-28-33XH).

Springer drilling times were also reduced through improved drilling and directional control technology. The Cash 1-26H, which was a 4,775-foot lateral, was drilled in 34 days from spud to total depth, down 45% from comparable wells drilled in third quarter 2015. Including costs for the larger stimulation, total completed well cost for the Cash 1-26H was $7.6 million, down $2.7 million, or approximately 25%, compared to the third quarter 2015 Springer wells.  

The Company has elected to increase activity in the Springer during 2017 and now plans to complete up to 10 Springer wells during the year.

The Company has approximately 197,000 net acres in the SCOOP Springer, which is located approximately 1,000 feet above the Woodford formation.

Sycamore Further Expands SCOOP Asset Value

Continental announced its first two well completions targeting the Sycamore formation in Grady County, adding yet another highly productive layer in SCOOP to its portfolio. The Company has approximately 300,000 net reservoir acres in the Sycamore, which lies directly above the Woodford formation.  

Initial 24-hour production test rates for the Company's new wells included:

• 7.8 MMcf and 225 Bo per day with a flowing casing pressure of 3,200 psi from a 5,800-foot lateral (Ryan Express 1-18-19XH); and
• 12.2 MMcf and 109 Bo per day with a flowing casing pressure of 3,900 psi from a 7,900-foot lateral (Pudge 1-7-6XH).

The wells have been on production approximately 170 and 180 days, respectively.

Continental is projecting that its SCOOP Sycamore wells will have an average EUR between 1.6 and 2.0 MMBoe, based on a 7,500-foot lateral.

"We are excited about Continental's Sycamore position and the added value it will bring to the Company," said Mr. Stark. "We plan to drill five to seven additional wells during the year focused on delineating the high-liquids windows of the play."

STACK: Continued Successful Well Results

STACK production increased 20% to 29,216 Boe per day in first quarter 2017, compared to fourth quarter 2016. Continental had 27 gross (8 net) operated and non-operated wells with first production in STACK in first quarter 2017.

The Company reported three operated standalone wells in the STACK Meramec over-pressured oil window and one operated well in the over-pressured condensate window.

Initial 24-hour production test rates and flowing casing pressures in pounds per square inch (psi) for these wells included:

• 2,865 Boe per day (74% oil) flowing at 2,850 psi from a 4,575-foot lateral (Swaim 1-14H);
• 2,104 Boe per day (51% oil) flowing at 2,910 psi from a 4,800-foot lateral (Mowery 1-36H);
• 1,907 Boe per day (59% oil) flowing at 3,925 psi from a 10,500-foot lateral (Herod FIU 1-8-5XH); and
• 3,011 Boe per day (10% oil) flowing at 4,400 psi from a 10,100-foot lateral (Nuzum 1-12-1XH).

The Company has 11 operated rigs in the play, with six rigs targeting the Meramec formation in the over-pressured oil and condensate windows and five targeting the Woodford formation in the Northwest Cana joint development agreement area in Blaine and Custer counties.

Financial Update

"Improving production results, strong cash management and additional operating efficiencies combined to deliver an excellent first quarter," said John Hart, Chief Financial Officer. "This enabled us to come in $33 million below budget on non-acquisition capital expenditures and to reduce debt by $70 million for the quarter."

Continental continues to see accelerating production growth throughout the year and thereafter, he said. "We expect to achieve annual production growth of 20% from 2018 through 2020 while reducing debt below $6 billion. These plans are cash neutral each year at oil prices between $50 and $55 per barrel, reflecting strong well productivity and cost efficiency."

In first quarter 2017, Continental's average realized sales price excluding the effects of derivative positions was $44.69 per barrel of oil and $3.00 per Mcf of gas, or $32.90 per Boe. Based on realizations without the effect of derivatives, the Company's first quarter 2017 oil differential was $7.09 per barrel below the NYMEX daily average for the period. The realized wellhead natural gas price for the quarter was on average $0.29 per Mcf below the average NYMEX Henry Hub benchmark price.      

Production expense per Boe was $3.78 for first quarter 2017. Other select operating costs and expenses for first quarter 2017 included production taxes of 6.5% of oil and natural gas sales; DD&A of $19.84 per Boe; and total G&A of $2.45 per Boe.

Non-acquisition capital expenditures for first quarter 2017 totaled approximately $427.0 million, which was 7% lower than budgeted. Non-acquisition capital expenditures for the quarter included $329.8 million in exploration and development drilling, $69.8 million in leasehold and seismic, and $27.4 million in workovers, recompletions and other. 

As of March 31, 2017, Continental's balance sheet included approximately $17.2 million in cash and cash equivalents and $6.5 billion in long-term debt.

The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.

First Quarter Earnings Conference Call

Continental plans to host a conference call to discuss first quarter results on Thursday, May 4, 2017, at 12 p.m. ET (11 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 first quarter 2017 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on May 4, 2017. 

Upcoming Conferences

Members of Continental's management team plan to participate in the following investment conferences:

About Continental Resources

Continental Resources (NYSE: CLR) is a top 15 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 significant 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 December 31, 2016, 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.

Non-GAAP Financial Measures

EBITDAX

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income (loss) or net cash provided by operating activities as determined by U.S. GAAP.

Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.  

The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.

Adjusted earnings and adjusted earnings per share

Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.

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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