FORT WORTH, Texas, Feb. 27, 2018 (GLOBE NEWSWIRE) -- RANGE RESOURCES CORPORATION (NYSE:RRC) today announced its fourth quarter and year-end 2017 financial results.
Highlights –
- GAAP earnings for 2017 reached $333 million ($1.34 per diluted share) versus a loss of $521 million ($2.75 per diluted share) in 2016
- Net cash provided from operating activities in 2017 increased to $816 million in 2017 compared to $387 million in 2016, an increase of 111%
- GAAP revenues increased to $2.6 billion in 2017 compared to $1.1 billion in 2016, an increase of 137%
- Production increased to 2.0 Bcfe per day in 2017 compared to 1.5 Bcfe per day in 2016, an increase of 30%
- Southwest Marcellus production in fourth quarter 2017 increased to 1,657 net Mmcfe per day, a 34% increase over the prior year
Commenting, Jeff Ventura, the Company’s CEO said, “Financial results were much improved in 2017 with increases in earnings, cash flow, revenues and production compared to 2016. Operationally, the Marcellus continues to drive growth and profitability, with increasing capital efficiency. Outstanding Marcellus drilling results during the year expanded the core Marcellus drilling inventory in all directions. Our marketing strategy, which will be fully implemented in 2018 after years of planning, is expected to improve margins going forward as Range will be positioned to access growing demand for natural gas and NGLs, particularly in the expanding export markets. We are slowing activity in North Louisiana following disappointing results in 2017, which will allow time for additional technical analysis that we expect will improve results in 2018.
As shown in our five-year outlook, we expect to grow production by approximately 11% annually, while generating greater than $1 billion in cumulative free cash flow. With Range’s long-life inventory of over 4,000 high-quality drilling locations, extensive transportation network and ability to add reserves at some of the lowest costs in the industry, we believe Range is well positioned to generate shareholder value for many years, while also significantly strengthening the balance sheet.”
Range previously announced 2017 proved reserves results and a five-year outlook on January 24, 2018. Highlights from these announcements were:
2017 Proved Reserves Results
- Proved reserves increased by 26% to 15.3 Tcfe
- SEC PV10 reserve value increased by 119% to $8.1 billion
- Record low drill-bit finding costs were $0.31 per mcfe
Five-Year Outlook
- ~$1 billion in cumulative free cash flow from 2018 through 2022
- Leverage below 2x net debt to EBITDAX in 2022, without asset sales
- 13% production CAGR on a debt-adjusted per share basis
- 3,200 core Marcellus locations remaining after the 5 year period ending in 2022
2018 Capital Spending Plans
Range’s 2018 capital budget is $941 million. At year-end strip pricing, this is expected to be less than cash flow, with the excess cash flow expected to be used to reduce debt. In addition, any proceeds received from asset sales are also expected to be applied to reduce debt.
Approximately 85% of the capital budget is expected to be allocated to the Appalachia division and 15% to the North Louisiana division. The budget includes projected service cost increases in 2018. In Appalachia, approximately 60% of activity will be directed towards liquids-rich drilling, where successful drilling in 2017 led to improved type curves in the Company’s super-rich area. In addition, Range’s liquids-rich acreage has an extensive inventory of existing pads that reduce capital costs and gathering expense. The acreage is also in close proximity to capacity for both existing and expected NGL and natural gas takeaway projects, improving netback pricing. The Company expects production of approximately 2.23 Bcfe per day in 2018, which equates to 11% growth compared to 2017.
The 2018 capital budget includes approximately $857.4 million for drilling and recompletions (91% of the total), $54 million for leasehold, $4.3 million for seismic, and $25.5 million for pipelines, facilities and other capital expenditures. The budget includes 100 wells expected to be brought on line during the year in the Marcellus and 11 wells in North Louisiana. In the Marcellus, approximately half of the wells are planned to be drilled from existing pads in 2018.
Fourth quarter 2017 drilling expenditures of $369 million funded the drilling of 53 (48 net) wells. Drilling expenditures for the year totaled $1.18 billion, and Range drilled 177 (164 net) wells during the year. A 99% success rate was achieved. In addition, during 2017, $62 million was spent on acreage purchases, $15 million on gas gathering systems and $51 million on exploration expense.
Financial Discussion
Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market adjustment on derivatives, non-cash stock compensation and other items shown separately on the attached tables. “Unit costs” as used in this release are composed of direct operating, transportation, gathering, processing and compression, production and ad valorem taxes, general and administrative, interest and depletion, depreciation and amortization costs divided by production. See “Non-GAAP Financial Measures” for a definition of each of the non-GAAP financial measures and the tables that reconcile each of the non-GAAP measures to their most directly comparable GAAP financial measure.
Full Year 2017
GAAP revenues for 2017 totaled $2.6 billion (137% increase compared to 2016), GAAP net cash provided from operating activities including changes in working capital was $816 million, compared to $387 million in 2016, and GAAP earnings were $333 million ($1.34 per diluted share) versus a loss of $521 million ($2.75 per diluted share) in 2016. Full year 2017 results include a $270 million impairment of unproved properties, reflecting expected North Louisiana lease expirations compared to $30 million in 2016, a gain of $24 million from asset sales compared to a loss of $7 million in 2016, $213 million in derivative gains due to decreases in future commodity prices compared to a $261 million loss in the prior year and a $51 million mark to market gain related to the deferred compensation plan compared to a $19 million loss in the prior year. The reduction in the corporate tax rate from 35% to 21% under the Tax Cuts and Jobs Act of 2017 required a one-time revaluation of certain tax related assets and liabilities to reflect their value at the lower corporate tax rate. A one-time tax benefit was recorded related to the tax law changes in the amount of $334 million.
Non-GAAP revenues for 2017 totaled $2.4 billion, an increase of 41% compared to 2016 and cash flow from operations before changes in working capital, a non-GAAP measure, was $916 million, compared to $569 million in 2016. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $143 million ($0.58 per diluted share), compared to $4.9 million ($0.03 per diluted share) in 2016.
Range announced its full year 2017 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates), which averaged $2.99 per mcfe, a 9% increase from the prior year. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.
- Production and realized prices by each commodity for 2017 were: natural gas – 1,343 Mmcf per day ($2.90 per mcf), NGLs – 97,834 barrels per day ($14.88 per barrel) and crude oil and condensate – 13,115 barrels per day ($49.49 per barrel).
- The 2017 average Company natural gas price including the impact of basis hedging was $2.79 per mcf, or ($0.31) per mcf below NYMEX which compares favorably to a ($0.45) differential in the prior year. In addition, NYMEX natural gas financial hedges increased realizations $0.11 per mcf for 2017.
- Pre-hedge NGL realizations improved to 33% of West Texas Intermediate (“WTI”) in 2017, compared to 26% of WTI in 2016. Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was $14.88 per barrel compared to $13.15 in the prior year. Hedging decreased NGL prices by $2.04 per barrel in 2017 compared to an increase of $1.71 per barrel in the prior year.
- Crude oil and condensate price realizations, before hedges, for the year averaged $46.30 per barrel, or $4.77 below WTI, compared to $9.09 below WTI in the prior year. Hedging added $3.19 per barrel in 2017, compared to hedge gains of $13.22 per barrel in the prior year.
Range’s total unit costs plus DD&A for 2017 continued to improve, decreasing by $0.07 per mcfe, or 3%, compared to the prior year, as shown below.
| Expenses | Full Year 2017 (per mcfe) | Full Year 2016 (per mcfe) | Increase (Decrease) | |||||||
| Direct operating | $ | 0.18 | $ | 0.17 | 6 | % | ||||
| Transportation, gathering, processing and compression | 1.04 | 1.00 | 4 | % | ||||||
| Production and ad valorem taxes | 0.06 | 0.05 | 20 | % | ||||||
| General and administrative | 0.21 | 0.23 | (9 | %) | ||||||
| Interest expense | 0.27 | 0.30 | (10 | %) | ||||||
| Total cash unit costs | 1.76 | 1.75 | 1 | % | ||||||
| Depletion, depreciation and amortization (DD&A) | 0.85 | 0.93 | (9 | %) | ||||||
| Total unit costs plus DD&A | $ | 2.61 | $ | 2.68 | (3 | %) | ||||
Fourth Quarter 2017
Fourth quarter 2017 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts’ estimates) averaged $3.01 per mcfe, a 6% decrease from the prior-year quarter. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company’s website.
- Production and realized prices by each commodity for fourth quarter 2017 were: natural gas – 1,444 Mmcf per day ($2.84 per mcf), NGLs – 106,038 barrels per day ($15.63 per barrel) and crude oil and condensate – 15,007 barrels per day ($50.95 per barrel).
- The average Company natural gas price including the impact of basis hedging was $2.59 per mcf, or ($0.35) per mcf below NYMEX which compares to a ($0.37) differential in the prior year quarter. In addition, NYMEX natural gas financial hedges increased realizations $0.25 per mcf in fourth quarter 2017.
- Pre-hedge NGL realizations improved to 36% of WTI in fourth quarter 2017, compared to 29% of WTI in the previous year. Total NGL pricing per barrel, including ethane and processing expenses after realized cash-settled hedging decreased to $15.63 for the fourth quarter compared to $17.20 per barrel in the prior year. Hedging decreased NGL prices by $4.06 per barrel in the fourth quarter compared to an increase of $2.70 per barrel in the prior year.
- Crude oil and condensate price realizations, before realized hedges, for the fourth quarter averaged $50.67 per barrel, or $4.63 below WTI, compared to $4.66 below WTI in the prior year. Hedging added $0.27 per barrel compared to hedge gains of $16.69 in the prior year.
Range’s total unit costs plus DD&A in fourth quarter 2017 were 2% lower than the previous year quarter. Operating expenses increased due to workover expenses in north Louisiana. Increased transportation expenses were partially offset by higher realized prices, as products were moved to more favorable markets.
| Expenses | 4Q 2017 (per mcfe) | 4Q 2016 (per mcfe) | Increase (Decrease) | ||||||||
| Direct operating | $ | 0.19 | $ | 0.17 | 12 | % | |||||
| Transportation, gathering, processing and compression | 1.00 | 0.96 | 4 | % | |||||||
| Production and ad valorem taxes | 0.06 | 0.04 | 50 | % | |||||||
| General and administrative | 0.21 | 0.26 | (19 | %) | |||||||
| Interest expense | 0.26 | 0.27 | (4 | %) | |||||||
| Total cash unit costs | 1.72 | 1.70 | 1 | % | |||||||
| Depletion, depreciation and amortization (DD&A) | 0.82 | 0.88 | (7 | %) | |||||||
| Total unit costs plus DD&A | $ | 2.54 | $ | 2.58 | (2 | %) | |||||
Operational Discussion
Range previously updated its investor presentation with economic calculations and type curves for the Marcellus and North Louisiana. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – February 27, 2018”
The table below summarizes 2017 activity and estimates for 2018 regarding the number of wells to sales and average lateral lengths for each area. Updated well costs and EUR’s by area can be found in the updated company presentation. Consistent with the prior year, updated type curves reflect expected flow restrictions that result from infrastructure and facility design constraints. As a result, early production from prolific wells is often constrained, resulting in flatter decline curves, and is reflected in the type curves. As seen in the presentation slides, Marcellus wells turned in line (“TIL”) over the past four years in the southwest Pennsylvania wet and dry areas continue to perform in line with type curve expectations. In the super-rich area, the 2018 type curve was increased by approximately 8%, reflecting improved production performance. These results demonstrate the quality of acreage as the Company continues development across its core position in southwest Pennsylvania.
| Wells TIL in 2017 | Average 2017 Lateral Length | Planned Wells TIL in 2018 | Expected Average 2018 Lateral Length | |||||
| SW PA Super-Rich | 26 | 8,713 ft. | 15 | 11,550 ft. | ||||
| SW PA Wet | 42 | 8,961 ft. | 42 | 9,550 ft. | ||||
| SW PA Dry | 41 | 9,513 ft. | 43 | 9,830 ft. | ||||
| Total Appalachia | 109 | 100 | ||||||
| Total N. LA. | 58 | 6,881 ft. | 11 | 7,500 ft. | ||||
| Total | 167 | 111 |
Appalachia Division
Production for the fourth quarter of 2017 averaged approximately 1,799 net Mmcfe per day from the Appalachia division, a 27% increase over the prior year. Included in this amount was over 100,000 barrels per day of liquids production, making Range one of the largest NGL producers in the U.S. among independent E&P companies. The southwest area of the division averaged 1,657 net Mmcfe per day during the quarter, a 34% increase over the prior year. This growth timed nicely with the Company’s pipeline capacity additions. This was achieved through continued operational improvements and exceptional well results across Range’s acreage position. The northeast area of the division averaged 126 net Mmcf per day during the fourth quarter.
The division brought on line 42 wells in the fourth quarter, one in the super-rich area, 17 in the wet area and 24 in the dry area. The division expects to run five rigs in 2018.
Some noteworthy results from the fourth quarter include:
- A five-well pad in the dry area that produced at a 24-hour IP rate of 36.1 Mmcfe per day per well completed with average lateral lengths of 14,400 feet and 73 stages per well
- A five-well pad in the wet area that produced at a 24-hour IP rate of 36.7 Mmcfe per day (including 2,814 NGL bbls per day) per well was completed with average lateral lengths of 13,600 feet and 68 stages per well
- A four-well pad in the super rich area (3 wells in 3Q17 and 1 well in 4Q17) that produced at a 24-hour IP rate of 40.3 Mmcfe per day (2,880 bbls NGLs and 1,707 bbls condensate per day) per well completed with average lateral lengths of 9,800 feet and 49 stages per well
North Louisiana
Production for the division in the fourth quarter of 2017 averaged approximately 348 net Mmcfe per day.
The division expects to turn in line 11 wells in 2018. The division will run one rig in 2018 as the team monitors results from 2017, while incorporating additional seismic data processed at the end of 2017. Production in North Louisiana is expected to decline through 2018, then remain relatively flat through the remainder of the previously announced five-year outlook.
Marketing and Transportation
In late 2017 and early 2018, two additional natural gas pipeline projects came on line for which Range has contracted for capacity, moving Marcellus gas from southwest Pennsylvania to favorable Gulf Coast markets. Enbridge’s TETCO Adair Southwest project commenced service during the fourth quarter and TransCanada’s Leach and Rayne Xpress project commenced full service in January. As a result of slight project delays, Range’s fourth quarter transportation expense was better than expected. This was somewhat offset by higher natural gas differentials as more natural gas was sold locally. Energy Transfer’s Rover project (phase 2) is expected to reach full completion in second quarter 2018, and is the last major natural gas transportation project for which Range has contracted for capacity. Once all of the projects are fully in service, approximately 90% of Range’s 2018 gas price exposure is expected to be in favorable markets. Importantly, these additions to Range’s transportation portfolio reduce basis volatility, especially during seasonally weak months, and should increase the predictability of Range’s corporate natural gas differential going forward.
Financial Position and Liquidity
At December 31, 2017, Range had total debt outstanding of $4.1 billion, before debt issuance costs, consisting of $2.9 billion in senior notes, $1.2 billion in bank debt and $49 million in senior subordinated notes. Net debt outstanding, after unamortized debt issuance costs and premiums, equaled $4.1 billion.
At December 31, 2017, Range’s bank facility had a borrowing base of $3.0 billion, and bank commitments of $2.0 billion, with an outstanding balance of $1.2 billion and undrawn letters of credit of $281 million, leaving $508 million of borrowing capacity available under the commitment amount.
Guidance – 2018
Production per day Guidance
Production for the first quarter of 2018 is expected to be approximately 2.18 Bcfe per day.
Production for the full year 2018 is expected to average approximately 2.23 Bcfe per day. This equates to a year-over-year growth rate of approximately 11%.
1Q 2018 Expense Guidance
| Direct operating expense: | $0.18 - $0.19 per mcfe | |
| Transportation, gathering, processing and compression expense: | $1.04 - $1.08 per mcfe | |
| Production tax expense: | $0.05 - $0.07 per mcfe | |
| Exploration expense: | $7.0 - $10.0 million | |
| Unproved property impairment expense: | $13.0 - $15.0 million | |
| G&A expense: | $0.21 - $0.23 per mcfe | |
| Interest expense: | $0.26 - $0.28 per mcfe | |
| DD&A expense: | $0.82 - $0.85 per mcfe | |
| Net brokered gas marketing expense: | ~$2.0 million |
1Q 2018 Natural gas price differentials NYMEX plus $0.11
Based on current market pricing indications, Range expects to receive the following pre-hedge differentials for its production in 2018.
| Natural Gas: | NYMEX minus $0.15 | |
| Natural Gas Liquids (including ethane): | 28% - 32% of WTI | |
| Oil/Condensate: | WTI minus $5.00 to 6.00 |
Hedging Status
Range hedges portions of its expected future production volumes to increase the predictability of cash flow and to help maintain a strong, flexible financial position. Range currently has over 70% of its expected 2018 natural gas production hedged at a weighted average floor price of $3.09 per mcf. Similarly, Range has hedged over 70% of its 2018 projected crude oil production at a floor price of $53.30 and approximately 50% of its composite NGL production. Please see Range’s detailed hedging schedule posted at the end of the financial tables below and on its website at www.rangeresources.com.
Range has also hedged Marcellus and other basis differentials to limit volatility between NYMEX and regional prices. The fair value of the basis hedges as of December 31, 2017 was a loss of $7.8 million, compared to a gain of $11.8 million at December 31, 2016.
Conference Call Information
A conference call to review the financial results is scheduled on Wednesday, February 28 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 7649028 about 10 minutes prior to the scheduled start time.
A simultaneous webcast of the call may be accessed at www.rangeresources.com. The webcast will be archived for replay on the Company's website until March 28.
Non-GAAP Financial Measures
Adjusted net income comparable to analysts’ estimates as set forth in this release represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed in the accompanying table) less income taxes. We believe adjusted net income comparable to analysts’ estimates is calculated on the same basis as analysts’ estimates and that many investors use this published research in making investment decisions and evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income comparable to analysts’ estimates on a diluted per share basis. A table is included which reconciles income or loss from operations to adjusted net income comparable to analysts’ estimates and diluted earnings per share (adjusted). On its website, the Company provides additional comparative information on prior periods along with non-GAAP revenue disclosures.
Cash flow from operations before changes in working capital (sometimes referred to as “adjusted cash flow”) as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles net cash provided by operations to cash flow from operations before changes in working capital as used in this release. On its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.
The cash prices realized for oil and natural gas production, including the amounts realized on cash-settled derivatives and net of transportation, gathering, processing and compression expense, is a critical component in the Company’s performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various derivative transactions and third-party transportation, gathering, processing and compression expense, such information is now reported in various lines of the income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third-party transportation, gathering, processing and compression expense which historically were reported as natural gas, NGLs and oil sales. This information is intended to bridge the gap between various readers’ understanding and fully disclose the information needed.
The Company discloses in this release the detailed components of many of the single line items shown in the GAAP financial statements included in the Company’s Annual Report on Form 10-K. The Company believes that it is important to furnish this detail of the various components comprising each line of the Statements of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.
Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. Drill-bit development cost per mcfe is based on estimated and unaudited drilling, development and exploration costs incurred divided by the total of reserve additions, performance and price revisions. These calculations do not include the future development costs required for the development of proved undeveloped reserves. This reserves metric may not be comparable to similarly titled measurements used by other companies. The SEC method of computing finding costs contains additional cost components and results in a higher number. A reconciliation of the two methods is shown on our website at www.rangeresources.com.
The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance. In addition, since the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation.
We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on prices and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and security analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis.
RANGE RESOURCES CORPORATION (NYSE:RRC) is a leading U.S. independent oil and natural gas producer with operations focused in stacked-pay projects in the Appalachian Basin and North Louisiana. The Company pursues an organic growth strategy targeting high return, low-cost projects within its large inventory of low risk development drilling opportunities. The Company is headquartered in Fort Worth, Texas. More information about Range can be found at www.rangeresources.com.
Included within are certain “forward-looking statements” within the meaning of the federal securities laws, including the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 that are not limited to historical facts, but reflect Range’s current beliefs, expectations or intentions regarding future events. Words such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “outlook”, “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forward-looking statements.
All statements, except for statements of historical fact, made within regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future well costs, expected asset sales, well productivity, future liquidity and financial resilience, anticipated exports and related financial impact, NGL market supply and demand, improving commodity fundamentals and pricing, future capital efficiencies, future shareholder value, emerging plays, capital spending, anticipated drilling and completion activity, acreage prospectivity, expected pipeline utilization and future guidance information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and Range's future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements. Further information on risks and uncertainties is available in Range's filings with the Securities and Exchange Commission (SEC), including its most recent Annual Report on Form 10-K. Unless required by law, Range undertakes no obligation to publicly update or revise any forward-looking statements to reflect circumstances or events after the date they are made.
The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves. Range has elected not to disclose its probable and possible reserves in its filings with the SEC. Range uses certain broader terms such as "resource potential,” “unrisked resource potential,” "unproved resource potential" or "upside" or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. 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 actually being realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unproven resource potential has not been fully risked by Range's management. “EUR”, or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially. Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data.
In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K on the SEC’s website at www.sec.gov or by calling the SEC at 1-800-SEC-0330.
Investor Contacts:
Laith Sando, Vice President – Investor Relations
817-869-4267
lsando@rangeresources.com
David Amend, Investor Relations Manager
817-869-4266
damend@rangeresources.com
Michael Freeman, Investor Relations Manager
817-869-4264
mfreeman@rangeresources.com
Josh Stevens, Senior Financial Analyst
817-869-1564
jrstevens@rangeresources.com
Media Contact:
Michael Mackin, Director of External Affairs
724-743-6776
mmackin@rangeresources.com
RANGE RESOURCES CORPORATION
| STATEMENTS OF OPERATIONS | |||||||||||||||||||||||
| Based on GAAP reported earnings with additional | |||||||||||||||||||||||
| details of items included in each line in Form 10-K | |||||||||||||||||||||||
| (Unaudited, in thousands, except per share data) | |||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2017 | 2016 | % | 2017 | 2016 | % | ||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||
| Natural gas, NGLs and oil sales (a) | $ | 603,159 | $ | 458,645 | $ | 2,176,287 | $ | 1,197,215 | |||||||||||||||
| Derivative fair value income/(loss) | 25,024 | (250,057 | ) | 213,350 | (261,391 | ) | |||||||||||||||||
| Brokered natural gas, marketing and other (b) | 50,732 | 44,774 | 219,474 | 163,219 | |||||||||||||||||||
| ARO settlement (loss) gain (b) | (17 | ) | 54 | 47 | 40 | ||||||||||||||||||
| Other (b) | 134 | 106 | 1,872 | 856 | |||||||||||||||||||
| Total revenues and other income | 679,032 | 253,522 | 168 | % | 2,611,030 | 1,099,939 | 137 | % | |||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Direct operating | 37,424 | 29,755 | 132,192 | 95,086 | |||||||||||||||||||
| Direct operating – non-cash stock-based compensation (c) | 497 | 521 | 2,060 | 2,302 | |||||||||||||||||||
| Transportation, gathering, processing and compression | 200,300 | 164,338 | 761,183 | 565,209 | |||||||||||||||||||
| Production and ad valorem taxes | 11,757 | 6,790 | 42,882 | 25,443 | |||||||||||||||||||
| Brokered natural gas and marketing | 50,734 | 46,095 | 218,874 | 166,851 | |||||||||||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation (c) | 397 | 376 | 1,437 | 1,725 | |||||||||||||||||||
| Exploration | 6,747 | 13,055 | 50,920 | 30,027 | |||||||||||||||||||
| Exploration – non-cash stock-based compensation (c) | 1,146 | 629 | 2,742 | 2,298 | |||||||||||||||||||
| Abandonment and impairment of unproved properties | 217,544 | 6,307 | 269,725 | 30,076 | |||||||||||||||||||
| General and administrative | 41,167 | 44,285 | 150,786 | 132,104 | |||||||||||||||||||
| General and administrative – non-cash stock-based compensation (c) | 39,717 | 11,611 | 74,873 | 49,293 | |||||||||||||||||||
| General and administrative – lawsuit settlements | (831 | ) | 1,131 | 6,197 | 2,575 | ||||||||||||||||||
| General and administrative – bad debt expense | 500 | — | 1,550 | 800 | |||||||||||||||||||
| Memorial merger expenses | — | 813 | — | 37,225 | |||||||||||||||||||
| Termination costs | (278 | ) | (822 | ) | 2,106 | (519 | ) | ||||||||||||||||
| Termination costs – non-cash stock-based compensation (c) | (1 | ) | — | 1,664 | — | ||||||||||||||||||
| Deferred compensation plan (d) | (14,077 | ) | (11,013 | ) | (50,915 | ) | 19,153 | ||||||||||||||||
| Interest expense | 51,473 | 46,749 | 195,679 | 168,213 | |||||||||||||||||||
| Depletion, depreciation and amortization | 162,918 | 149,662 | 624,992 | 524,102 | |||||||||||||||||||
| Impairment of proved properties and other assets | — | — | 63,679 | 43,040 | |||||||||||||||||||
| (Gain) loss on sale of assets | (207 | ) | (470 | ) | (23,716 | ) | 7,074 | ||||||||||||||||
| Total costs and expenses | 806,927 | 509,812 | 58 | % | 2,528,910 | 1,902,077 | 33 | % | |||||||||||||||
| (Loss) income before income taxes | (127,895 | ) | (256,290 | ) | 50 | % | 82,120 | (802,138 | ) | 110 | % | ||||||||||||
| Income taxes: | |||||||||||||||||||||||
| Current | 17 | 98 | 17 | 98 | |||||||||||||||||||
| Deferred | (349,097 | ) | (95,679 | ) | (251,043 | ) | (280,848 | ) | |||||||||||||||
| (349,080 | ) | (95,581 | ) | (251,026 | ) | (280,750 | ) | ||||||||||||||||
| Net income (loss) | $ | 221,185 | $ | (160,709 | ) | 238 | % | $ | 333,146 | $ | (521,388 | ) | 164 | % | |||||||||
| Net Income (Loss) Per Common Share: | |||||||||||||||||||||||
| Basic | $ | 0.89 | $ | (0.66 | ) | $ | 1.34 | $ | (2.75 | ) | |||||||||||||
| Diluted | $ | 0.89 | $ | (0.66 | ) | $ | 1.34 | $ | (2.75 | ) | |||||||||||||
| Weighted average common shares outstanding, as reported: | |||||||||||||||||||||||
| Basic | 245,281 | 244,362 | 0 | % | 245,091 | 189,868 | 29 | % | |||||||||||||||
| Diluted | 245,537 | 244,362 | 0 | % | 245,458 | 189,868 | 29 | % | |||||||||||||||
(a) See separate natural gas, NGLs and oil sales information table.
(b) Included in Brokered natural gas, marketing and other revenues in the 10-K.
(c) Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct personnel costs, which are combined with the cash costs in the 10-K.
(d) Reflects the change in market value of the vested Company stock held in the deferred compensation plan.
RANGE RESOURCES CORPORATION
| BALANCE SHEETS | |||||||
| (In thousands) | December 31, | December 31, | |||||
| 2017 | 2016 | ||||||
| (Audited) | (Audited) | ||||||
| Assets | |||||||
| Current assets | $ | 370,627 | $ | 268,605 | |||
| Derivative assets | 58,880 | 13,483 | |||||
| Goodwill | 1,641,197 | 1,654,292 | |||||
| Natural gas and oil properties, successful efforts method | 9,566,737 | 9,256,337 | |||||
| Transportation and field assets | 14,666 | 16,873 | |||||
| Other | 76,734 | 72,655 | |||||
| $ | 11,728,841 | $ | 11,282,245 | ||||
| Liabilities and Stockholders’ Equity | |||||||
| Current liabilities | $ | 704,913 | $ | 530,373 | |||
| Asset retirement obligations | 6,327 | 7,271 | |||||
| Derivative liabilities | 44,233 | 165,009 | |||||
| Bank debt | 1,208,467 | 876,428 | |||||
| Senior notes | 2,851,754 | 2,848,591 | |||||
| Senior subordinated notes | 48,585 | 48,498 | |||||
| Total debt | 4,108,806 | 3,773,517 | |||||
| Deferred tax liability | 693,356 | 943,343 | |||||
| Derivative liabilities | 9,789 | 24,491 | |||||
| Deferred compensation liability | 101,102 | 119,231 | |||||
| Asset retirement obligations and other liabilities | 286,043 | 310,642 | |||||
| Common stock and retained earnings | 5,776,203 | 5,409,577 | |||||
| Other comprehensive loss | (1,332 | ) | — | ||||
| Common stock held in treasury stock | (599 | ) | (1,209 | ) | |||
| Total stockholders’ equity | 5,774,272 | 5,408,368 | |||||
| $ | 11,728,841 | $ | 11,282,245 |
| RECONCILIATION OF TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING CERTAIN ITEMS, a non-GAAP measure | ||||||||||||||||||||||||
| (Unaudited, in thousands) | ||||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||
| 2017 | 2016 | % | 2017 | 2016 | % | |||||||||||||||||||
| Total revenues and other income, as reported | $ | 679,032 | $ | 253,522 | 168 | % | $ | 2,611,030 | $ | 1,099,939 | 137 | % | ||||||||||||
| Adjustment for certain special items: | ||||||||||||||||||||||||
| Total change in fair value related to derivatives prior to settlement (gain) loss | (27,969 | ) | 336,736 | (200,233 | ) | 608,727 | ||||||||||||||||||
| ARO settlement (gain) loss | 17 | (54 | ) | (47 | ) | (40 | ) | |||||||||||||||||
| Total revenues, as adjusted, non-GAAP | $ | 651,080 | $ | 590,204 | 10 | % | $ | 2,410,750 | $ | 1,708,626 | 41 | % | ||||||||||||
RANGE RESOURCES CORPORATION
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||
| (Unaudited in thousands) | |||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||||
| Net income (loss) | $ | 221,185 | $ | (160,709 | ) | $ | 333,146 | $ | (521,388 | ) | |||||||
| Adjustments to reconcile net cash provided from continuing operations: | |||||||||||||||||
| Deferred income taxes | (349,097 | ) | (95,679 | ) | (251,043 | ) | (280,848 | ) | |||||||||
| Depletion, depreciation, amortization and impairment | 162,918 | 149,662 | 688,671 | 567,142 | |||||||||||||
| Exploration dry hole costs | 6 | 16 | 9,172 | 18 | |||||||||||||
| Abandonment and impairment of unproved properties | 217,544 | 6,307 | 269,725 | 30,076 | |||||||||||||
| Derivative fair value income (loss) | (25,024 | ) | 250,057 | (213,350 | ) | 261,391 | |||||||||||
| Cash settlements on derivative financial instruments that do not qualify for hedge | |||||||||||||||||
| Accounting | (2,945 | ) | 86,679 | 13,117 | 347,336 | ||||||||||||
| Allowance for bad debts | 500 | — | 1,550 | 800 | |||||||||||||
| Amortization of deferred issuance costs, loss on extinguishment of debt, and other | 1,261 | 1,787 | 5,445 | 7,170 | |||||||||||||
| Deferred and stock-based compensation | 26,769 | 1,996 | 30,706 | 74,685 | |||||||||||||
| (Gain) loss on sale of assets and other | (207 | ) | (470 | ) | (23,716 | ) | 7,074 | ||||||||||
| Changes in working capital: | |||||||||||||||||
| Accounts receivable | (63,172 | ) | (52,571 | ) | (102,866 | ) | (20,586 | ) | |||||||||
| Inventory and other | (1,475 | ) | 6,996 | (2,979 | ) | 6,220 | |||||||||||
| Accounts payable | 1,197 | 14,009 | 45,912 | (27,259 | ) | ||||||||||||
| Accrued liabilities and other | 26,262 | (26,849 | ) | 12,764 | (64,763 | ) | |||||||||||
| Net changes in working capital | (37,188 | ) | (58,415 | ) | (47,169 | ) | (106,388 | ) | |||||||||
| Net cash provided from operating activities | $ | 215,722 | $ | 181,231 | $ | 816,254 | $ | 387,068 | |||||||||
| RECONCILIATION OF NET CASH PROVIDED FROM OPERATING ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP measure | |||||||||||||||||
| (Unaudited, in thousands) | |||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||||
| Net cash provided from operating activities, as reported | $ | 215,722 | $ | 181,231 | $ | 816,254 | $ | 387,068 | |||||||||
| Net changes in working capital | 37,188 | 58,415 | 47,169 | 106,388 | |||||||||||||
| Exploration expense | 6,230 | 13,039 | 41,237 | 30,009 | |||||||||||||
| Memorial merger expenses | — | 813 | — | 37,225 | |||||||||||||
| Lawsuit settlements | (831 | ) | 1,131 | 6,197 | 2,575 | ||||||||||||
| Cash paid to exchange senior subordinated notes | — | — | — | 6,600 | |||||||||||||
| Termination costs | (278 | ) | (822 | ) | 2,106 | (519 | ) | ||||||||||
| Non-cash compensation adjustment | 2,021 | 56 | 3,403 | 19 | |||||||||||||
| Cash flow from operations before changes in working capital – non-GAAP measure | $ | 260,052 | $ | 253,863 | $ | 916,366 | $ | 569,365 | |||||||||
| ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | |||||||||||||||||
| (Unaudited, in thousands) | |||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||||
| Basic: | |||||||||||||||||
| Weighted average shares outstanding | 248,140 | 247,161 | 247,882 | 192,661 | |||||||||||||
| Stock held by deferred compensation plan | (2,859 | ) | (2,799 | ) | (2,791 | ) | (2,793 | ) | |||||||||
| Adjusted basic | 245,281 | 244,362 | 245,091 | 189,868 | |||||||||||||
| Dilutive: | |||||||||||||||||
| Weighted average shares outstanding | 248,140 | 247,161 | 247,882 | 192,661 | |||||||||||||
| Dilutive stock options under treasury method | (2,603 | ) | (2,799 | ) | (2,424 | ) | (2,793 | ) | |||||||||
| Adjusted dilutive | 245,537 | 244,362 | 245,458 | 189,868 | |||||||||||||
RANGE RESOURCES CORPORATION
| RECONCILIATION OF NATURAL GAS, NGLs AND OIL SALES AND DERIVATIVE FAIR VALUE INCOME (LOSS) TO CALCULATED CASH REALIZED NATURAL GAS, NGLs AND OIL PRICES WITH AND WITHOUT THIRD PARTY TRANSPORTATION, GATHERING AND COMPRESSION FEES, a non-GAAP measure | ||||||||||||||||||||||||
| (Unaudited, in thousands, except per unit data) | ||||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||||
| 2017 | 2016 | % | 2017 | 2016 | % | |||||||||||||||||||
| Natural gas, NGL and oil sales components: | ||||||||||||||||||||||||
| Natural gas sales | $ | 340,965 | $ | 289,790 | $ | 1,349,965 | $ | 753,888 | ||||||||||||||||
| NGL sales | 192,232 | 119,585 | 604,672 | 318,462 | ||||||||||||||||||||
| Oil sales | 69,962 | 49,270 | 221,650 | 124,865 | ||||||||||||||||||||
| Total oil and gas sales, as reported | $ | 603,159 | $ | 458,645 | 32 | % | $ | 2,176,287 | $ | 1,197,215 | 82 | % | ||||||||||||
| Derivative fair value income (loss), as reported: | $ | 25,024 | $ | (250,057 | ) | $ | 213,350 | $ | (261,391 | ) | ||||||||||||||
| Cash settlements on derivative financial instruments – (gain) loss: | ||||||||||||||||||||||||
| Natural gas | (36,412 | ) | (46,015 | ) | (71,059 | ) | (252,000 | ) | ||||||||||||||||
| NGLs | 39,733 | (22,231 | ) | 73,192 | (47,626 | ) | ||||||||||||||||||
| Crude Oil | (376 | ) | (18,433 | ) | (15,250 | ) | (47,710 | ) | ||||||||||||||||
| Total change in fair value related to derivatives prior to settlement, a non-GAAP measure | $ | 27,969 | $ | (336,736 | ) | $ | 200,233 | $ | (608,727 | ) | ||||||||||||||
| Transportation, gathering, processing and compression components: | ||||||||||||||||||||||||
| Natural gas | $ | 141,902 | $ | 114,854 | $ | 526,671 | $ | 403,209 | ||||||||||||||||
| NGLs | 58,398 | 49,484 | 234,512 | 162,000 | ||||||||||||||||||||
| Total transportation, gathering, processing and compression, as reported | $ | 200,300 | $ | 164,338 | $ | 761,183 | $ | 565,209 | ||||||||||||||||
| Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | ||||||||||||||||||||||||
| Natural gas sales | $ | 377,377 | $ | 335,805 | $ | 1,421,024 | $ | 1,005,888 | ||||||||||||||||
| NGL sales | 152,499 | 141,816 | 531,480 | 366,088 | ||||||||||||||||||||
| Oil sales | 70,338 | 67,703 | 236,900 | 172,575 | ||||||||||||||||||||
| Total | $ | 600,214 | $ | 545,324 | 10 | % | $ | 2,189,404 | $ | 1,544,551 | 42 | % | ||||||||||||
| Production of oil and gas during the periods (a): | ||||||||||||||||||||||||
| Natural gas (mcf) | 132,864,354 | 114,480,336 | 16 | % | 490,253,467 | 375,811,462 | 30 | % | ||||||||||||||||
| NGL (bbl) | 9,755,481 | 8,245,792 | 18 | % | 35,709,254 | 27,825,635 | 28 | % | ||||||||||||||||
| Oil (bbl) | 1,380,649 | 1,104,414 | 25 | % | 4,787,022 | 3,609,171 | 33 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) | 199,681,134 | 170,581,572 | 17 | % | 733,231,123 | 564,420,298 | 30 | % | ||||||||||||||||
| Production of oil and gas – average per day (a): | ||||||||||||||||||||||||
| Natural gas (mcf) | 1,444,178 | 1,244,351 | 16 | % | 1,343,160 | 1,026,807 | 31 | % | ||||||||||||||||
| NGL (bbl) | 106,038 | 89,628 | 18 | % | 97,834 | 76,026 | 29 | % | ||||||||||||||||
| Oil (bbl) | 15,007 | 12,005 | 25 | % | 13,115 | 9,861 | 33 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) | 2,170,447 | 1,854,148 | 17 | % | 2,008,852 | 1,542,132 | 30 | % | ||||||||||||||||
| Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | ||||||||||||||||||||||||
| Natural gas (mcf) | $ | 2.57 | $ | 2.53 | 1 | % | $ | 2.75 | $ | 2.01 | 37 | % | ||||||||||||
| NGL (bbl) | $ | 19.71 | $ | 14.50 | 36 | % | $ | 16.93 | $ | 11.44 | 48 | % | ||||||||||||
| Oil (bbl) | $ | 50.67 | $ | 44.61 | 14 | % | $ | 46.30 | $ | 34.60 | 34 | % | ||||||||||||
| Gas equivalent (mcfe) (b) | $ | 3.02 | $ | 2.69 | 12 | % | $ | 2.97 | $ | 2.12 | 40 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | ||||||||||||||||||||||||
| Natural gas (mcf) | $ | 2.84 | $ | 2.93 | -3 | % | $ | 2.90 | $ | 2.68 | 8 | % | ||||||||||||
| NGL (bbl) | $ | 15.63 | $ | 17.20 | -9 | % | $ | 14.88 | $ | 13.16 | 13 | % | ||||||||||||
| Oil (bbl) | $ | 50.95 | $ | 61.30 | -17 | % | $ | 49.49 | $ | 47.82 | 3 | % | ||||||||||||
| Gas equivalent (mcfe) (b) | $ | 3.01 | $ | 3.20 | -6 | % | $ | 2.99 | $ | 2.74 | 9 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives: (d) | ||||||||||||||||||||||||
| Natural gas (mcf) | $ | 1.77 | $ | 1.93 | -8 | % | $ | 1.82 | $ | 1.60 | 14 | % | ||||||||||||
| NGL (bbl) | $ | 9.65 | $ | 11.20 | -14 | % | $ | 8.32 | $ | 7.33 | 13 | % | ||||||||||||
| Oil (bbl) | $ | 50.95 | $ | 61.30 | -17 | % | $ | 49.49 | $ | 47.82 | 3 | % | ||||||||||||
| Gas equivalent (mcfe) (b) | $ | 2.00 | $ | 2.23 | -10 | % | $ | 1.95 | $ | 1.74 | 12 | % | ||||||||||||
| Transportation, gathering and compression expense per mcfe | $ | 1.00 | $ | 0.96 | 4 | % | $ | 1.04 | $ | 1.00 | 4 | % | ||||||||||||
(a) Represents volumes sold regardless of when produced.
(b) Oil and NGLs are converted at the rate of one barrel equals six mcfe based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
(c) Excluding third party transportation, gathering and compression costs.
(d) Net of transportation, gathering, processing and compression costs.
RANGE RESOURCES CORPORATION
| RECONCILIATION OF INCOME BEFORE INCOME TAXES AS REPORTED TO INCOME BEFORE INCOME TAXES EXCLUDING CERTAIN ITEMS, a non-GAAP measure | | ||||||||||||||||||||||
| (Unaudited, in thousands, except per share data) | |||||||||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
| 2017 | 2016 | % | 2017 | 2016 | % | ||||||||||||||||||
| (Loss) income from operations before income taxes, as reported | $ | (127,895 | ) | $ | (256,290 | ) | 50 | % | $ | 82,120 | $ | (802,138 | ) | 110 | % | ||||||||
| Adjustment for certain special items: | |||||||||||||||||||||||
| Loss (gain) on sale of assets | (207 | ) | (470 | ) | (23,716 | ) | 7,074 | ||||||||||||||||
| (Gain) loss on ARO settlements | 17 | (54 | ) | (47 | ) | (40 | ) | ||||||||||||||||
| Change in fair value related to derivatives prior to settlement | (27,969 | ) | 336,736 | (200,233 | ) | 608,727 | |||||||||||||||||
| Abandonment and impairment of unproved properties | 217,544 | 6,307 | 269,725 | 30,076 | |||||||||||||||||||
| Impairment of proved property | — | — | 63,679 | 43,040 | |||||||||||||||||||
| Memorial merger expenses | — | 813 | — | 37,225 | |||||||||||||||||||
| Lawsuit settlements | (831 | ) | 1,131 | 6,197 | 2,575 | ||||||||||||||||||
| Fees paid to exchange senior subordinated notes | — | — | — | 6,600 | |||||||||||||||||||
| Termination costs | (278 | ) | (822 | ) | 2,106 | (519 | ) | ||||||||||||||||
| Termination costs – non-cash stock-based compensation | (1 | ) | — | 1,664 | — | ||||||||||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation | 397 | 376 | 1,437 | 1,725 | |||||||||||||||||||
| Direct operating – non-cash stock-based compensation | 497 | 521 | 2,060 | 2,302 | |||||||||||||||||||
| Exploration expenses – non-cash stock-based compensation | 1,146 | 629 | 2,742 | 2,298 | |||||||||||||||||||
| General & administrative – non-cash stock-based compensation | 39,717 | 11,611 | 74,873 | 49,293 | |||||||||||||||||||
| Deferred compensation plan – non-cash adjustment | (14,077 | ) | (11,013 | ) | (50,915 | ) | 19,153 | ||||||||||||||||
| Income (loss) before income taxes, as adjusted | 88,060 | 89,475 | -2 | % | 231,692 | 7,391 | 3,035 | % | |||||||||||||||
| Income tax expense, as adjusted | |||||||||||||||||||||||
| Current | 17 | 98 | 17 | 98 | |||||||||||||||||||
| Deferred (a) | 33,446 | 33,760 | 88,738 | 2,426 | |||||||||||||||||||
| Net income (loss) excluding certain items, a non-GAAP measure | $ | 54,597 | $ | 55,618 | -2 | % | $ | 142,937 | $ | 4,867 | 2,837 | % | |||||||||||
| Non-GAAP (loss) income per common share | |||||||||||||||||||||||
| Basic | $ | 0.22 | $ | 0.23 | -4 | % | $ | 0.58 | $ | 0.03 | 1,833 | % | |||||||||||
| Diluted | $ | 0.22 | $ | 0.23 | -4 | % | $ | 0.58 | $ | 0.03 | 1,833 | % | |||||||||||
| Non-GAAP diluted shares outstanding, if dilutive | 245,537 | 244,761 | 245,458 | 189,911 | |||||||||||||||||||
(a) Deferred taxes for 2017 and 2016 are estimated to be approximately 38%.
RANGE RESOURCES CORPORATION
| RECONCILIATION OF NET INCOME (LOSS), EXCLUDING CERTAIN ITEMS AND ADJUSTMENT EARNINGS PER SHARE, non-GAAP measures | |||||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||||
| Net income (loss), as reported | $ | 221,185 | $ | (160,709 | ) | $ | 333,146 | $ | (521,388 | ) | |||||||
| Adjustment for certain special items: | |||||||||||||||||
| (Gain) loss on sale of assets | (207 | ) | (470 | ) | (23,716 | ) | 7,074 | ||||||||||
| Loss (gain) on ARO settlements | 17 | (54 | ) | (47 | ) | (40 | ) | ||||||||||
| Change in fair value related to derivatives prior to settlement | (27,969 | ) | 336,736 | (200,233 | ) | 608,727 | |||||||||||
| Impairment of proved property | — | — | 63,679 | 43,040 | |||||||||||||
| Abandonment and impairment of unproved properties | 217,544 | 6,307 | 269,725 | 30,076 | |||||||||||||
| MRD merger expenses | — | 813 | — | 37,225 | |||||||||||||
| Fees paid to exchange senior subordinated notes | — | 6,600 | |||||||||||||||
| Lawsuit settlements | (831 | ) | 1,131 | 6,197 | 2,575 | ||||||||||||
| Termination costs | (278 | ) | (822 | ) | 2,106 | (519 | ) | ||||||||||
| Non-cash stock-based compensation | 41,756 | 13,137 | 82,776 | 55,618 | |||||||||||||
| Deferred compensation plan | (14,077 | ) | (11,013 | ) | (50,915 | ) | 19,153 | ||||||||||
| Tax impact | (382,543 | ) | (129,439 | ) | (339,781 | ) | (283,274 | ) | |||||||||
| Net income (loss) excluding certain items, a non-GAAP measure | $ | 54,597 | $ | 55,618 | $ | 142,937 | $ | 4,867 | |||||||||
| Net income (loss) per diluted share, as reported | $ | 0.89 | $ | (0.66 | ) | $ | 1.34 | $ | (2.75 | ) | |||||||
| Adjustment for certain special items per diluted share: | |||||||||||||||||
| (Gain) loss on sale of assets | (0.00 | ) | (0.00 | ) | (0.10 | ) | 0.04 | ||||||||||
| Change in fair value related to derivatives prior to settlement | (0.11 | ) | 1.38 | (0.82 | ) | 3.21 | |||||||||||
| Impairment of proved property | — | — | 0.26 | 0.23 | |||||||||||||
| Abandonment and impairment of unproved properties | 0.89 | 0.03 | 1.10 | 0.16 | |||||||||||||
| MRD merger expenses | — | 0.00 | — | 0.20 | |||||||||||||
| Fees paid to exchange senior subordinated notes | — | — | — | 0.03 | |||||||||||||
| Lawsuit settlements | (0.00 | ) | 0.00 | 0.03 | 0.01 | ||||||||||||
| Termination costs | (0.00 | ) | (0.00 | ) | 0.01 | (0.00 | ) | ||||||||||
| Non-cash stock-based compensation | 0.17 | 0.05 | 0.34 | 0.29 | |||||||||||||
| Deferred compensation plan | (0.06 | ) | (0.05 | ) | (0.21 | ) | 0.10 | ||||||||||
| Adjustment for rounding differences | 0.01 | — | 0.01 | 0.01 | |||||||||||||
| Tax impact | (1.56 | ) | (0.53 | ) | (1.38 | ) | (1.49 | ) | |||||||||
| Net income (loss) per diluted share, excluding certain items, a non-GAAP measure | $ | 0.22 | $ | 0.23 | $ | 0.58 | $ | 0.03 | |||||||||
| Adjusted earnings (loss) per share, a non-GAAP measure: | |||||||||||||||||
| Basic | $ | 0.22 | $ | 0.23 | $ | 0.58 | $ | 0.03 | |||||||||
| Diluted | $ | 0.22 | $ | 0.23 | $ | 0.58 | $ | 0.03 | |||||||||
RANGE RESOURCES CORPORATION
| RECONCILIATION OF CASH MARGIN PER MCFE, a non-GAAP measure | |||||||||||||||||
| (Unaudited, in thousands, except per unit data) | |||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||||
| Revenues | |||||||||||||||||
| Natural gas, NGL and oil sales, as reported | $ | 603,159 | $ | 458,645 | $ | 2,176,287 | $ | 1,197,215 | |||||||||
| Derivative fair value income (loss), as reported | 25,024 | (250,057 | ) | 213,350 | (261,391 | ) | |||||||||||
| Less non-cash fair value (gain) loss | (27,969 | ) | 336,736 | (200,233 | ) | 608,727 | |||||||||||
| Brokered natural gas and marketing and other, as reported | 50,849 | 44,934 | 221,393 | 164,115 | |||||||||||||
| Less ARO settlement and other (gains) losses | (117 | ) | (160 | ) | (1,919 | ) | (896 | ) | |||||||||
| Cash revenue applicable to production | 650,946 | 590,098 | 2,408,878 | 1,707,770 | |||||||||||||
| Expenses | |||||||||||||||||
| Direct operating, as reported | 37,921 | 30,276 | 134,252 | 97,388 | |||||||||||||
| Less direct operating stock-based compensation | (497 | ) | (521 | ) | (2,060 | ) | (2,302 | ) | |||||||||
| Transportation, gathering and compression, as reported | 200,300 | 164,338 | 761,183 | 565,209 | |||||||||||||
| Production and ad valorem taxes, as reported | 11,757 | 6,790 | 42,882 | 25,443 | |||||||||||||
| Brokered natural gas and marketing, as reported | 51,131 | 46,471 | 220,311 | 168,576 | |||||||||||||
| Less brokered natural gas and marketing stock-based compensation | (397 | ) | (376 | ) | (1,437 | ) | (1,725 | ) | |||||||||
| General and administrative, as reported | 80,553 | 57,027 | 233,406 | 184,772 | |||||||||||||
| Less G&A stock-based compensation | (39,717 | ) | (11,611 | ) | (74,873 | ) | (49,293 | ) | |||||||||
| Less lawsuit settlements | 831 | (1,131 | ) | (6,197 | ) | (2,575 | ) | ||||||||||
| Interest expense, as reported | 51,473 | 46,749 | 195,679 | 168,213 | |||||||||||||
| Cash expenses | 393,355 | 338,012 | 1,503,146 | 1,153,706 | |||||||||||||
| Cash margin, a non-GAAP measure | $ | 257,591 | $ | 252,086 | $ | 905,732 | $ | 554,064 | |||||||||
| Mmcfe produced during period | 199,681 | 170,581 | 733,231 | 564,420 | |||||||||||||
| Cash margin per mcfe | $ | 1.29 | $ | 1.48 | $ | 1.24 | $ | 0.98 | |||||||||
| RECONCILIATION OF INCOME (LOSS) BEFORE INCOME TAXES TO CASH MARGIN | |||||||||||||||||
| (Unaudited, in thousands, except per unit data) | |||||||||||||||||
| Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||||
| Income (loss) before income taxes, as reported | $ | (127,895 | ) | $ | (256,290 | ) | $ | 82,120 | $ | (802,138 | ) | ||||||
| Adjustments to reconcile income (loss) before income taxes to cash margin: | |||||||||||||||||
| ARO settlements and other (gains) losses | (117 | ) | (160 | ) | (1,919 | ) | (896 | ) | |||||||||
| Derivative fair value (income) loss | (25,024 | ) | 250,057 | (213,350 | ) | 261,391 | |||||||||||
| Net cash receipts on derivative settlements | (2,945 | ) | 86,679 | 13,117 | 347,336 | ||||||||||||
| Exploration expense | 6,747 | 13,055 | 50,920 | 30,027 | |||||||||||||
| Lawsuit settlements | (831 | ) | 1,131 | 6,197 | 2,575 | ||||||||||||
| MRD merger expenses | — | 813 | — | 37,225 | |||||||||||||
| Termination costs | (278 | ) | (822 | ) | 2,106 | (519 | ) | ||||||||||
| Deferred compensation plan | (14,077 | ) | (11,013 | ) | (50,915 | ) | 19,153 | ||||||||||
| Stock-based compensation (direct operating, brokered natural gas and marketing, general and administrative and termination costs) | 41,756 | 13,137 | 82,776 | 55,618 | |||||||||||||
| Depletion, depreciation and amortization | 162,918 | 149,662 | 624,992 | 524,102 | |||||||||||||
| (Gain) loss on sale of assets | (207 | ) | (470 | ) | (23,716 | ) | 7,074 | ||||||||||
| Impairment of proved property and other assets | — | — | 63,679 | 43,040 | |||||||||||||
| Abandonment and impairment of unproved properties | 217,544 | 6,307 | 269,725 | 30,076 | |||||||||||||
| Cash margin, a non-GAAP measure | $ | 257,591 | $ | 252,086 | $ | 905,732 | $ | 554,064 | |||||||||
RANGE RESOURCES CORPORATION
HEDGING POSITION AS OF FEBRUARY 15, 2018 – (Unaudited)
| Daily Volume | Hedge Price | ||||||||||
| Gas 1 | |||||||||||
| 1Q 2018 Collars | 60,000 Mmbtu | $3.40 x $3.76 | |||||||||
| 1Q 2018 Swaps | 1,100,778 Mmbtu | $3.41 | |||||||||
| 2Q 2018 Swaps | 1,110,000 Mmbtu | $2.98 | |||||||||
| 3Q 2018 Swaps | 1,110,000 Mmbtu | $2.98 | |||||||||
| 4Q 2018 Swaps | 1,083,478 Mmbtu | $2.98 | |||||||||
| 2019 Swaps | 237,329 Mmbtu | $2.88 | |||||||||
| Oil | |||||||||||
| 1Q 2018 Swaps | 9,750 bbls | $53.42 | |||||||||
| 2Q 2018 Swaps | 9,250 bbls | $53.35 | |||||||||
| 3Q 2018 Swaps | 8,500 bbls | $53.20 | |||||||||
| 4Q 2018 Swaps | 8,500 bbls | $53.20 | |||||||||
| 2019 Swaps | 5,622 bbls | $53.49 | |||||||||
| C2 Ethane | |||||||||||
| 1H 2018 Swaps | 250 bbls | $0.29/gallon | |||||||||
| C3 Propane 2 | |||||||||||
| 1Q 2018 Collars | 2,000 bbls | $0.90 x $1.05 /gallon | |||||||||
| 1Q 2018 Swaps | 14,250 bbls | $0.70/gallon | |||||||||
| 2Q 2018 Swaps | 11,960 bbls | $0.66/gallon | |||||||||
| 3Q 2018 Swaps | 8,918 bbls | $0.62/gallon | |||||||||
| 4Q 2018 Swaps | 7,918 bbls | $0.59/gallon | |||||||||
| C4 Normal Butane | |||||||||||
| 1Q 2018 Swaps | 5,500 bbls | $0.82/gallon | |||||||||
| 2Q 2018 Swaps | 4,500 bbls | $0.81/gallon | |||||||||
| 3Q 2018 Swaps | 4,250 bbls | $0.81/gallon | |||||||||
| 4Q 2018 Swaps | 4,250 bbls | $0.81/gallon | |||||||||
| C5 Natural Gasoline | |||||||||||
| 1Q 2018 Swaps | 5,917 bbls | $1.19/gallon | |||||||||
| 2Q 2018 Swaps | 5,159 bbls | $1.22/gallon | |||||||||
| 3Q 2018 Swaps | 4,902 bbls | $1.21/gallon | |||||||||
| 4Q 2018 Swaps | 4,652 bbls | $1.21/gallon | |||||||||
| 1H 2019 Swaps | 1,000 bbls | $1.24/gallon | |||||||||
- Range also sold call swaptions of 220,000 Mmbtu/d for April-December 2018 and 245,000 Mmbtu/d for calendar 2019 at average strike prices of $2.87 and $3.04 per Mmbtu, respectively
- Swaps incorporate international propane hedges
SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS AND ADDITIONAL HEDGING DETAILS