FORT WORTH, Texas, Aug. 01, 2017 (GLOBE NEWSWIRE) -- RANGE RESOURCES CORPORATION (NYSE:RRC) today announced its second quarter 2017 financial results.
Highlights –
- Second quarter GAAP net income was $70 million, or $0.28 per diluted share, compared to a net loss of $225 million, or $1.35 per share in the prior-year quarter
- Second quarter cash margins improved to $1.09 per mcfe, compared to $0.70 per mcfe in the prior-year quarter, an improvement of 55%
- Cash flow from operations before changes in working capital, a non-GAAP measure, reached $194 million, compared to $93 million in second quarter 2016
- Record production totaled 1.945 Bcfe per day, an increase of 37% compared to the prior-year quarter
- Total unit costs continued to decline, with second quarter 2017 costs of $2.66 per mcfe, compared to $2.73 in the previous year quarter, an improvement of 3%
- Seven-well Marcellus pad on the western edge of the super-rich area with average IP’s per well of 29.1 Mmcfe per day (73% liquids)
- Four-well Marcellus pad on the eastern edge of the dry gas area with average IP’s per well of 30.0 Mmcf per day
Commenting, Jeff Ventura, the Company’s CEO said, “Range continues to improve both operationally and financially. Second quarter financial results continue to build on the first quarter improvement in earnings and cash flow, margins and total unit costs. Operationally, the Marcellus is continuing to see improvement in well results and capital efficiency. In southwest Pennsylvania this year, we have drilled some of our best wells to date on our 515,000 acre position, further demonstrating the size and quality of our acreage position. As we look forward to the next several years and beyond, with our extensive, core acreage positions, diversified low-cost transportation portfolio and talented technical team, Range is well-positioned to deliver significant shareholder value.”
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.
Second Quarter 2017
GAAP revenues for the second quarter of 2017 totaled $673 million (over 6 times second quarter 2016), GAAP net cash provided from operating activities including changes in working capital was $185 million (125% increase as compared to second quarter 2016) and GAAP earnings were $70 million ($0.28 per diluted share) versus a loss of $225 million ($1.35 per diluted share) in the prior-year quarter. Second quarter 2017 included $111 million in derivative gains due to decreased commodity prices, compared to a $163 million loss in second quarter 2016.
Non-GAAP revenues for second quarter 2017 totaled $565 million (56% increase compared to second quarter 2016) and cash flow from operations before changes in working capital, a non-GAAP measure, reached $194 million, compared to $93 million in second quarter 2016, an increase of 108%. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $16 million ($0.06 per diluted share) compared to a loss of $23 million ($0.14 per diluted share) for second quarter 2016.
The Company’s total unit costs were 3% lower than the second quarter of 2016, while cash unit costs were 1% higher than the prior-year quarter. Direct operating costs increased by $0.02 per mcfe over the prior-year quarter due to higher workover and well service costs. Transportation, gathering, processing and compression expense increased by $0.02 per mcfe over the prior-year quarter, which was more than offset by higher realized prices, as products were moved to more favorable markets with higher prices, thereby resulting in increased cash margins from the previous year. General and administrative, interest and depletion, depreciation and amortization expenses per mcfe continued to trend lower.
| Expenses | 2Q 2017 (per mcfe) | 2Q 2016 (per mcfe) | Increase (Decrease) | ||||||||
| Direct operating | $ | 0.17 | $ | 0.15 | 13 | % | |||||
| Transportation, gathering, processing and compression | 1.08 | 1.06 | 2 | % | |||||||
| Production and ad valorem taxes | 0.06 | 0.05 | 20 | % | |||||||
| General and administrative | 0.21 | 0.23 | (9 | %) | |||||||
| Interest expense | 0.27 | 0.29 | (7 | %) | |||||||
| Total cash unit costs(a) | 1.79 | 1.78 | 1 | % | |||||||
| Depletion, depreciation and amortization | 0.86 | 0.95 | (9 | %) | |||||||
| Total unit costs(a) | $ | 2.66 | $ | 2.73 | (3 | %) | |||||
(a) Totals may not add due to rounding.
Second 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 $2.88 per mcfe, a 15% increase from the prior-year quarter as price differentials improved for all of the Company’s products. 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 second quarter 2017 were: natural gas – 1,313 Mmcf per day ($2.82 per mcf), NGLs – 93,673 barrels per day ($14.15 per barrel) and crude oil and condensate – 11,569 barrels per day ($48.82 per barrel).
- The average Company natural gas price differential including the impact of basis hedges for second quarter 2017 improved to minus ($0.39) per mcf, compared to minus ($0.48) in second quarter 2016. The second quarter 2017 average natural gas price, before all hedging settlements, was $2.82 per mcf as compared to $1.50 per mcf in the prior-year quarter.
- Pre-hedge NGL realizations improved to 30% of West Texas Intermediate (“WTI”) crude oil in second quarter 2017, compared to 24% of WTI in second quarter 2016. Total NGL pricing per barrel after realized cash-settled hedging improved to $14.15 for second quarter 2017 compared to $11.57 per barrel in the prior-year quarter. Range’s realized NGL pricing includes ethane extraction and is net of processing and certain other costs.
- Crude oil and condensate price realizations, before realized hedges, for the second quarter 2017 averaged $43.52 per barrel, or $4.84 below WTI, compared to $31.74, or $13.57 below WTI in the prior-year quarter.
Capital Expenditures
Second quarter 2017 drilling expenditures of $280 million funded the drilling and completion of 35 (32 net) wells. A 100% success rate was achieved. In addition, during the quarter, $8.6 million was incurred on acreage purchases, $1.4 million on gas gathering systems and $7.1 million on seismic expense. Range is on target with its $1.15 billion capital budget for 2017.
Financial Position and Liquidity
At June 30, 2017, Range had total debt outstanding of $3.9 billion, before amortization of debt issuance costs and premium, consisting of $2.9 billion in senior notes, $954 million in bank debt and $49 million in senior subordinated notes. The outstanding bank debt of $954 million combined with $286 million of undrawn letters of credit provides committed liquidity of $760 million.
Operational Discussion
Range has updated its investor presentation. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – August 1, 2017”.
The table below summarizes second quarter activity and the number of wells expected to be turned in line (TIL) for the remainder of 2017:
| 2017 | ||||||
| Wells TIL - First Quarter | Wells TIL - Second Quarter | Wells TIL - 3rd and 4th Quarters | Planned Annual Total Wells to Sales | |||
| Super-Rich Area | 6 | 8 | 18 | 32 | ||
| Wet Area | 10 | 5 | 28 | 43 | ||
| Dry- SW | 6 | 8 | 22 | 36 | ||
| Dry- NE | — | 2 | — | 2 | ||
| Total Marcellus | 22 | 23 | 68 | 113 | ||
| Upper Red | 19 | 3 | 12 | 34 | ||
| Lower Red | 5 | 3 | 5 | 13 | ||
| Pink | 3 | — | 3 | 6 | ||
| Extension Area | — | — | 3 | 3 | ||
| Total N. LA. | 27 | 6 | 23 | 56 | ||
| Company Total | 49 | 29 | 91 | 169 | ||
Appalachia Division
Division production for second quarter 2017 averaged 1.5 net Bcfe per day, a 9% increase over the prior-year quarter. The southwest properties averaged 1,344 net Mmcfe per day during the quarter, a 13% increase over the prior-year quarter. The northeast properties averaged 155 net Mmcf per day during the quarter, a 17% decrease over the prior-year quarter. The division brought on line 23 wells in the second quarter, eight in the super-rich area, five in the wet area, eight in the southwest dry area and two in the northeast dry area.
Significantly, two exceptional pads were brought on line in June, one on the eastern edge and one on the western edge of Range’s southwest acreage position. When combined with the pad announced in the first quarter on the northern portion of the super-rich area, near the planned Harmon Creek processing plant, and the pad announced in the fourth quarter on the southern edge of the wet gas area, the results bolster Range’s confidence in the quality of the 515,000 acreage position in southwest Pennsylvania. Results from these pads are summarized below:
- On the western edge of the super-rich area, a seven well pad was recently completed with an average IP per well of 29.1 Mmcfe per day (73% liquids), and an average lateral length of 10,685 feet with 54 stages.
- On the eastern edge of the dry gas area, a four well pad was recently brought on line with an average IP per well of 30.0 Mmcf per day, and an average lateral length of 11,100 feet with 56 stages. Two of the four wells have lateral lengths in excess of 15,000 feet.
- In the northern portion of Range’s super-rich acreage, Range announced results in the first quarter from two wells brought on line from a four well pad, near the planned Harmon Creek processing plant. An additional two wells were brought on line in the second quarter, with continued outstanding results. The average IP per well for the 4 well pad is 29.5 Mmcfe per day (67% liquids), a 30-day average IP of 19.6 Mmcfe per day and an average lateral length of 9,197 feet with 46 stages.
- On the southern edge of our wet gas area, Range announced a four well pad on the fourth quarter conference call now expected to average over 4.0 Bcfe per 1,000 feet of lateral.
Range continues to improve capital efficiency by drilling longer laterals, lowering costs and increasing recoveries with approximately one-third of 2017 wells expected to be drilled from existing pads. Lateral lengths for wells brought on line in the first half of 2017 averaged approximately 7,500 feet, but are expected to average over 9,500 feet in the second half of the year. Recent development plans have also included the application of technologies such as real-time data streaming, advanced data visualization and machine learning to optimize completions and production. Recent well results demonstrate the potential gains from using this technology to identify opportunities for improved performance.
North Louisiana Division
Production for the division in the second quarter of 2017 averaged 416 net Mmcfe per day, an increase of 5% from the previous quarter. Late in the second quarter, the division brought on line six wells, consisting of three Upper Red wells and three Lower Red wells.
The division continues to focus on Terryville while methodically testing and delineating other areas. Significant progress has been made in lowering the cost to drill and complete a typical 7,500 foot lateral well in Terryville, currently at $7.4 million. As previously discussed, production from the wells brought to sales in early 2017 were below expectations. These included wells that were drilled prior to the acquisition, but not completed. In addition, Range experimented with changes to completion designs and more specifically, fluid intensity, in an attempt to mitigate the impact to offset wells. These wells on average were stimulated with approximately 40% less fluid per foot compared to typical Terryville completions, while utilizing the same proppant per foot. The initial production response in the wells has been below expectations by a similar percentage, with a flatter decline profile, suggesting the wells were under-stimulated. Going forward, Range is planning to return to the larger fluid designs.
In the expansion areas, the two wells previously announced (one to the east and one to the west of Vernon field), continue to perform well. Gas in place estimates for the area are 400 Bcf per square mile and plans are underway to offset each of these expansion wells with another horizontal well. The offset wells are expected to spud in the third quarter with results near year-end. In addition, the Company plans to drill two vertical wells in the area to better determine reservoir properties and identify the optimal target of the six potential intervals.
Guidance – 2017
2017 Production per day Guidance
Range’s third quarter production is expected to be 1,970 Mmcfe per day. Production for the fourth quarter is expected to be 2,170 Mmcfe per day, which is a 17% increase compared to the prior-year quarter. This results in annual production growth of 30%.
The reduction in annual production guidance is primarily driven by early 2017 production results from North Louisiana, as discussed above. In addition, non-recurring timing delays on several well pads in southwest Pennsylvania will impact our full year 2017 production.
3Q 2017 Expense Guidance
| Direct operating expense: | $0.17 - $0.18 per mcfe |
| Transportation, gathering, processing and compression expense: | $1.05 - $1.07 per mcfe |
| Production tax expense: | $0.05 - $0.06 per mcfe |
| Exploration expense: | $15.0 - $18.0 million |
| Unproved property impairment expense: | $20.0 - $23.0 million |
| G&A expense: | $0.21 - $0.23 per mcfe |
| Interest expense: | $0.26 - $0.28 per mcfe |
| DD&A expense: | $0.86 - $0.88 per mcfe |
| Net brokered gas marketing expense: | ~$3.0 million |
2017 Differentials
Based on current market pricing indications, Range expects to receive the following pre-hedge differentials for its production in 2017.
| Natural Gas: | NYMEX minus $0.30 |
| Natural Gas Liquids (including ethane): | 28% - 30% 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 75% of its expected remaining 2017 natural gas production hedged at a weighted average floor price of approximately $3.23 per mcf, and over one Bcf per day of first quarter 2018 production hedged at $3.43. Similarly, Range has hedged approximately 65% of its remaining 2017 projected crude oil production at a floor price of approximately $56 and approximately 65% 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 basis differentials to limit volatility between NYMEX and regional prices, primarily in the Appalachian region. The fair value of the basis hedges as of June 30, 2017 was a loss of $10.5 million.
Conference Call Information
A conference call to review the financial results is scheduled on Wednesday, August 2 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 48401322 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 September 2, 2017.
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 statement of operations. The Company believes that it is important to furnish a table reflecting the details of the various components of each statement of operations 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 Statement of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.
RANGE RESOURCES CORPORATION (NYSE:RRC) is a leading U.S. independent natural gas, NGL and oil 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.
All statements, except for statements of historical fact, made in this release 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), which are incorporated by reference. Range undertakes no obligation to publicly update or revise any forward-looking statements.
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 the Company’s 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.
2017-07
SOURCE: Range Resources Corporation
| RANGE RESOURCES CORPORATION | |||||||||||||||||||||||
| STATEMENTS OF OPERATIONS | |||||||||||||||||||||||
| Based on GAAP reported earnings with additional | |||||||||||||||||||||||
| details of items included in each line in Form 10-Q | |||||||||||||||||||||||
| (Unaudited, in thousands, except per share data) | |||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2017 | 2016 | % | 2017 | 2016 | % | ||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||
| Natural gas, NGLs and oil sales (a) | $ | 506,137 | $ | 224,606 | $ | 1,065,587 | $ | 434,093 | |||||||||||||||
| Derivative fair value income (loss) | 111,195 | (162,798 | ) | 276,752 | (75,890 | ) | |||||||||||||||||
| Brokered natural gas, marketing and other (b) | 56,016 | 39,473 | 107,597 | 74,331 | |||||||||||||||||||
| ARO settlement (loss) (b) | (40 | ) | (6 | ) | (40 | ) | (8 | ) | |||||||||||||||
| Other (b) | (197 | ) | 522 | (130 | ) | 684 | |||||||||||||||||
| Total revenues and other income | 673,111 | 101,797 | 561 | % | 1,449,766 | 433,210 | 235 | % | |||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Direct operating | 30,898 | 19,975 | 58,397 | 43,441 | |||||||||||||||||||
| Direct operating – non-cash stock-based compensation (c) | 522 | 696 | 1,046 | 1,284 | |||||||||||||||||||
| Transportation, gathering, processing and compression | 191,590 | 136,844 | 369,238 | 262,107 | |||||||||||||||||||
| Production and ad valorem taxes | 9,969 | 6,049 | 19,132 | 11,936 | |||||||||||||||||||
| Brokered natural gas and marketing | 55,469 | 40,547 | 108,756 | 76,589 | |||||||||||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation (c) | 388 | 378 | 651 | 894 | |||||||||||||||||||
| Exploration | 13,970 | 6,414 | 21,967 | 10,637 | |||||||||||||||||||
| Exploration – non-cash stock-based compensation (c) | 528 | 371 | 1,035 | 1,061 | |||||||||||||||||||
| Abandonment and impairment of unproved properties | 5,193 | 7,059 | 9,613 | 17,687 | |||||||||||||||||||
| General and administrative | 37,203 | 29,968 | 73,158 | 58,391 | |||||||||||||||||||
| General and administrative – non-cash stock-based compensation (c) | 14,279 | 15,443 | 25,197 | 26,556 | |||||||||||||||||||
| General and administrative – lawsuit settlements | 540 | 403 | 1,163 | 1,324 | |||||||||||||||||||
| General and administrative – bad debt expense | 300 | 250 | 300 | 450 | |||||||||||||||||||
| Memorial merger expenses | — | 2,621 | — | 2,621 | |||||||||||||||||||
| Termination costs | (50 | ) | 5 | 2,400 | 167 | ||||||||||||||||||
| Termination costs – non-cash stock-based compensation (c) | (46 | ) | — | 1,696 | — | ||||||||||||||||||
| Deferred compensation plan (d) | (14,466 | ) | 25,746 | (27,635 | ) | 41,802 | |||||||||||||||||
| Interest expense | 47,926 | 37,758 | 95,027 | 75,497 | |||||||||||||||||||
| Depletion, depreciation and amortization | 152,504 | 122,390 | 302,325 | 242,951 | |||||||||||||||||||
| Impairment of proved properties and other assets | — | — | — | 43,040 | |||||||||||||||||||
| (Gain) loss on sale of assets | (807 | ) | 3,304 | (23,407 | ) | 4,947 | |||||||||||||||||
| Total costs and expenses | 545,910 | 456,221 | 20 | % | 1,040,059 | 923,382 | 13 | % | |||||||||||||||
| Income (loss) before income taxes | 127,201 | (354,424 | ) | 409,707 | (490,172 | ) | |||||||||||||||||
| Income tax expense (benefit): | |||||||||||||||||||||||
| Current | — | — | — | — | |||||||||||||||||||
| Deferred | 57,651 | (129,488 | ) | 170,046 | (171,464 | ) | |||||||||||||||||
| 57,651 | (129,488 | ) | 170,046 | (171,464 | ) | ||||||||||||||||||
| Net income (loss) | $ | 69,550 | $ | (224,936 | ) | $ | 239,661 | $ | (318,708 | ) | |||||||||||||
| Net Income (Loss) Per Common Share: | |||||||||||||||||||||||
| Basic | $ | 0.28 | $ | (1.35 | ) | $ | 0.97 | $ | (1.91 | ) | |||||||||||||
| Diluted | $ | 0.28 | $ | (1.35 | ) | $ | 0.97 | $ | (1.91 | ) | |||||||||||||
| Weighted average common shares outstanding, as reported: | |||||||||||||||||||||||
| Basic | 245,177 | 167,126 | 47 | % | 244,916 | 166,964 | 47 | % | |||||||||||||||
| Diluted | 245,335 | 167,126 | 47 | % | 245,242 | 166,964 | 47 | % | |||||||||||||||
(a) See separate natural gas, NGLs and oil sales information table.
(b) Included in Brokered natural gas, marketing and other revenues in the 10-Q.
(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-Q.
(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) | June 30, | December 31, | |||||
| 2017 | 2016 | ||||||
| (Unaudited) | (Audited) | ||||||
| Assets | |||||||
| Current assets | $ | 280,055 | $ | 268,605 | |||
| Derivative assets | 97,429 | 13,483 | |||||
| Goodwill | 1,646,710 | 1,654,292 | |||||
| Natural gas and oil properties, successful efforts method | 9,505,442 | 9,256,337 | |||||
| Transportation and field assets | 16,160 | 16,873 | |||||
| Other | 75,540 | 72,655 | |||||
| $ | 11,621,336 | $ | 11,282,245 | ||||
| Liabilities and Stockholders’ Equity | |||||||
| Current liabilities | $ | 584,821 | $ | 530,373 | |||
| Asset retirement obligations | 7,271 | 7,271 | |||||
| Derivative liabilities | 4,900 | 165,009 | |||||
| Bank debt | 949,948 | 876,428 | |||||
| Senior notes | 2,850,100 | 2,848,591 | |||||
| Senior subordinated notes | 48,541 | 48,498 | |||||
| Total debt | 3,848,589 | 3,773,517 | |||||
| Deferred tax liability | 1,114,583 | 943,343 | |||||
| Derivative liabilities | 541 | 24,491 | |||||
| Deferred compensation liability | 96,854 | 119,231 | |||||
| Asset retirement obligations and other liabilities | 301,886 | 310,642 | |||||
| Common stock and retained earnings | 5,662,490 | 5,409,577 | |||||
| Common stock held in treasury stock | (599 | ) | (1,209 | ) | |||
| Total stockholders’ equity | 5,661,891 | 5,408,368 | |||||
| $ | 11,621,336 | $ | 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 June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||
| 2017 | 2016 | % | 2017 | 2016 | % | ||||||||||||||||||||
| Total revenues and other income, as reported | $ | 673,111 | $ | 101,797 | 561 | % | $ | 1,449,766 | $ | 433,210 | 235 | % | |||||||||||||
| Adjustment for certain special items: | |||||||||||||||||||||||||
| Total change in fair value related to derivatives prior to settlement (gain) loss | (107,809 | ) | 260,876 | (277,547 | ) | 283,434 | |||||||||||||||||||
| ARO settlement loss | 40 | 6 | 40 | 8 | |||||||||||||||||||||
| Total revenues, as adjusted, non-GAAP | $ | 565,342 | $ | 362,679 | 56 | % | $ | 1,172,259 | $ | 716,652 | 64 | % | |||||||||||||
| RANGE RESOURCES CORPORATION | ||||||||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||||
| (Unaudited in thousands) | ||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||||
| Net income (loss) | $ | 69,550 | $ | (224,936 | ) | $ | 239,661 | $ | (318,708 | ) | ||||||||
| Adjustments to reconcile net cash provided from continuing operations: | ||||||||||||||||||
| Deferred income tax expense (benefit) | 57,651 | (129,488 | ) | 170,046 | (171,464 | ) | ||||||||||||
| Depletion, depreciation, amortization and impairment | 152,504 | 122,390 | 302,325 | 285,991 | ||||||||||||||
| Exploration dry hole costs | 161 | — | 161 | — | ||||||||||||||
| Abandonment and impairment of unproved properties | 5,193 | 7,059 | 9,613 | 17,687 | ||||||||||||||
| Derivative fair value adjustment | (111,195 | ) | 162,798 | (276,752 | ) | 75,890 | ||||||||||||
| Cash settlements on derivative financial instruments that do not qualify for hedge accounting | 3,387 | 98,078 | (794 | ) | 207,544 | |||||||||||||
| Allowance for bad debts | 300 | 250 | 300 | 450 | ||||||||||||||
| Amortization of deferred issuance costs, loss on extinguishment of debt, and other | 1,247 | 1,730 | 2,557 | 3,437 | ||||||||||||||
| Deferred and stock-based compensation | 990 | 42,590 | 1,952 | 71,718 | ||||||||||||||
| (Gain) loss on sale of assets and other | (807 | ) | 3,304 | (23,407 | ) | 4,947 | ||||||||||||
| Changes in working capital: | ||||||||||||||||||
| Accounts receivable | (8,920 | ) | 23,203 | (13,610 | ) | 41,955 | ||||||||||||
| Inventory and other | 848 | 5,167 | 3,716 | 10,500 | ||||||||||||||
| Accounts payable | (5,958 | ) | (31,116 | ) | 18,426 | (19,194 | ) | |||||||||||
| Accrued liabilities and other | 20,515 | 1,387 | (22,866 | ) | (37,552 | ) | ||||||||||||
| Net changes in working capital | 6,485 | (1,359 | ) | (14,334 | ) | (4,291 | ) | |||||||||||
| Net cash provided from operating activities | $ | 185,466 | $ | 82,416 | $ | 411,328 | $ | 173,201 | ||||||||||
| 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 June 30, | Six Months Ended June 30, | |||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||||
| Net cash provided from operating activities, as reported | $ | 185,466 | $ | 82,416 | $ | 411,328 | $ | 173,201 | ||||||||||
| Net changes in working capital | (6,485 | ) | 1,359 | 14,334 | 4,291 | |||||||||||||
| Exploration expense | 13,809 | 6,414 | 21,806 | 10,637 | ||||||||||||||
| Memorial merger expenses | — | 2,621 | — | 2,621 | ||||||||||||||
| Lawsuit settlements | 540 | 403 | 1,163 | 1,324 | ||||||||||||||
| Termination costs | (50 | ) | 5 | 2,400 | 167 | |||||||||||||
| Non-cash compensation adjustment | 801 | 126 | 1,092 | 42 | ||||||||||||||
| Cash flow from operations before changes in working capital – non-GAAP measure | $ | 194,081 | $ | 93,344 | $ | 452,123 | $ | 192,283 | ||||||||||
| ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | ||||||||||||||||||
| (Unaudited, in thousands) | ||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||||
| Basic: | ||||||||||||||||||
| Weighted average shares outstanding | 247,852 | 169,907 | 247,622 | 169,745 | ||||||||||||||
| Stock held by deferred compensation plan | (2,675 | ) | (2,781 | ) | (2,706 | ) | (2,781 | ) | ||||||||||
| Adjusted basic | 245,177 | 167,126 | 244,916 | 166,964 | ||||||||||||||
| Dilutive: | ||||||||||||||||||
| Weighted average shares outstanding | 247,852 | 169,907 | 247,622 | 169,745 | ||||||||||||||
| Dilutive stock options under treasury method | (2,517 | ) | (2,781 | ) | (2,380 | ) | (2,781 | ) | ||||||||||
| Adjusted dilutive | 245,335 | 167,126 | 245,242 | 166,964 | ||||||||||||||
| 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 June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
| 2017 | 2016 | % | 2017 | 2016 | % | |||||||||||||||||||
| Natural gas, NGL and oil sales components: | ||||||||||||||||||||||||
| Natural gas sales | $ | 336,534 | $ | 124,187 | $ | 707,886 | $ | 266,622 | ||||||||||||||||
| NGL sales | 123,784 | 73,456 | 261,847 | 123,618 | ||||||||||||||||||||
| Oil sales | 45,819 | 26,963 | 95,854 | 43,853 | ||||||||||||||||||||
| Total oil and gas sales, as reported | $ | 506,137 | $ | 224,606 | 125 | % | $ | 1,065,587 | $ | 434,093 | 145 | % | ||||||||||||
| Derivative fair value income (loss), as reported: | $ | 111,195 | $ | (162,798 | ) | $ | 276,752 | $ | (75,890 | ) | ||||||||||||||
| Cash settlements on derivative financial instruments – (gain) loss: | ||||||||||||||||||||||||
| Natural gas | (942 | ) | (84,648 | ) | (8,397 | ) | (170,163 | ) | ||||||||||||||||
| NGLs | 3,131 | (6,003 | ) | 17,464 | (16,881 | ) | ||||||||||||||||||
| Crude Oil | (5,575 | ) | (7,427 | ) | (8,272 | ) | (20,500 | ) | ||||||||||||||||
| Total change in fair value related to derivatives prior to settlement, a non-GAAP measure | $ | 107,809 | $ | (260,876 | ) | $ | 277,547 | $ | (283,434 | ) | ||||||||||||||
| Transportation, gathering, processing and compression components: | ||||||||||||||||||||||||
| Natural gas | $ | 129,557 | $ | 96,298 | $ | 251,750 | $ | 188,890 | ||||||||||||||||
| NGLs | 62,033 | 40,546 | 117,488 | 73,217 | ||||||||||||||||||||
| Total transportation, gathering, processing and compression, as reported | $ | 191,590 | $ | 136,844 | $ | 369,238 | $ | 262,107 | ||||||||||||||||
| Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | ||||||||||||||||||||||||
| Natural gas sales | $ | 337,476 | $ | 208,835 | $ | 716,283 | $ | 436,785 | ||||||||||||||||
| NGL sales | 120,653 | 79,459 | 244,383 | 140,499 | ||||||||||||||||||||
| Oil sales | 51,394 | 34,390 | 104,126 | 64,353 | ||||||||||||||||||||
| Total | $ | 509,523 | $ | 322,684 | 58 | % | 1,064,792 | 641,637 | 66 | % | ||||||||||||||
| Production of oil and gas during the periods (a): | ||||||||||||||||||||||||
| Natural gas (mcf) | 119,487,827 | 82,997,371 | 44 | % | 235,744,164 | 167,864,741 | 40 | % | ||||||||||||||||
| NGL (bbl) | 8,524,267 | 6,865,948 | 24 | % | 17,060,995 | 12,840,682 | 33 | % | ||||||||||||||||
| Oil (bbl) | 1,052,784 | 849,538 | 24 | % | 2,118,070 | 1,693,879 | 25 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) | 176,950,133 | 129,290,287 | 37 | % | 350,818,554 | 255,072,107 | 38 | % | ||||||||||||||||
| Production of oil and gas – average per day (a): | ||||||||||||||||||||||||
| Natural gas (mcf) | 1,313,053 | 912,059 | 44 | % | 1,302,454 | 922,334 | 41 | % | ||||||||||||||||
| NGL (bbl) | 93,673 | 75,450 | 24 | % | 94,260 | 70,553 | 34 | % | ||||||||||||||||
| Oil (bbl) | 11,569 | 9,336 | 24 | % | 11,702 | 9,307 | 26 | % | ||||||||||||||||
| Gas equivalent (mcfe) (b) | 1,944,507 | 1,420,772 | 37 | % | 1,938,224 | 1,401,495 | 38 | % | ||||||||||||||||
| Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | ||||||||||||||||||||||||
| Natural gas (mcf) | $ | 2.82 | $ | 1.50 | 88 | % | $ | 3.00 | $ | 1.59 | 89 | % | ||||||||||||
| NGL (bbl) | $ | 14.52 | $ | 10.70 | 36 | % | $ | 15.35 | $ | 9.63 | 59 | % | ||||||||||||
| Oil (bbl) | $ | 43.52 | $ | 31.74 | 37 | % | $ | 45.26 | $ | 25.89 | 75 | % | ||||||||||||
| Gas equivalent (mcfe) (b) | $ | 2.86 | $ | 1.74 | 64 | % | $ | 3.04 | $ | 1.70 | 79 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | ||||||||||||||||||||||||
| Natural gas (mcf) | $ | 2.82 | $ | 2.52 | 12 | % | $ | 3.04 | $ | 2.60 | 17 | % | ||||||||||||
| NGL (bbl) | $ | 14.15 | $ | 11.57 | 22 | % | $ | 14.32 | $ | 10.94 | 31 | % | ||||||||||||
| Oil (bbl) | $ | 48.82 | $ | 40.48 | 21 | % | $ | 49.16 | $ | 37.99 | 29 | % | ||||||||||||
| Gas equivalent (mcfe) (b) | $ | 2.88 | $ | 2.50 | 15 | % | $ | 3.04 | $ | 2.52 | 21 | % | ||||||||||||
| Average prices, including cash-settled hedges and derivatives: (d) | ||||||||||||||||||||||||
| Natural gas (mcf) | $ | 1.74 | $ | 1.36 | 28 | % | $ | 1.97 | $ | 1.48 | 33 | % | ||||||||||||
| NGL (bbl) | $ | 6.88 | $ | 5.67 | 21 | % | $ | 7.44 | $ | 5.24 | 42 | % | ||||||||||||
| Oil (bbl) | $ | 48.82 | $ | 40.48 | 21 | % | $ | 49.16 | $ | 37.99 | 29 | % | ||||||||||||
| Gas equivalent (mcfe) (b) | $ | 1.80 | $ | 1.44 | 25 | % | $ | 1.98 | $ | 1.49 | 33 | % | ||||||||||||
| Transportation, gathering and compression expense per mcfe | $ | 1.08 | $ | 1.06 | 2 | % | $ | 1.05 | $ | 1.03 | 2 | % | ||||||||||||
(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 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 June 30, | Six Months Ended June 30, | |||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| Income (loss) before income taxes, as reported | $ | 127,201 | $ | (354,424 | ) | $ | 409,707 | $ | (490,172 | ) | ||||||
| Adjustment for certain special items: | ||||||||||||||||
| (Gain) loss on sale of assets | (807 | ) | 3,304 | (23,407 | ) | 4,947 | ||||||||||
| Loss (gain) on ARO settlements | 40 | 6 | 40 | 8 | ||||||||||||
| Change in fair value related to derivatives prior to settlement | (107,809 | ) | 260,876 | (277,547 | ) | 283,434 | ||||||||||
| Abandonment and impairment of unproved properties | 5,193 | 7,059 | 9,613 | 17,687 | ||||||||||||
| Impairment of proved property | — | — | — | 43,040 | ||||||||||||
| Memorial merger expenses | — | 2,621 | — | 2,621 | ||||||||||||
| Lawsuit settlements | 540 | 403 | 1,163 | 1,324 | ||||||||||||
| Termination costs | (50 | ) | 5 | 2,400 | 167 | |||||||||||
| Termination costs – non-cash stock-based compensation | (46 | ) | — | 1,696 | — | |||||||||||
| Brokered natural gas and marketing – non-cash stock-based compensation | 388 | 378 | 651 | 894 | ||||||||||||
| Direct operating – non-cash stock-based compensation | 522 | 696 | 1,046 | 1,284 | ||||||||||||
| Exploration expenses – non-cash stock-based compensation | 528 | 371 | 1,035 | 1,061 | ||||||||||||
| General & administrative – non-cash stock-based compensation | 14,279 | 15,443 | 25,197 | 26,556 | ||||||||||||
| Deferred compensation plan – non-cash adjustment | (14,466 | ) | 25,746 | (27,635 | ) | 41,802 | ||||||||||
| Income (loss) before income taxes, as adjusted | 25,513 | (37,516 | ) | 123,959 | (65,347 | ) | ||||||||||
| Income tax expense, as adjusted | ||||||||||||||||
| Current | — | — | — | — | ||||||||||||
| Deferred (a) | 9,622 | (14,269 | ) | 47,250 | (24,966 | ) | ||||||||||
| Net income (loss) excluding certain items, a non-GAAP measure | $ | 15,891 | $ | (23,247 | ) | $ | 76,709 | $ | (40,381 | ) | ||||||
| Non-GAAP income per common share | ||||||||||||||||
| Basic | $ | 0.06 | $ | (0.14 | ) | $ | 0.31 | $ | (0.24 | ) | ||||||
| Diluted | $ | 0.06 | $ | (0.14 | ) | $ | 0.31 | $ | (0.24 | ) | ||||||
| Non-GAAP diluted shares outstanding, if dilutive | 245,335 | 167,621 | 245,242 | 167,098 | ||||||||||||
(a) Deferred taxes for 2017 and 2016 are estimated to be approximately 38%.
| RANGE RESOURCES CORPORATION | |||||||||||
| HEDGING POSITION AS OF JULY 24, 2017 | |||||||||||
| (Unaudited) – | |||||||||||
| Daily Volume | Hedge Price | ||||||||||
| Gas 1 | |||||||||||
| 3Q 2017 Swaps | 841,196 Mmbtu | $3.19 | |||||||||
| 4Q 2017 Swaps | 867,935 Mmbtu | $3.20 | |||||||||
| 1Q 2018 Swaps | 1,020,000 Mmbtu | $3.43 | |||||||||
| 2Q-4Q 2018 Swaps2 | 260,000 Mmbtu | $2.98 | |||||||||
| 3Q 2017 Collars | 122,609 Mmbtu | $3.45 x $4.11 | |||||||||
| 4Q 2017 Collars | 122,609 Mmbtu | $3.45 x $4.11 | |||||||||
| 1Q 2018 Collars | 60,000 Mmbtu | $3.40 x $3.76 | |||||||||
| 3Q 2017 Puts | 185,870 Mmbtu | $3.50 ($0.32) 3 | |||||||||
| 4Q 2017 Puts | 185,870 Mmbtu | $3.50 ($0.32) 3 | |||||||||
| Oil | |||||||||||
| 3Q 2017 Swaps | 8,761 bbls | $56.38 | |||||||||
| 4Q 2017 Swaps | 8,761 bbls | $56.38 | |||||||||
| 2018 Swaps | 5,250 bbls | $53.20 | |||||||||
| 2019 Swaps | 500 bbls | $51.75 | |||||||||
| C2 Ethane | |||||||||||
| 3Q 2017 Swaps | 3,000 bbls | $0.27/gallon | |||||||||
| 4Q 2017 Swaps | 3,000 bbls | $0.27/gallon | |||||||||
| 1H 2018 Swaps | 250 bbls | $0.29/gallon | |||||||||
| C3 Propane | |||||||||||
| 3Q 2017 Swaps | 13,826 bbls | $0.56/gallon | |||||||||
| 4Q 2017 Swaps | 14,076 bbls | $0.56/gallon | |||||||||
| 2018 Swaps | 7,199 bbls | $0.61/gallon | |||||||||
| C4 Normal Butane | |||||||||||
| 3Q 2017 Swaps | 7,750 bbls | $0.74/gallon | |||||||||
| 4Q 2017 Swaps | 8,000 bbls | $0.75/gallon | |||||||||
| 2018 Swaps | 4,250 bbls | $0.81/gallon | |||||||||
| C5 Natural Gasoline | |||||||||||
| 3Q 2017 Swaps | 5,500 bbls | $1.07/gallon | |||||||||
| 4Q 2017 Swaps | 5,500 bbls | $1.07/gallon | |||||||||
| 2018 Swaps | 1,500 bbls | $1.19/gallon | |||||||||
(1) Range has deferred calls at a strike of $3.70 for 2H17. Total volume of 4,300,000 Mmbtu with a deferred premium price of $0.27 paid to Range
(2) Includes swaps of 40,000 Mmbtu per day at $3.05 which could be extended into 2019
(3) Notes deferred premium on puts
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS