Exhibit 99.1
NEWS RELEASE
RANGE ANNOUNCES THIRD QUARTER 2017 RESULTS
FORT WORTH, TEXAS, OCTOBER 24, 2017…RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its third quarter 2017 financial results.
Highlights –
| • | Year to date 2017 GAAP net income was $112 million, or $0.45 per diluted share, compared to a net loss of $361 million, or $2.10 per share in the comparable period of 2016 |
| • | Year to date net cash provided from operating activities (GAAP) was $601 million, compared to $206 million in the comparable period of 2016, an improvement of 192% while year to date cash flow from operations before changes in working capital, (non-GAAP), reached $656 million, compared to $316 million, an improvement of 108% |
| • | Two recently completed Marcellus super-rich pads were brought on line with average per well 24-hour IPs of 41.3 Mmcfe per day, containing 64% liquids, with 20% being condensate |
| • | Record third quarter production totaled 1.99 Bcfe per day, an increase of 32% compared to the prior-year quarter |
| • | Third quarter NGL pre-hedge realized prices improved to $16.93 per barrel versus $11.17 per barrel in the prior-year quarter, a 52% improvement |
| • | Third quarter natural gas price differential including the impact of basis hedges improved to minus ($0.51) per mcf, compared to minus ($0.68) in the prior-year quarter, a 25% improvement |
| • | Third quarter crude oil and condensate realized prices improved to $4.80 per barrel below WTI versus $5.81 per barrel below WTI in the prior-year quarter, a 17% improvement |
Commenting, Jeff Ventura, the Company’s CEO said, “This is an exciting time for Range as we are nearing an inflection point in our Marcellus development and as we continue to improve well results in North Louisiana. In the Marcellus, the last of our natural gas transportation projects are coming on line over the next few months which will allow us to develop our Marcellus position over the long-term while having access to better priced markets. This buildout process has been years in the making and we believe Range’s combination of high-quality assets and infrastructure provide a solid foundation to deliver strong returns for many years.”
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. “Cash margin” as used in this release represents cash revenues related to production less cash expenses related to production, which are comprised of expense categories included in “unit costs” excluding depletion, depreciation and amortization, but including brokered natural gas and marketing. “Cash margin per mcfe” represents cash margin 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.
GAAP revenues for the third quarter of 2017 totaled $482 million, a 17% increase over the prior-year quarter. GAAP net cash provided from operating activities including changes in working capital was $189 million versus $33 million in third quarter 2016 and a GAAP net loss of $128 million ($0.52 per diluted share) versus a loss of $42 million ($0.23 per diluted share) in the prior-year quarter. Third quarter 2017 included $88 million in derivative losses due to increased commodity prices, compared to a $65 million gain in third quarter 2016. Third quarter 2017 also included $43 million in unproved property impairment compared to $6 million in third quarter 2016, as a result of increasing lease expirations due to budgeting constraints, primarily in North Louisiana. Proved property impairment of $64 million was recorded in third quarter 2017 on properties located in Oklahoma and the Texas Panhandle.
Non-GAAP revenues for third quarter 2017 totaled $587 million, a 46% increase compared to third quarter 2016 and cash flow from operations before changes in working capital, a non-GAAP measure, reached $204 million, compared to $123 million in third quarter 2016. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $12 million ($0.05 per diluted share) compared to a loss of $10 million ($0.06 per diluted share) for third quarter 2016.
The Company’s total unit costs were $2.66 per mcfe, 1% lower than third quarter 2016, while cash unit costs were $1.78 per mcfe, 2% higher than the prior-year quarter. General and administrative, interest and depletion, depreciation and amortization expenses per mcfe continued to trend lower. Transportation, gathering, processing and compression expense increased by $0.05 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. Direct operating costs increased by $0.04 per mcfe over the prior-year quarter due to higher workover and well service costs. Production, and ad valorem taxes increased by $0.02 per mcfe due to a one-time production tax adjustment.
Expenses |
| 3Q 2017 (per mcfe) |
| 3Q 2016 (per mcfe) |
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| Increase (Decrease) | |
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Direct operating |
| $ 0.20 |
| $ 0.16 |
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| 25% | |
Transportation, gathering, processing and compression |
| 1.05 |
| 1.00 |
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| 5% | |
Production and ad valorem taxes |
| 0.07 |
| 0.05 |
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| 40% | |
General and administrative |
| 0.20 |
| 0.21 |
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| (5%) | |
Interest expense |
| 0.27 |
| 0.33 |
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| (18%) | |
Total cash unit costs(a) |
| 1.78 |
| 1.75 |
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| 2% | |
Depletion, depreciation and amortization |
| 0.87 |
| 0.95 |
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| (8%) | |
Total unit costs(a) |
| $ 2.66 |
| $ 2.70 |
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| (1%) | |
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(a) Totals may not add due to rounding. |
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Third 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 $2.78 per mcfe, a 27% 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 third quarter 2017 were: natural gas – 1,322 Mmcf per day ($2.48 per mcf), NGLs – 96,661 barrels per day ($16.93 per barrel) and crude oil and condensate – 14,003 barrels per day ($43.34 per barrel). |
| • | The average Company natural gas price differential including the impact of basis hedges for third quarter 2017 improved to minus ($0.51) per mcf, compared to minus ($0.68) in third quarter 2016. The third quarter 2017 average natural gas price, before all hedging settlements, was $2.48 per mcf as compared to $2.11 per mcf in the prior-year quarter. |
2
| • | Crude oil and condensate price realizations, before realized hedges, for the third quarter 2017 improved to $43.34, or $4.80 per barrel below WTI, compared to $39.15, or $5.81 per barrel below WTI in the prior-year quarter. |
Cash Margins
Third quarter cash margins improved to $1.09 per mcfe compared to $0.82 per mcfe in third quarter 2016, an improvement of 33%. Year to date cash margins improved to $1.21 per mcfe, versus $0.77 per mcfe in the comparable period of 2016, an improvement of 57%. See the attached table that reconciles income (loss) before income taxes with cash margins, a non-GAAP measure.
Capital Expenditures
Third quarter 2017 drilling expenditures of $305 million funded the drilling and completion of 35 (33 net) wells. A 97% success rate was achieved. In addition, during the quarter, $7.8 million was incurred on acreage purchases, $3.5 million on gas gathering systems and $5.1 million on seismic expense. Range is on target with its $1.15 billion capital budget for 2017.
Financial Position and Liquidity
At September 30, 2017, Range had total debt outstanding of $4.0 billion, before amortization of debt issuance costs and premium, consisting of $2.9 billion in senior notes, $1.1 billion in bank debt and $49 million in senior subordinated notes. The outstanding bank debt of $1.1 billion combined with $286 million of undrawn letters of credit provides committed liquidity of $628 million.
3
Range has updated its investor presentation. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation – October 24, 2017”.
The table below summarizes quarterly activity and the number of wells expected to be turned in line (TIL) for the remainder of 2017 and total year of 2017:
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| 2017 | ||||
| Wells TIL — 1st and 2nd Quarters | Wells TIL — 3rd Quarter | Wells to be TIL — 4th Quarter | Planned Annual Total Wells to Sales | ||
Super-Rich Area |
| 14 | 11 | 7 | 32 | |
Wet Area |
| 15 | 10 | 15 | 40 | |
Dry- SW |
| 14 | 1 | 24 | 39 | |
Dry- NE |
| 2 | — | — | 2 | |
Total Marcellus |
| 45 | 22 | 46 | 113 | |
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Upper Red |
| 22 | 3 | 9 | 34 | |
Lower Red |
| 8 | — | 5 | 13 | |
Pink |
| 3 | 3 | — | 6 | |
Extension Area |
| — | 1 | 2 | 3 | |
Total N. LA. |
| 33 | 7 | 16 | 56 | |
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Company Total |
| 78 | 29 | 62 | 169 | |
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Appalachia Division
Division production for third quarter 2017 averaged 1.60 net Bcfe per day, a 15% increase over the prior-year quarter. The southwest properties averaged 1.45 net Bcfe per day during the quarter, an 18% increase over the prior-year quarter. The northeast properties averaged 153 net Mmcf per day during the quarter, a 9% decrease over the prior-year quarter. The division brought on line 22 wells in the third quarter, 11 in the super-rich area, 10 in the wet area, and one in the southwest dry area. As shown in the table above, the number of wells brought on line will increase in the fourth quarter when prices are expected to improve and new pipeline infrastructure becomes available.
The division continues to drill longer laterals, thereby improving capital efficiency by lowering well costs per foot and increasing recoveries. Lateral lengths in the third quarter averaged over 11,700 feet compared to an average lateral length of less than 6,171 feet in third quarter 2016. Average lateral lengths of 10,000 feet or greater is the expectation for 2018 as the Company’s goal of holding acreage and capturing resource potential is essentially complete and the focus is now on maximizing operational efficiencies and improving returns. The combination of longer laterals and additional completion efficiencies has allowed Range to lower total well costs on a normalized basis by 25%, as compared to the previous year.
Two recent four well pads were completed in the super-rich area with seven wells turned to sales in the third quarter. Both pads are examples of impressive liquids production in addition to gas. One pad had an average 24-hour IP per well of 41.7 Mmcfe per day consisting of 16.2 Mmcf of gas, 1,089 barrels of condensate and 3,172 barrels of NGLs. The wells were completed with an average lateral length of 9,478 feet with 48 stages. The other pad had an average 24-hour IP of 40.6 Mmcfe per day consisting of 12.7 Mmcf of gas, 1,755 barrels of condensate and 2,904 barrels of NGLs. The wells were completed with an average lateral length of 9,880 feet with 50 stages.
4
Production for the division in the third quarter of 2017 averaged 360 net Mmcfe per day. The division brought seven wells on line during the quarter. The last three wells were previously disclosed at an energy conference in September, as they represent the first wells Range has operated from start to finish. The three wells continue to perform well, with the two Upper Red wells having 30 day rates to sales of 25.8 and 20.7 Mmcfe per day, with lateral lengths of 7,427 feet and 6,827 feet. A Lower Deep Pink well on the same pad averaged 20.2 Mmcfe per day to sales for 30 days. It appears to be the best Pink interval well drilled in the field to date.
Activity in the extension area to the south of Terryville is continuing, building upon the encouraging results previously announced. A well was recently completed in a new fault block south of Terryville and north of Driscoll field. Early production data is promising, with production rates over 3.5 Mmcf per day per 1,000 feet of lateral. Two offset horizontal wells to the east and west of Vernon field are planned with one well currently drilling.
The division expects to bring on line 16 wells in the fourth quarter.
Marketing and Transportation
During the next two quarters, several incremental natural gas transportation projects in southwest Appalachia are expected to commence operations. Once in service, Range’s natural gas transportation portfolio will be largely complete, allowing Marcellus natural gas volumes to be directed toward expanding markets, especially the Gulf Coast where significant incremental natural gas demand is expected over the next several years.
TransCanada’s Rayne/Leach Xpress project and Enbridge’s TETCO Adair Southwest project are both expected to be in service before the end of 2017, and Energy Transfer’s Rover Phase 2 project is expected to be available in early 2018. In combination, these projects will add an additional 900,000 Mmbtu per day to Range’s gross capacity and are expected to improve corporate natural gas differentials to NYMEX minus $0.15 or better during 2018. As a result of these additional transportation commitments, Range is expecting its transportation, gathering, compression and processing expense to increase to ~$1.20 per Mcfe when all three projects are fully in service before trending back down as capacity is fully utilized.
Range is also well-positioned to benefit from the improving NGL macro environment. The Company reported NGL pre-hedge pricing improved to 35% of WTI in the third quarter, compared to 25% of WTI a year ago. This substantial improvement in NGL pricing realizations was led by propane, which achieved multi-year highs in September. As the only producer with propane capacity on Mariner East 1, Range has been able to capture above Mont Belvieu prices by exporting the majority of its propane to international markets since early 2016. As a result of Range’s projects currently in place, and improving NGL market fundamentals, Range expects fourth quarter 2017 pre-hedge NGL differentials to be approximately 35% of WTI. Based on current strip prices, Range anticipates pre-hedge NGL realizations of 30% to 32% of WTI in 2018.
5
2017 Production per day Guidance
Range’s fourth quarter production is expected to be 2,170 Mmcfe per day. This results in annual production growth of 30%, or organic growth of approximately 10%.
4Q 2017 Expense Guidance
Direct operating expense: | $0.18 — $0.20 per mcfe |
Transportation, gathering, processing and compression expense: | $1.05 — $1.07 per mcfe |
Production tax expense: | $0.06 — $0.07 per mcfe |
Exploration expense: | $15.0 — $17.0 million |
Unproved property impairment expense: | $22.0 — $24.0 million |
G&A expense: | $0.21 — $0.23 per mcfe |
Interest expense: | $0.27 — $0.29 per mcfe |
DD&A expense: | $0.86 — $0.88 per mcfe |
Net brokered gas marketing expense: | ~$3.0 million |
Price Differentials
Based on current market pricing indications, Range expects to receive the following pre-hedge differentials for its production in the full year of 2017 and 2018.
| 2017 | 2018 |
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Natural Gas: | NYMEX minus $0.30 | NYMEX minus $0.15 or better |
Natural Gas Liquids (with ethane): | 32% of WTI | 30% — 32% of WTI |
Oil/Condensate: | WTI minus $5.00 to $6.00 | 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 $3.24 per mcf, and over 50% of 2018 production hedged at approximately $3.14. Similarly, Range has hedged approximately 70% of its remaining 2017 projected crude oil production at a floor price of approximately $56.00 and approximately 70% 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 September 30, 2017 was a loss of $4.7 million. Range also hedges propane prices with swap contracts that lock in the differential between Mont Belvieu and international propane indices. The fair value of these contracts was a gain of $1.1 million on September 30, 2017.
Conference Call Information
A conference call to review the financial results is scheduled on Wednesday, October 25 at 9:00 a.m. ET. To participate in the call, please dial 866-900-7525 and provide conference code 95985702 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 November 25, 2017.
6
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.
Cash margin as used in this release represents cash revenues related to production less cash expenses related to production as shown in the table below. Cash margin per mcfe represents cash margin divided by production, and is similar to a unit based gross profit calculation as used in other industries, which can be useful in comparing a measure of gross profitability between time periods. A reconciliation is provided in the table between cash margin and the related GAAP measure of income (loss) before income taxes. On its website, the Company provides additional comparative information on prior periods for cash flow, non-GAAP earnings and cash margin 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.
7
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.
8
2017-07
SOURCE: Range Resources Corporation
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, Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
Josh Stevens, Financial Analyst
817-869-1564
jrstevens@rangeresources.com
Media Contact:
Michael Mackin, Director of External Affairs
724-743-6776
mmackin@rangeresources.com
www.rangeresources.com
9
STATEMENTS OF OPERATIONS |
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Based on GAAP reported earnings with additional |
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details of items included in each line in Form 10-Q |
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(Unaudited, in thousands, except per share data) |
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| Three Months Ended September 30, |
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| Nine Months Ended September 30, |
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| 2017 |
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Revenues and other income: |
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Natural gas, NGLs and oil sales (a) | $ | 507,541 |
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| $ | 304,477 |
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| $ | 1,573,128 |
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| $ | 738,570 |
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Derivative fair value (loss)/income |
| (88,426 | ) |
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| 64,556 |
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| 188,326 |
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| (11,334 | ) |
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Brokered natural gas, marketing and other (b) |
| 61,145 |
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| 44,114 |
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| 168,742 |
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| 118,445 |
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ARO settlement gain (loss) (b) |
| 104 |
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| (6 | ) |
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| 64 |
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| (14 | ) |
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Other (b) |
| 1,868 |
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| 66 |
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| 1,738 |
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| 750 |
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Total revenues and other income |
| 482,232 |
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| 413,207 |
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| 17 | % |
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| 1,931,998 |
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| 846,417 |
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| 128 | % |
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Costs and expenses: |
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Direct operating |
| 36,371 |
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| 21,890 |
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| 94,768 |
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| 65,331 |
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Direct operating – non-cash stock-based compensation (c) |
| 517 |
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| 497 |
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| 1,563 |
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| 1,781 |
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Transportation, gathering, processing and compression |
| 191,645 |
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| 138,764 |
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| 560,883 |
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| 400,871 |
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Production and ad valorem taxes |
| 11,993 |
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| 6,717 |
|
|
|
|
|
|
| 31,125 |
|
|
| 18,653 |
|
|
|
|
|
Brokered natural gas and marketing |
| 59,384 |
|
|
| 44,167 |
|
|
|
|
|
|
| 168,140 |
|
|
| 120,756 |
|
|
|
|
|
Brokered natural gas and marketing — non-cash |
| 389 |
|
|
| 455 |
|
|
|
|
|
|
| 1,040 |
|
|
| 1,349 |
|
|
|
|
|
Exploration |
| 22,206 |
|
|
| 6,335 |
|
|
|
|
|
|
| 44,173 |
|
|
| 16,972 |
|
|
|
|
|
Exploration – non-cash stock-based compensation (c) |
| 561 |
|
|
| 608 |
|
|
|
|
|
|
| 1,596 |
|
|
| 1,669 |
|
|
|
|
|
Abandonment and impairment of unproved properties |
| 42,568 |
|
|
| 6,082 |
|
|
|
|
|
|
| 52,181 |
|
|
| 23,769 |
|
|
|
|
|
General and administrative |
| 36,461 |
|
|
| 29,428 |
|
|
|
|
|
|
| 109,619 |
|
|
| 87,819 |
|
|
|
|
|
General and administrative — non-cash stock-based |
| 9,959 |
|
|
| 11,126 |
|
|
|
|
|
|
| 35,156 |
|
|
| 37,682 |
|
|
|
|
|
General and administrative — lawsuit settlements |
| 5,865 |
|
|
| 120 |
|
|
|
|
|
|
| 7,028 |
|
|
| 1,444 |
|
|
|
|
|
General and administrative — bad debt expense |
| 750 |
|
|
| 350 |
|
|
|
|
|
|
| 1,050 |
|
|
| 800 |
|
|
|
|
|
Memorial merger expenses |
| — |
|
|
| 33,791 |
|
|
|
|
|
|
| — |
|
|
| 36,412 |
|
|
|
|
|
Termination costs |
| (16 | ) |
|
| 136 |
|
|
|
|
|
|
| 2,384 |
|
|
| 303 |
|
|
|
|
|
Termination costs — non-cash stock-based compensation (c) |
| (31 | ) |
|
| — |
|
|
|
|
|
|
| 1,665 |
|
|
| — |
|
|
|
|
|
Deferred compensation plan (d) |
| (9,203 | ) |
|
| (11,636 | ) |
|
|
|
|
|
| (36,838 | ) |
|
| 30,166 |
|
|
|
|
|
Interest expense |
| 49,179 |
|
|
| 45,967 |
|
|
|
|
|
|
| 144,206 |
|
|
| 121,464 |
|
|
|
|
|
Depletion, depreciation and amortization |
| 159,749 |
|
|
| 131,489 |
|
|
|
|
|
|
| 462,074 |
|
|
| 374,440 |
|
|
|
|
|
Impairment of proved properties and other assets |
| 63,679 |
|
|
| — |
|
|
|
|
|
|
| 63,679 |
|
|
| 43,040 |
|
|
|
|
|
(Gain) loss on sale of assets |
| (102 | ) |
|
| 2,597 |
|
|
|
|
|
|
| (23,509 | ) |
|
| 7,544 |
|
|
|
|
|
Total costs and expenses |
| 681,924 |
|
|
| 468,883 |
|
|
| 45 | % |
|
| 1,721,983 |
|
|
| 1,392,265 |
|
|
| 24 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes |
| (199,692 | ) |
|
| (55,676 | ) |
|
| -259 | % |
|
| 210,015 |
|
|
| (545,848 | ) |
|
| 138 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (benefit) expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
| — |
|
|
| — |
|
|
|
|
|
|
| — |
|
|
| — |
|
| �� |
|
|
Deferred |
| (71,992 | ) |
|
| (13,705 | ) |
|
|
|
|
|
| 98,054 |
|
|
| (185,169 | ) |
|
|
|
|
|
| (71,992 | ) |
|
| (13,705 | ) |
|
|
|
|
|
| 98,054 |
|
|
| (185,169 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income | $ | (127,700 | ) |
| $ | (41,971 | ) |
|
| -204 | % |
| $ | 111,961 |
|
| $ | (360,679 | ) |
|
| 131 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income Per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic | $ | (0.52 | ) |
| $ | (0.23 | ) |
|
|
|
|
| $ | 0.45 |
|
| $ | (2.10 | ) |
|
|
|
|
Diluted | $ | (0.52 | ) |
| $ | (0.23 | ) |
|
|
|
|
| $ | 0.45 |
|
| $ | (2.10 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding, as reported: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| 245,244 |
|
|
| 180,683 |
|
|
| 36 | % |
|
| 245,027 |
|
|
| 171,571 |
|
|
| 43 | % |
Diluted |
| 245,244 |
|
|
| 180,683 |
|
|
| 36 | % |
|
| 245,280 |
|
|
| 171,571 |
|
|
| 43 | % |
(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.
10
RANGE RESOURCES CORPORATION
BALANCE SHEETS |
|
|
|
|
|
|
|
(In thousands) |
| September 30, |
|
|
| December 31, |
|
|
| 2017 |
|
|
| 2016 |
|
|
| (Unaudited) |
|
|
| (Audited) |
|
Assets |
|
|
|
|
|
|
|
Current assets | $ | 307,074 |
|
| $ | 268,605 |
|
Derivative assets |
| 30,688 |
|
|
| 13,483 |
|
Goodwill |
| 1,641,197 |
|
|
| 1,654,292 |
|
Natural gas and oil properties, successful efforts method |
| 9,568,776 |
|
|
| 9,256,337 |
|
Transportation and field assets |
| 15,604 |
|
|
| 16,873 |
|
Other |
| 74,400 |
|
|
| 72,655 |
|
| $ | 11,637,739 |
|
| $ | 11,282,245 |
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders’ Equity |
|
|
|
|
|
|
|
Current liabilities | $ | 631,562 |
|
| $ | 530,373 |
|
Asset retirement obligations |
| 7,271 |
|
|
| 7,271 |
|
Derivative liabilities |
| 32,533 |
|
|
| 165,009 |
|
|
|
|
|
|
|
|
|
Bank debt |
| 1,082,708 |
|
|
| 876,428 |
|
Senior notes |
| 2,850,692 |
|
|
| 2,848,591 |
|
Senior subordinated notes |
| 48,562 |
|
|
| 48,498 |
|
Total debt |
| 3,981,962 |
|
|
| 3,773,517 |
|
|
|
|
|
|
|
|
|
Deferred tax liability |
| 1,042,889 |
|
|
| 943,343 |
|
Derivative liabilities |
| 16,292 |
|
|
| 24,491 |
|
Deferred compensation liability |
| 91,014 |
|
|
| 119,231 |
|
Asset retirement obligations and other liabilities |
| 296,736 |
|
|
| 310,642 |
|
|
|
|
|
|
|
|
|
Common stock and retained earnings |
| 5,538,079 |
|
|
| 5,409,577 |
|
Common stock held in treasury stock |
| (599 | ) |
|
| (1,209 | ) |
Total stockholders’ equity |
| 5,537,480 |
|
|
| 5,408,368 |
|
| $ | 11,637,739 |
|
| $ | 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 September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
| % |
|
|
| 2017 |
|
|
| 2016 |
|
|
| % |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Total revenues and other income, as reported | $ | 482,232 |
|
| $ | 413,207 |
|
|
| 17 | % |
| $ | 1,931,998 |
|
| $ | 846,417 |
|
|
| 128 | % | ||
Adjustment for certain special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Total change in fair value related to derivatives |
| 105,283 |
|
|
| (11,443 | ) |
|
|
|
|
|
| (172,264 | ) |
|
| 271,991 |
|
|
|
|
| ||
ARO settlement (gain) loss |
| (104 | ) |
|
| 6 |
|
|
|
|
|
|
| (64 | ) |
|
| 14 |
|
|
|
|
| ||
Total revenues, as adjusted, non-GAAP | $ | 587,411 |
|
| $ | 401,770 |
|
|
| 46 | % |
| $ | 1,759,670 |
|
| $ | 1,118,422 |
|
|
| 57 | % | ||
11
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
(Unaudited in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
| 2017 |
|
|
| 2016 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Net (loss) income | $ | (127,700 | ) |
| $ | (41,971 | ) |
| $ | 111,961 |
|
| $ | (360,679 | ) | ||
Adjustments to reconcile net cash provided from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Deferred income tax (benefit) expense |
| (71,992 | ) |
|
| (13,705 | ) |
|
| 98,054 |
|
|
| (185,169 | ) | ||
Depletion, depreciation, amortization and impairment |
| 223,428 |
|
|
| 131,489 |
|
|
| 525,753 |
|
|
| 417,480 |
| ||
Exploration dry hole costs |
| 9,005 |
|
|
| 2 |
|
|
| 9,166 |
|
|
| 2 |
| ||
Abandonment and impairment of unproved properties |
| 42,568 |
|
|
| 6,082 |
|
|
| 52,181 |
|
|
| 23,769 |
| ||
Derivative fair value loss (income) |
| 88,426 |
|
|
| (64,556 | ) |
|
| (188,326 | ) |
|
| 11,334 |
| ||
Cash settlements on derivative financial instruments |
| 16,856 |
|
|
| 53,113 |
|
|
| 16,062 |
|
|
| 260,657 |
| ||
Allowance for bad debts |
| 750 |
|
|
| 350 |
|
|
| 1,050 |
|
|
| 800 |
| ||
Amortization of deferred issuance costs, loss on extinguishment of debt, and other |
| 1,627 |
|
|
| 1,946 |
|
|
| 4,184 |
|
|
| 5,383 |
| ||
Deferred and stock-based compensation |
| 1,985 |
|
|
| 971 |
|
|
| 3,937 |
|
|
| 72,689 |
| ||
(Gain) loss on sale of assets and other |
| (102 | ) |
|
| 2,597 |
|
|
| (23,509 | ) |
|
| 7,544 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Changes in working capital: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Accounts receivable |
| (26,084 | ) |
|
| (9,970 | ) |
|
| (39,694 | ) |
|
| 31,985 |
| ||
Inventory and other |
| (5,220 | ) |
|
| (11,276 | ) |
|
| (1,504 | ) |
|
| (776 | ) | ||
Accounts payable |
| 26,289 |
|
|
| (22,074 | ) |
|
| 44,715 |
|
|
| (41,268 | ) | ||
Accrued liabilities and other |
| 9,368 |
|
|
| (362 | ) |
|
| (13,498 | ) |
|
| (37,914 | ) | ||
Net changes in working capital |
| 4,353 |
|
|
| (43,682 | ) |
|
| (9,981 | ) |
|
| (47,973 | ) | ||
Net cash provided from operating activities | $ | 189,204 |
|
| $ | 32,636 |
|
| $ | 600,532 |
|
| $ | 205,837 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
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 September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
| 2017 |
|
|
| 2016 |
| ||
Net cash provided from operating activities, as reported | $ | 189,204 |
|
| $ | 32,636 |
|
| $ | 600,532 |
|
| $ | 205,837 |
| ||
Net changes in working capital |
| (4,353 | ) |
|
| 43,682 |
|
|
| 9,981 |
|
|
| 47,973 |
| ||
Exploration expense |
| 13,200 |
|
|
| 6,333 |
|
|
| 35,006 |
|
|
| 16,970 |
| ||
Memorial merger expenses |
| — |
|
|
| 33,791 |
|
|
| — |
|
|
| 36,412 |
| ||
Lawsuit settlements |
| 5,865 |
|
|
| 120 |
|
|
| 7,028 |
|
|
| 1,444 |
| ||
Cash paid to exchange senior subordinated notes |
| — |
|
|
| 6,600 |
|
|
| — |
|
|
| 6,600 |
| ||
Termination costs |
| (16 | ) |
|
| 136 |
|
|
| 2,384 |
|
|
| 303 |
| ||
Non-cash compensation adjustment |
| 291 |
|
|
| (79 | ) |
|
| 1,383 |
|
|
| (37 | ) | ||
Cash flow from operations before changes in working capital — non-GAAP measure | $ | 204,191 |
|
| $ | 123,219 |
|
| $ | 656,314 |
|
| $ | 315,502 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
(Unaudited, in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
| 2017 |
|
|
| 2016 |
| ||
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Weighted average shares outstanding |
| 248,133 |
|
|
| 183,491 |
|
|
| 247,794 |
|
|
| 174,361 |
| ||
Stock held by deferred compensation plan |
| (2,889 | ) |
|
| (2,808 | ) |
|
| (2,767 | ) |
|
| (2,790 | ) | ||
Adjusted basic |
| 245,244 |
|
|
| 180,683 |
|
|
| 245,027 |
|
|
| 171,571 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Dilutive: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Weighted average shares outstanding |
| 248,133 |
|
|
| 183,491 |
|
|
| 247,794 |
|
|
| 174,361 |
| ||
Dilutive stock options under treasury method |
| (2,889 | ) |
|
| (2,808 | ) |
|
| (2,514 | ) |
|
| (2,790 | ) | ||
Adjusted dilutive |
| 245,244 |
|
|
| 180,683 |
|
|
| 245,280 |
|
|
| 171,571 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
12
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 September 30, |
|
| Nine Months Ended September 30, |
| |||||||||||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
| % |
|
|
| 2017 |
|
|
| 2016 |
|
|
| % |
| |
Natural gas, NGL and oil sales components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas sales | $ | 301,114 |
|
| $ | 197,476 |
|
|
|
|
|
| $ | 1,009,000 |
|
| $ | 464,098 |
|
|
|
|
| |
NGL sales |
| 150,593 |
|
|
| 75,259 |
|
|
|
|
|
|
| 412,440 |
|
|
| 198,877 |
|
|
|
|
| |
Oil sales |
| 55,834 |
|
|
| 31,742 |
|
|
|
|
|
|
| 151,688 |
|
|
| 75,595 |
|
|
|
|
| |
Total oil and gas sales, as reported | $ | 507,541 |
|
| $ | 304,477 |
|
|
| 67 | % |
| $ | 1,573,128 |
|
| $ | 738,570 |
|
|
| 113 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Derivative fair value income (loss), as reported: | $ | (88,426 | ) |
| $ | 64,556 |
|
|
|
|
|
| $ | 188,326 |
|
| $ | (11,334 | ) |
|
|
|
| |
Cash settlements on derivative financial instruments – (gain) loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas |
| (26,250 | ) |
|
| (35,822 | ) |
|
|
|
|
|
| (34,647 | ) |
|
| (205,985 | ) |
|
|
|
| |
NGLs |
| 15,995 |
|
|
| (8,514 | ) |
|
|
|
|
|
| 33,459 |
|
|
| (25,395 | ) |
|
|
|
| |
Crude Oil |
| (6,602 | ) |
|
| (8,777 | ) |
|
|
|
|
|
| (14,874 | ) |
|
| (29,277 | ) |
|
|
|
| |
Total change in fair value related to derivatives prior to settlement, a | $ | (105,283 | ) |
| $ | 11,443 |
|
|
|
|
|
| $ | 172,264 |
|
| $ | (271,991 | ) |
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Transportation, gathering, processing and compression components: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas | $ | 133,019 |
|
| $ | 99,465 |
|
|
|
|
|
| $ | 384,769 |
|
| $ | 288,355 |
|
|
|
|
| |
NGLs |
| 58,626 |
|
|
| 39,299 |
|
|
|
|
|
|
| 176,114 |
|
|
| 112,516 |
|
|
|
|
| |
Total transportation, gathering, processing and compression, as reported | $ | 191,645 |
|
| $ | 138,764 |
|
|
|
|
|
| $ | 560,883 |
|
| $ | 400,871 |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas, NGL and oil sales, including cash-settled derivatives: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas sales | $ | 327,364 |
|
| $ | 233,298 |
|
|
|
|
|
| $ | 1,043,647 |
|
| $ | 670,083 |
|
|
|
|
| |
NGL sales |
| 134,598 |
|
|
| 83,773 |
|
|
|
|
|
|
| 378,981 |
|
|
| 224,272 |
|
|
|
|
| |
Oil sales |
| 62,436 |
|
|
| 40,519 |
|
|
|
|
|
|
| 166,562 |
|
|
| 104,872 |
|
|
|
|
| |
Total | $ | 524,398 |
|
| $ | 357,590 |
|
|
| 47 | % |
|
| 1,589,190 |
|
|
| 999,227 |
|
|
| 59 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Production of oil and gas during the periods (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas (mcf) |
| 121,644,949 |
|
|
| 93,466,385 |
|
|
| 30 | % |
|
| 357,389,113 |
|
|
| 261,331,126 |
|
|
| 37 | % | |
NGL (bbl) |
| 8,892,778 |
|
|
| 6,739,161 |
|
|
| 32 | % |
|
| 25,953,773 |
|
|
| 19,579,843 |
|
|
| 33 | % | |
Oil (bbl) |
| 1,288,303 |
|
|
| 810,878 |
|
|
| 59 | % |
|
| 3,406,373 |
|
|
| 2,504,757 |
|
|
| 36 | % | |
Gas equivalent (mcfe) (b) |
| 182,731,435 |
|
|
| 138,766,619 |
|
|
| 32 | % |
|
| 533,549,989 |
|
|
| 393,838,726 |
|
|
| 35 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Production of oil and gas – average per day (a): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas (mcf) |
| 1,322,228 |
|
|
| 1,015,939 |
|
|
| 30 | % |
|
| 1,309,118 |
|
|
| 953,763 |
|
|
| 37 | % | |
NGL (bbl) |
| 96,661 |
|
|
| 73,252 |
|
|
| 32 | % |
|
| 95,069 |
|
|
| 71,459 |
|
|
| 33 | % | |
Oil (bbl) |
| 14,003 |
|
|
| 8,814 |
|
|
| 59 | % |
|
| 12,478 |
|
|
| 9,141 |
|
|
| 36 | % | |
Gas equivalent (mcfe) (b) |
| 1,986,211 |
|
|
| 1,508,333 |
|
|
| 32 | % |
|
| 1,954,396 |
|
|
| 1,437,368 |
|
|
| 36 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average prices, including cash-settled hedges before third party transportation costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas (mcf) | $ | 2.48 |
|
| $ | 2.11 |
|
|
| 17 | % |
| $ | 2.82 |
|
| $ | 1.78 |
|
|
| 59 | % | |
NGL (bbl) | $ | 16.93 |
|
| $ | 11.17 |
|
|
| 52 | % |
| $ | 15.89 |
|
| $ | 10.16 |
|
|
| 56 | % | |
Oil (bbl) | $ | 43.34 |
|
| $ | 39.15 |
|
|
| 11 | % |
| $ | 44.53 |
|
| $ | 30.18 |
|
|
| 48 | % | |
Gas equivalent (mcfe) (b) | $ | 2.78 |
|
| $ | 2.19 |
|
|
| 27 | % |
| $ | 2.95 |
|
| $ | 1.88 |
|
|
| 57 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average prices, including cash-settled hedges and derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas (mcf) | $ | 2.69 |
|
| $ | 2.50 |
|
|
| 8 | % |
| $ | 2.92 |
|
| $ | 2.56 |
|
|
| 14 | % | |
NGL (bbl) | $ | 15.14 |
|
| $ | 12.43 |
|
|
| 22 | % |
| $ | 14.60 |
|
| $ | 11.45 |
|
|
| 27 | % | |
Oil (bbl) | $ | 48.46 |
|
| $ | 49.97 |
|
|
| -3 | % |
| $ | 48.90 |
|
| $ | 41.87 |
|
|
| 17 | % | |
Gas equivalent (mcfe) (b) | $ | 2.87 |
|
| $ | 2.58 |
|
|
| 11 | % |
| $ | 2.98 |
|
| $ | 2.54 |
|
|
| 17 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average prices, including cash-settled hedges and derivatives: (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas (mcf) | $ | 1.60 |
|
| $ | 1.43 |
|
|
| 12 | % |
| $ | 1.84 |
|
| $ | 1.46 |
|
|
| 26 | % | |
NGL (bbl) | $ | 8.54 |
|
| $ | 6.60 |
|
|
| 29 | % |
| $ | 7.82 |
|
| $ | 5.71 |
|
|
| 37 | % | |
Oil (bbl) | $ | 48.46 |
|
| $ | 49.97 |
|
|
| -3 | % |
| $ | 48.90 |
|
| $ | 41.87 |
|
|
| 17 | % | |
Gas equivalent (mcfe) (b) | $ | 1.82 |
|
| $ | 1.58 |
|
|
| 15 | % |
| $ | 1.93 |
|
| $ | 1.52 |
|
|
| 27 | % | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Transportation, gathering and compression expense per mcfe | $ | 1.05 |
|
| $ | 1.00 |
|
|
| 5 | % |
| $ | 1.05 |
|
| $ | 1.02 |
|
|
| 3 | % | |
(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.
13
RECONCILIATION OF NET INCOME (LOSS), AND ADJUSTED EARNINGS PER SHARE EXCLUDING CERTAIN ITEMS, a non-GAAP measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Three Months Ended September 30, |
|
|
| Nine Months Ended September 30, |
|
| ||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
|
| 2017 |
|
|
| 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income, as reported
| $ | (127,700 | ) |
| $ | (41,971 | ) |
|
| $ | 111,961 |
|
| $ | (360,679 | ) |
|
Adjustment for certain special items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on sale of assets |
| (102 | ) |
|
| 2,597 |
|
|
|
| (23,509 | ) |
|
| 7,544 |
|
|
Loss (gain) on ARO settlements |
| (104 | ) |
|
| 6 |
|
|
|
| (64 | ) |
|
| 14 |
|
|
Change in fair value related to derivatives prior to settlement |
| 105,283 |
|
|
| (11,443 | ) |
|
|
| (172,264 | ) |
|
| 271,991 |
|
|
Impairment of proved property |
| 63,679 |
|
|
| — |
|
|
|
| 63,679 |
|
|
| 43,040 |
|
|
Abandonment and impairment of unproved properties |
| 42,568 |
|
|
| 6,082 |
|
|
|
| 52,181 |
|
|
| 23,769 |
|
|
MRD merger expenses |
| — |
|
|
| 33,791 |
|
|
|
| — |
|
|
| 36,412 |
|
|
Fees paid to exchange senior subordinated notes |
| — |
|
|
| 6,600 |
|
|
|
| — |
|
|
| 6,600 |
|
|
Lawsuit settlements |
| 5,865 |
|
|
| 120 |
|
|
|
| 7,028 |
|
|
| 1,444 |
|
|
Termination costs |
| (16 | ) |
|
| 136 |
|
|
|
| 2,384 |
|
|
| 303 |
|
|
Non-cash stock-based compensation |
| 11,395 |
|
|
| 12,686 |
|
|
|
| 41,020 |
|
|
| 42,481 |
|
|
Deferred compensation plan |
| (9,203 | ) |
|
| (11,636 | ) |
|
|
| (36,838 | ) |
|
| 30,166 |
|
|
Tax impact |
| (80,034 | ) |
|
| (7,338 | ) |
|
|
| 42,762 |
|
|
| (153,836 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) excluding certain items, a non-GAAP measure | $ | 11,631 |
|
| $ | (10,370 | ) |
|
| $ | 88,340 |
|
| $ | (50,751 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per diluted share, as reported
| $ | (0.52 | ) |
| $ | (0.23 | ) |
|
| $ | 0.45 |
|
| $ | (2.10 | ) |
|
Adjustment for certain special items per diluted share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on sale of assets |
| — |
|
|
| 0.01 |
|
|
|
| (0.10 | ) |
|
| 0.04 |
|
|
Change in fair value related to derivatives prior to settlement |
| 0.43 |
|
|
| (0.06 | ) |
|
|
| (0.70 | ) |
|
| 1.59 |
|
|
Impairment of proved property |
| 0.26 |
|
|
| — |
|
|
|
| 0.26 |
|
|
| 0.25 |
|
|
Abandonment and impairment of unproved properties |
| 0.17 |
|
|
| 0.03 |
|
|
|
| 0.21 |
|
|
| 0.14 |
|
|
MRD merger expenses |
| — |
|
|
| 0.19 |
|
|
|
| — |
|
|
| 0.21 |
|
|
Fees paid to exchange senior subordinated notes |
| — |
|
|
| 0.04 |
|
|
|
| — |
|
|
| 0.04 |
|
|
Lawsuit settlements |
| 0.02 |
|
|
| — |
|
|
|
| 0.03 |
|
|
| 0.01 |
|
|
Termination costs |
| — |
|
|
| — |
|
|
|
| 0.01 |
|
|
| — |
|
|
Non-cash stock-based compensation |
| 0.05 |
|
|
| 0.07 |
|
|
|
| 0.17 |
|
|
| 0.25 |
|
|
Deferred compensation plan |
| (0.04 | ) |
|
| (0.06 | ) |
|
|
| (0.15 | ) |
|
| 0.18 |
|
|
Adjustment for rounding differences |
| 0.01 |
|
|
| (0.01 | ) |
|
|
| 0.01 |
|
|
| (0.01 | ) |
|
Tax impact |
| (0.33 | ) |
|
| (0.04 | ) |
|
|
| 0.17 |
|
|
| (0.90 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per diluted share, excluding certain items, a non-GAAP measure | $ | 0.05 |
|
| $ | (0.06 | ) |
|
| $ | 0.36 |
|
| $ | (0.30 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted income (loss) per share, a non-GAAP measure: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic | $ | 0.05 |
|
| $ | (0.06 | ) |
|
| $ | 0.36 |
|
| $ | (0.30 | ) |
|
Diluted | $ | 0.05 |
|
| $ | (0.06 | ) |
|
| $ | 0.36 |
|
| $ | (0.30 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
RECONCILIATION OF CASH MARGIN PER MCFE, a non-GAAP measure |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in thousands, except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Three Months Ended September 30, |
|
|
| Nine Months Ended September 30, |
|
| ||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
|
| 2017 |
|
|
| 2016 |
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGL and oil sales, as reported | $ | 507,541 |
|
| $ | 304,477 |
|
|
| $ | 1,573,128 |
|
| $ | 738,570 |
|
|
Derivative fair value income (loss), as reported |
| (88,426 | ) |
|
| 64,556 |
|
|
|
| 188,326 |
|
|
| (11,334 | ) |
|
Less non-cash fair value (gain) loss |
| 105,283 |
|
|
| (11,443 | ) |
|
|
| (172,264 | ) |
|
| 271,991 |
|
|
Brokered natural gas and marketing and other, as reported |
| 63,117 |
|
|
| 44,174 |
|
|
|
| 170,544 |
|
|
| 119,181 |
|
|
Less ARO settlement and other (gains) losses |
| (1,972 | ) |
|
| (60 | ) |
|
|
| (1,802 | ) |
|
| (736 | ) |
|
Cash revenue applicable to production |
| 585,543 |
|
|
| 401,704 |
|
|
|
| 1,757,932 |
|
|
| 1,117,672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating, as reported |
| 36,888 |
|
|
| 22,387 |
|
|
|
| 96,331 |
|
|
| 67,112 |
|
|
Less direct operating stock-based compensation |
| (517 | ) |
|
| (497 | ) |
|
|
| (1,563 | ) |
|
| (1,781 | ) |
|
Transportation, gathering and compression, as reported |
| 191,645 |
|
|
| 138,764 |
|
|
|
| 560,883 |
|
|
| 400,871 |
|
|
Production and ad valorem taxes, as reported |
| 11,993 |
|
|
| 6,717 |
|
|
|
| 31,125 |
|
|
| 18,653 |
|
|
Brokered natural gas and marketing, as reported |
| 59,773 |
|
|
| 44,622 |
|
|
|
| 169,180 |
|
|
| 122,105 |
|
|
Less brokered natural gas and marketing stock-based compensation |
| (389 | ) |
|
| (455 | ) |
|
|
| (1,040 | ) |
|
| (1,349 | ) |
|
General and administrative, as reported |
| 53,035 |
|
|
| 41,024 |
|
|
|
| 152,853 |
|
|
| 127,745 |
|
|
Less G&A stock-based compensation |
| (9,959 | ) |
|
| (11,126 | ) |
|
|
| (35,156 | ) |
|
| (37,682 | ) |
|
Less lawsuit settlements |
| (5,865 | ) |
|
| (120 | ) |
|
|
| (7,028 | ) |
|
| (1,444 | ) |
|
Interest expense, as reported |
| 49,179 |
|
|
| 45,967 |
|
|
|
| 144,206 |
|
|
| 121,464 |
|
|
Cash expenses |
| 385,783 |
|
|
| 287,283 |
|
|
|
| 1,109,791 |
|
|
| 815,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash margin, a non-GAAP measure | $ | 199,760 |
|
| $ | 114,421 |
|
|
| $ | 648,141 |
|
| $ | 301,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mmcfe produced during period |
| 182,731 |
|
|
| 138,767 |
|
|
|
| 533,550 |
|
|
| 393,839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash margin per mcfe | $ | 1.09 |
|
| $ | 0.82 |
|
|
| $ | 1.21 |
|
| $ | 0.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RECONCILIATION OF INCOME (LOSS) BEFORE INCOME TAXES TO CASH MARGIN |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited, in thousands, except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Three Months Ended September 30, |
|
|
| Nine Months Ended September 30, |
|
| ||||||||||
|
| 2017 |
|
|
| 2016 |
|
|
|
| 2017 |
|
|
| 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes, as reported | $ | (199,692 | ) |
| $ | (55,676 | ) |
|
| $ | 210,015 |
|
| $ | (545,848 | ) |
|
Adjustments to reconcile (loss) income before income taxes to cash margin: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ARO settlements and other (gains) losses |
| (1,972 | ) |
|
| (60 | ) |
|
|
| (1,802 | ) |
|
| (736 | ) |
|
Derivative fair value (income) loss |
| 88,426 |
|
|
| (64,556 | ) |
|
|
| (188,326 | ) |
|
| 11,334 |
|
|
Net cash receipts on derivative settlements |
| 16,857 |
|
|
| 53,113 |
|
|
|
| 16,062 |
|
|
| 260,657 |
|
|
Exploration expense |
| 22,206 |
|
|
| 6,335 |
|
|
|
| 44,173 |
|
|
| 16,972 |
|
|
Lawsuit settlements |
| 5,865 |
|
|
| 120 |
|
|
|
| 7,028 |
|
|
| 1,444 |
|
|
MRD merger expenses |
| — |
|
|
| 33,791 |
|
|
|
| — |
|
|
| 36,412 |
|
|
Termination costs |
| (16 | ) |
|
| 136 |
|
|
|
| 2,384 |
|
|
| 303 |
|
|
Deferred compensation plan |
| (9,203 | ) |
|
| (11,636 | ) |
|
|
| (36,838 | ) |
|
| 30,166 |
|
|
Stock-based compensation (direct operating, brokered natural gas and marketing, general and administrative and termination costs) |
| 11,395 |
|
|
| 12,686 |
|
|
|
| 41,020 |
|
|
| 42,481 |
|
|
Depletion, depreciation and amortization |
| 159,749 |
|
|
| 131,489 |
|
|
|
| 462,074 |
|
|
| 374,440 |
|
|
(Gain) loss on sale of assets |
| (102 | ) |
|
| 2,597 |
|
|
|
| (23,509 | ) |
|
| 7,544 |
|
|
Impairment of proved property and other assets |
| 63,679 |
|
|
| — |
|
|
|
| 63,679 |
|
|
| 43,040 |
|
|
Abandonment and impairment of unproved properties |
| 42,568 |
|
|
| 6,082 |
|
|
|
| 52,181 |
|
|
| 23,769 |
|
|
Cash margin, a non-GAAP measure | $ | 199,760 |
|
| $ | 114,421 |
|
|
| $ | 648,141 |
|
| $ | 301,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
HEDGING POSITION AS OF OCTOBER 23, 2017
(Unaudited) –
|
|
|
|
| Daily Volume |
|
|
| Hedge Price |
|
| Gas 1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 4Q 2017 Swaps |
|
|
| 867,935 Mmbtu |
|
|
| $3.20 |
|
| 1Q 2018 Swaps |
|
|
| 1,020,000 Mmbtu |
|
|
| $3.43 |
|
| 2Q-4Q 2018 Swaps2 |
|
|
| 790,000 Mmbtu |
|
|
| $3.01 |
|
| 2019 Swaps2 |
|
|
| 72,329 Mmbtu |
|
|
| $3.00 |
|
|
|
|
|
|
|
|
|
|
|
|
| 4Q 2017 Collars |
|
|
| 122,609 Mmbtu |
|
|
| $3.45 x $4.11 |
|
| 1Q 2018 Collars |
|
|
| 60,000 Mmbtu |
|
|
| $3.40 x $3.76 |
|
|
|
|
|
|
|
|
|
|
|
|
| 4Q 2017 Puts |
|
|
| 185,870 Mmbtu |
|
|
| $3.50 ($0.32) 3 |
|
|
|
|
|
|
|
|
|
|
|
|
| Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 4Q 2017 Swaps |
|
|
| 9,511 bbls |
|
|
| $56.03 |
|
| 2018 Swaps |
|
|
| 6,750 bbls |
|
|
| $52.89 |
|
|
|
|
|
|
|
|
|
|
|
|
| 2019 Swaps |
|
|
| 1,000 bbls |
|
|
| $51.50 |
|
|
|
|
|
|
|
|
|
|
|
|
| C2 Ethane |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 4Q 2017 Swaps |
|
|
| 3,000 bbls |
|
|
| $0.27/gallon |
|
| 1H 2018 Swaps |
|
|
| 250 bbls |
|
|
| $0.29/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
| C3 Propane 4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 4Q 2017 Swaps |
|
|
| 17,576 bbls |
|
|
| $0.60/gallon |
|
| 1Q 2018 Swaps |
|
|
| 12,000 bbls |
|
|
| $0.65/gallon |
|
| 2Q-4Q 2018 Swaps |
|
|
| 7,932 bbls |
|
|
| $0.61/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
| C4 Normal Butane |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 4Q 2017 Swaps |
|
|
| 9,000 bbls |
|
|
| $0.76/gallon |
|
| 1Q 2018 Swaps |
|
|
| 5,500 bbls |
|
|
| $0.82/gallon |
|
| 2Q-4Q 2018 Swaps |
|
|
| 4,250 bbls |
|
|
| $0.81/gallon |
|
|
|
|
|
|
|
|
|
|
|
|
| C5 Natural Gasoline |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 4Q 2017 Swaps |
|
|
| 6,416 bbls |
|
|
| $1.08/gallon |
|
| 1Q 2018 Swaps |
|
|
| 5,167 bbls |
|
|
| $1.18/gallon |
|
| 2Q-4Q 2018 Swaps |
|
|
| 3,655 bbls |
|
|
| $1.17/gallon |
|
| (1) | Range has deferred calls at a strike of $3.75 for 4Q17. Total volume of 1,650,000 Mmbtu with a deferred premium price of $0.31 paid to Range |
| (2) | Range also sold call swaptions of 160,000 Mmbtu/d for April-December 2018 and 220,000 Mmbtu/d for calendar 2019 at average strike prices of $3.02 and $3.05 per Mmbtu, respectively |
| (3) | Notes deferred premium on puts |
| (4) | Incorporates international propane hedges |
SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS AND ADDITIONAL HEDGING DETAILS
16