Range Announces Third Quarter 2016 Results
Highlights –
- Merger with
Memorial Resource Development Corp. (“Memorial”) closed onSeptember 16 th - Gulf Markets Expansion pipeline on line in early October improves natural gas netbacks by moving 150,000 Mmbtu per day of Range natural gas from Appalachia to
Gulf Coast markets North Louisiana production growth and additional takeaway projects result in better natural gas differentials going forward- New condensate sales agreements commenced
July 1 , improving condensate prices by approximately$7.00 per barrel compared to the previous quarter - NGL pricing improved to 25% of WTI compared to 13% of WTI in the prior-year quarter
- Third quarter production averaged a record 1,508 net Mmcfe per day
- Southern Marcellus production averaged a record 1,228 net Mmcfe per day, up 23% from the prior-year quarter
- Unit costs improved by 3%, or
$0.09 per mcfe, compared to prior-year quarter
Commenting,
Third quarter results were encouraging, as production increased, unit costs improved and unhedged cash margins rebounded. We are excited as we look forward to fourth quarter 2016 and the full year 2017, as we anticipate improving margins on all of our products and continued improvement in capital efficiency across the Company. With our extensive opportunity set in two high-quality natural gas plays, we believe Range is in a great position to drive shareholder value for many years to come.”
Financial Discussion
Except for generally accepted accounting principles (“GAAP”) reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market gain or loss 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.
Third Quarter 2016
GAAP revenues for third quarter 2016 totaled
Non-GAAP revenues for third quarter 2016 totaled
Expenses | 3Q 2016 (per mcfe) |
3Q 2015 (per mcfe) |
Increase (Decrease) |
|||||||||
Direct operating | $ | 0.16 | $ | 0.26 | $ | (38 | %) | |||||
Transportation, gathering, processing & compression | 1.00 | 0.75 | 33 | % | ||||||||
Production and ad valorem taxes | 0.05 | 0.06 | (17 | %) | ||||||||
General and administrative | 0.21 | 0.25 | (16 | %) | ||||||||
Interest expense | 0.33 | 0.32 | 3 | % | ||||||||
Total cash unit costs (a) | 1.75 | 1.64 | 7 | % | ||||||||
Depletion, depreciation amortization | 0.95 | 1.16 | (18 | %) | ||||||||
Total unit costs (a) | $ | 2.70 | $ | 2.79 | $ | (3 | %) |
(a) Totals may not add due to rounding.
Third quarter 2016 natural gas, NGLs and oil differentials all improved compared to the prior year as a result of transportation capacity, marketing contracts and 15 days of production from the newly acquired
- Production and realized prices, including hedging settlements, by each commodity for third quarter 2016 were: natural gas – 1,016 Mmcf per day (
$2.50 per mcf), NGLs – 73,252 barrels per day ($12.43 per barrel) and crude oil and condensate – 8,814 barrels per day ($49.97 per barrel). Total third quarter production was 1,508 Mmcfe per day ($2.58 per mcfe). - The third quarter average natural gas price, before NYMEX hedging settlements, was
$2.14 per mcf as compared to$1.98 per mcf in the prior-year quarter. The average Company natural gas price differential including the impact of basis hedges for the third quarter improved to($0.68) per mcf compared to($0.78) per mcf in the prior-year quarter, as a result of increased capacity to better markets and 15 days of production from the newly acquiredNorth Louisiana assets. NYMEX natural gas financial hedges increased realizations$0.35 per mcf in the third quarter 2016. - Total NGL pricing per barrel including ethane and processing expenses before hedging settlements improved to 25% of WTI (
$11.17 per barrel) compared to 13% of WTI ($6.23 per barrel) in the prior-year quarter as a result of increased NGL capacity to better markets, mainly due to Mariner East. Hedging increased NGL prices by$1.26 per barrel in the third quarter 2016. - Crude oil and condensate price realizations, before realized hedges, for the third quarter averaged
$39.15 per barrel, or$5.81 below WTI, compared to$13.35 below WTI in the prior-year quarter. The improved differential primarily resulted from new condensate sales agreements in southwestPennsylvania that began onJuly 1 , 2016. Hedging added$10.82 per barrel in the third quarter 2016.
Capital Expenditures
Third quarter 2016 drilling expenditures of
A new slide has been added to Range’s investor presentation on page seven, available on Range’s website at www.rangeresources.com. The slide depicts a preliminary view of 2017 and 2018 year-over-year production growth, based on current strip pricing in 2017 and assuming
The Company expects to announce the details for the 2017 capital plan in February, following approval by the Company’s Board of Directors.
Financial Position and Liquidity
Effective with the closing of the Memorial merger on
Concurrent with the closing of the Memorial merger, Range completed a series of exchange and tender offers that streamlined and standardized covenants across the debt capital structure. This standardization enhances the Company’s financial flexibility and facilitates investor analysis of the debt securities. Of the
Operational Discussion
Range has updated its investor presentation with third quarter financial and operational results. Please see www.rangeresources.com under the Investors tab, “Company Presentations” area, for the presentation entitled, “Company Presentation –
The table below summarizes year-to-date activity and the number of wells expected to be turned to sales for the remainder of 2016.
Area | Wells to sales YTD @ 9/30/16 |
Remaining Fourth quarter |
Planned Total Wells to sales in 2016 |
|||
Super-Rich | 13 | 1 | 14 | |||
Wet | 26 | - | 26 | |||
Dry - SW | 42 | - | 42 | |||
Dry - NE | 12 | 5 | 17 | |||
Total Marcellus/Utica | 93 | 6 | 99 | |||
N. Louisiana | 39 | 3 | 42 | |||
Total Company | 132 | 9 | 141 |
Several Marcellus wells that were previously expected to be turned to sales late in fourth quarter 2016 are now expected in the first two weeks of 2017. This small adjustment has been captured in the Company’s fourth quarter production guidance, which remains on track with previous guidance. In addition, the North Louisiana Division has approximately 25 drilled but uncompleted wells which are expected to be turned to sales in first quarter 2017.
Total Marcellus production for the third quarter averaged 1,396 net Mmcfe per day, a 9% increase over the prior-year quarter. The Southern Marcellus Shale Division averaged 1,228 net Mmcfe per day during the quarter, a 23% increase over the prior-year quarter. The Northern Marcellus Shale Division averaged 169 net Mmcf per day during the quarter, a 39% decrease compared to the prior-year quarter, resulting from the sale of our
The Southern Marcellus Shale Division continues to drill and complete outstanding wells, with peer-leading EURs, while continuing to drive costs lower. The examples below represent recent wells brought on line that continue to perform well.
- In the southwest dry area, a four well pad brought on line in August is expected to have an EUR of approximately 16.0 Bcf per well, or over 3.0 Bcf per 1,000 lateral feet, at a cost of approximately
$5.1 million per well. - In the wet area, a four well pad brought on line at the end of July is expected to have an EUR of approximately 27.0 Bcfe per well, or 4.0 Bcfe per 1,000 lateral feet, at a cost of approximately
$5.7 million per well.
Operational efficiency gains continued in the third quarter. Year to date through September, the division completed 2,854 stages, compared to 2,643 stages in the previous year, an 8% increase, despite a reduction in overall activity and capital spending.
Range also continues to drill faster and more efficiently. Year to date through September, Range drilled 22% more lateral feet per day per rig, with a 5% reduction in drilling cost per lateral foot, when compared to the prior-year quarter. Logistical improvements in water handling have resulted in annual savings of over
Although it has only been approximately 40 days since the closing of the Memorial merger, integration of the teams and assets has progressed quickly. The
For the third quarter, the division brought on line 16 wells, all located in the Terryville field. Even with some outstanding well results over the past year, the team is focused on continued improvement in recoveries and capital efficiency. Some recent examples include:
- Two recent Terryville wells recorded spud to rig release in 30 days, compared to a year-to-date average of 40 days.
- A recent Terryville well had a 30 day average rate to sales of 27 Mmcfe per day, or 4.7 Mmcfe per day per 1,000 lateral feet, one of the top wells drilled in the field to date on a normalized basis.
- Range’s experience in studying, isolating and improving formation targeting has the potential to increase recoveries and improve consistency of results.
- Targeting of porosity intervals has been improved to a range of 20 to 40 feet compared to the previous interval of 100 to 125 feet.
- Recent wells have stayed within the new target range for the entire lateral. These wells are expected to be completed and brought on line in first quarter 2017.
- Range’s purchasing power combined with supply chain logistics has resulted in a 7% savings in casing costs.
There are currently three wells in progress in the extension acreage area, south of the Terryville field. Based on log analysis, gas-in-place analysis and reservoir pressure data, combined with the stacked-pay potential in the area, Range is encouraged. Two of the wells are currently being completed and the third well is still in the drilling phase. Range expects to have well results by the end of the year.
Marketing and Transportation
Range’s marketing team has a track record of innovative and diversified marketing solutions across all products. The second half of
For natural gas, Spectra’s Gulf Markets Expansion pipeline came on line in early October moving 150,000 Mmbtu per day of Range natural gas from Appalachia to markets close to the
For NGLs, Range recently supplied a shipment of ethane to INEOS’ facilities in Grangemouth, Scotland. This was the first shipment to the
Regarding condensate, Range entered into long-term agreements in early July that will serve two Midwest refineries in purchasing condensate from southwest Pennsylvania. The contracts largely drove the improvement in Marcellus condensate prices by approximately
Guidance
Production per day Guidance
Production for the fourth quarter of 2016 is expected to be approximately 1,850 Mmcfe per day with 31% to 33% liquids.
Fourth Quarter 2016 Expense Guidance
Direct operating expense: | $0.18 – $0.19 per mcfe | |
Transportation, gathering and compression expense: | $1.03 – $1.04 per mcfe | |
Production tax expense: | $0.05 – $0.06 per mcfe | |
Exploration expense: | $ 13.0 – $15.0 million* | |
Unproved property impairment expense: | $ 7.0 – $9.0 million | |
G&A expense: | $0.22 – $0.24 per mcfe | |
Interest expense: | $0.27 – $0.29 per mcfe | |
DD&A expense: | $0.95 – $0.96 per mcfe | |
Net Brokered Gas Marketing Expense: | ~$2.0 million | |
*Includes North Louisiana seismic expense of approximately
Differential Calculation
Based on current market pricing indications, Range would expect to average the following pre-hedge differentials for its fourth quarter 2016 and full year 2017 production.
4th Quarter 2016 | Full-Year 2017 | ||
Natural Gas: | NYMEX less $0.46 | NYMEX less $0.30 - $0.35 | |
Natural Gas Liquids (including ethane): | 26% - 28% of WTI | 26% - 28% of WTI | |
Oil/Condensate: | WTI minus $6.00 - $7.00 |
WTI minus $6.00 - $7.00 |
|
Hedging Status
Range hedges portions of its expected future production volumes to increase the predictability of cash flow. Range currently has over 80% of its remaining 2016 natural gas production hedged at a weighted average floor price of
Range has hedged Marcellus and other basis differentials covering 59,385,000 Mmbtu per day for
Range has also hedged the premium spread between the Mont Belvieu propane index and the respective European and Asian propane market indexes on approximately 33% of anticipated LPG sales through December 2017. The fair value of these hedges based upon future strip prices as of
Conference Call and Webcast Information
A conference call to review the financial results is scheduled on
A simultaneous webcast of the call may be accessed over the internet at www.rangeresources.com. The webcast will be archived for replay on the Company’s website until
Non-GAAP Financial Measures
Adjusted net income or loss comparable to analysts’ estimates as set forth in this release represents income or loss 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 to adjusted net income (loss) 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 from operating activities 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 operating activities, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles net cash from operating activities 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 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 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 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 Quarterly Report on Form 10-Q. The Company believes that it is important to furnish this detail of the various components comprising each line of the Statements of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.
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 merger integration, 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, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of actual drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes, the ultimate timing, outcome and results of integrating the operations of Range and
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
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 September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | ||||||||||||||||||
Revenues and other income: | |||||||||||||||||||||||
Natural gas, NGLs and oil sales (a) | $ | 304,477 | $ | 252,065 | $ | 738,570 | $ | 835,601 | |||||||||||||||
Derivative fair value income/(loss) | 64,556 | 202,004 | (11,334 | ) | 290,052 | ||||||||||||||||||
Brokered natural gas, marketing and other (b) | 44,114 | 25,141 | 118,445 | 60,822 | |||||||||||||||||||
ARO settlement loss (b) | (6 | ) | (5 | ) | (14 | ) | 23 | ||||||||||||||||
Other (b) | 66 | 728 | 750 | 843 | |||||||||||||||||||
Total revenues and other income | 413,207 | 479,933 | -14 | % | 846,417 | 1,187,341 | -29 | % | |||||||||||||||
Costs and expenses: | |||||||||||||||||||||||
Direct operating | 21,890 | 34,449 | 65,331 | 104,826 | |||||||||||||||||||
Direct operating – non-cash stock-based compensation (c) | 497 | 609 | 1,781 | 2,149 | |||||||||||||||||||
Transportation, gathering, processing and compression | 138,764 | 99,634 | 400,871 | 284,258 | |||||||||||||||||||
Production and ad valorem taxes | 6,717 | 7,336 | 18,653 | 26,506 | |||||||||||||||||||
Brokered natural gas and marketing | 44,167 | 31,713 | 120,756 | 79,181 | |||||||||||||||||||
Brokered natural gas and marketing – non-cash stock-based compensation (c) |
455 | 618 | 1,349 | 1,743 | |||||||||||||||||||
Exploration | 6,335 | 3,547 | 16,972 | 14,975 | |||||||||||||||||||
Exploration – non-cash stock-based compensation (c) | 608 | 688 | 1,669 | 2,171 | |||||||||||||||||||
Abandonment and impairment of unproved properties | 6,082 | 12,366 | 23,769 | 36,187 | |||||||||||||||||||
General and administrative | 29,428 | 33,038 | 87,819 | 106,814 | |||||||||||||||||||
General and administrative – non-cash stock-based compensation (c) |
11,126 | 11,512 | 37,682 | 38,545 | |||||||||||||||||||
General and administrative – lawsuit settlements | 120 | 1,278 | 1,444 | 2,012 | |||||||||||||||||||
General and administrative – bad debt expense | 350 | 350 | 800 | 600 | |||||||||||||||||||
General and administrative – DEP penalty | – | – | – | 2,500 | |||||||||||||||||||
Memorial merger expenses | 33,791 | – | 36,412 | – | |||||||||||||||||||
Termination costs | 136 | (76 | ) | 303 | 4,570 | ||||||||||||||||||
Termination costs – non-cash stock-based compensation (c) | – | (1 | ) | – | 1,720 | ||||||||||||||||||
Deferred compensation plan (d) | (11,636 | ) | (43,705 | ) | 30,166 | (56,611 | ) | ||||||||||||||||
Interest expense | 45,967 | 42,904 | 121,464 | 125,590 | |||||||||||||||||||
Loss on early extinguishment of debt | – | 22,495 | – | 22,495 | |||||||||||||||||||
Depletion, depreciation and amortization | 131,489 | 153,993 | 374,440 | 453,178 | |||||||||||||||||||
Impairment of proved properties and other assets | – | 502,233 | 43,040 | 502,233 | |||||||||||||||||||
Loss (gain) on sale of assets | 2,597 | 681 | 7,544 | (2,053 | ) | ||||||||||||||||||
Total costs and expenses | 468,883 | 915,662 | 49 | % | 1,392,265 | 1,753,589 | 21 | % | |||||||||||||||
Loss before income taxes | (55,676 | ) | (435,729 | ) | 87 | % | (545,848 | ) | (566,248 | ) | 4 | % | |||||||||||
Income tax benefit: | |||||||||||||||||||||||
Current | – | – | – | – | |||||||||||||||||||
Deferred | (13,705 | ) | (134,781 | ) | (187,231 | ) | (174,390 | ) | |||||||||||||||
(13,705 | ) | (134,781 | ) | (187,231 | ) | (174,390 | ) | ||||||||||||||||
Net loss | $ | (41,971 | ) | $ | (300,948 | ) | 86 | % | $ | (358,617 | ) | $ | (391,858 | ) | 8 | % | |||||||
Net Loss Per Common Share: | |||||||||||||||||||||||
Basic | $ | (0.23 | ) | $ | (1.81 | ) | $ | (2.09 | ) | $ | (2.36 | ) | |||||||||||
Diluted | $ | (0.23 | ) | $ | (1.81 | ) | $ | (2.09 | ) | $ | (2.36 | ) | |||||||||||
Weighted average common shares outstanding, as reported: | |||||||||||||||||||||||
Basic | 180,683 | 166,517 | 9 | % | 171,571 | 166,327 | 3 | % | |||||||||||||||
Diluted | 180,683 | 166,517 | 9 | % | 171,571 | 166,327 | 3 | % |
(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) | September 30, | December 31, | |||||
2016 | 2015 | ||||||
(Unaudited) | (Audited) | ||||||
Assets | |||||||
Current assets | $ | 220,870 | $ | 157,530 | |||
Derivative assets | 179,820 | 288,762 | |||||
Goodwill | 1,630,981 | – | |||||
Natural gas and oil properties, successful efforts method | 9,206,100 | 6,361,305 | |||||
Transportation and field assets | 18,308 | 19,455 | |||||
Other | 71,180 | 72,979 | |||||
$ | 11,327,259 | $ | 6,900,031 | ||||
Liabilities and Stockholders’ Equity | |||||||
Current liabilities | $ | 439,786 | $ | 335,513 | |||
Asset retirement obligations | 15,071 | 15,071 | |||||
Derivative liabilities | 7,277 | 1,136 | |||||
Bank debt | 930,669 | 86,427 | |||||
Senior notes | 2,847,564 | 738,101 | |||||
Senior subordinated notes | 48,476 | 1,826,775 | |||||
Total debt | 3,826,709 | 2,651,303 | |||||
Deferred tax liability | 1,176,353 | 777,947 | |||||
Derivative liabilities | 3,934 | 21 | |||||
Deferred compensation liability | 119,645 | 104,792 | |||||
Asset retirement obligations and other liabilities | 277,671 | 254,590 | |||||
Common stock and retained earnings | 5,462,514 | 2,761,903 | |||||
Common stock held in treasury stock | (1,701 | ) | (2,245 | ) | |||
Total stockholders’ equity | 5,460,813 | 2,759,658 | |||||
$ | 11,327,259 | $ | 6,900,031 |
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, |
|||||||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | |||||||||||||||||||
Total revenues and other income, as reported | $ | 413,207 | $ | 479,933 | -14 | % | $ | 846,417 | $ | 1,187,341 | -29 | % | ||||||||||||
Adjustment for certain special items: | ||||||||||||||||||||||||
Total change in fair value related to derivatives prior to settlement (gain) loss | (11,443 | ) | (64,075 | ) | 271,991 | 70,593 | ||||||||||||||||||
ARO settlement (gain) loss | 6 | 5 | 14 | (23 | ) | |||||||||||||||||||
Total revenues, as adjusted, non-GAAP | $ | 401,770 | $ | 415,863 | -3 | % | $ | 1,118,422 | $ | 1,257,911 | -11 | % |
RANGE RESOURCES CORPORATION | |||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||
(Unaudited in thousands) | |||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||||
Net loss | $ | (41,971 | ) | $ | (300,948 | ) | $ | (358,617 | ) | $ | (391,858 | ) | |||||
Adjustments to reconcile net cash provided from continuing operations: | |||||||||||||||||
Deferred income tax benefit | (13,705 | ) | (134,781 | ) | (187,231 | ) | (174,390 | ) | |||||||||
Depletion, depreciation, amortization and impairment | 131,489 | 656,226 | 417,480 | 955,411 | |||||||||||||
Exploration dry hole costs | 2 | (19 | ) | 2 | 87 | ||||||||||||
Abandonment and impairment of unproved properties | 6,082 | 12,366 | 23,769 | 36,187 | |||||||||||||
Derivative fair value loss (income) | (64,556 | ) | (202,004 | ) | 11,334 | (290,052 | ) | ||||||||||
Cash settlements on derivative financial instruments that do not qualify for hedge accounting | 53,113 | 137,929 | 260,657 | 360,645 | |||||||||||||
Allowance for bad debts | 350 | 350 | 800 | 600 | |||||||||||||
Amortization of deferred issuance costs, loss on extinguishment of debt, and other | 1,946 | 24,482 | 5,383 | 27,572 | |||||||||||||
Deferred and stock-based compensation | 971 | (30,471 | ) | 72,689 | (10,679 | ) | |||||||||||
(Loss) gain on sale of assets and other | 2,597 | 681 | 7,544 | (2,053 | ) | ||||||||||||
Changes in working capital: | |||||||||||||||||
Accounts receivable | (9,970 | ) | 5,753 | 31,985 | 79,448 | ||||||||||||
Inventory and other | (11,276 | ) | (3,324 | ) | (776 | ) | (7,073 | ) | |||||||||
Accounts payable | (22,074 | ) | (16,650 | ) | (41,268 | ) | (13,158 | ) | |||||||||
Accrued liabilities and other | (565 | ) | (4,172 | ) | (41,714 | ) | (55,127 | ) | |||||||||
Net changes in working capital | (43,885 | ) | (18,393 | ) | (51,773 | ) | 4,090 | ||||||||||
Net cash provided from operating activities | $ | 32,433 | $ | 145,418 | $ | 202,037 | $ | 515,560 | |||||||||
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, | ||||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||||
Net cash provided from operating activities, as reported | $ | 32,433 | $ | 145,418 | $ | 202,037 | $ | 515,560 | |||||||||
Net changes in working capital | 43,885 | 18,393 | 51,773 | (4,090 | ) | ||||||||||||
Exploration expense | 6,333 | 3,566 | 16,970 | 14,888 | |||||||||||||
Lawsuit settlements | 120 | 1,278 | 1,444 | 2,012 | |||||||||||||
Cash paid to exchange senior subordinated notes | 6,600 | – | 6,600 | – | |||||||||||||
Legal contingency/DEP penalty | – | – | – | 2,500 | |||||||||||||
Memorial merger expenses | 33,791 | – | 36,412 | – | |||||||||||||
Termination costs | 136 | (76 | ) | 303 | 4,570 | ||||||||||||
Non-cash compensation adjustment | (79 | ) | 46 | (37 | ) | 636 | |||||||||||
Cash flow from operations before changes in working capital – non-GAAP measure | $ | 123,219 | $ | 168,625 | $ | 315,502 | $ | 536,076 | |||||||||
WEIGHTED AVERAGE SHARES OUTSTANDING | |||||||||||||||||
(Unaudited, in thousands) | |||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||||
Basic: | |||||||||||||||||
Weighted average shares outstanding | 247,145 | 169,362 | 247,145 | 169,142 | |||||||||||||
Impact of shares issued for Memorial acquisition | (63,654 | ) | – | (72,784 | ) | – | |||||||||||
Stock held by deferred compensation plan | (2,808 | ) | (2,845 | ) | (2,790 | ) | (2,815 | ) | |||||||||
Basic | 180,683 | 166,517 | 171,571 | 166,327 | |||||||||||||
Diluted: | |||||||||||||||||
Weighted average shares outstanding | 247,145 | 169,362 | 247,145 | 169,142 | |||||||||||||
Impact of shares issued for Memorial acquisition | (63,654 | ) | – | (72,784 | ) | – | |||||||||||
Stock held by deferred compensation plan | (2,808 | ) | (2,845 | ) | (2,790 | ) | (2,815 | ) | |||||||||
Diluted | 180,683 | 166,517 | 171,571 | 166,327 |
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, | |||||||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | |||||||||||||||||||
Natural gas, NGL and oil sales components: | ||||||||||||||||||||||||
Natural gas sales | $ | 197,476 | $ | 189,113 | $ | 464,098 | $ | 589,517 | ||||||||||||||||
NGL sales | 75,259 | 31,066 | 198,877 | 131,822 | ||||||||||||||||||||
Oil sales | 31,742 | 31,886 | 75,595 | 114,262 | ||||||||||||||||||||
Total oil and gas sales, as reported | $ | 304,477 | $ | 252,065 | 21 | % | $ | 738,570 | $ | 835,601 | -12 | % | ||||||||||||
Derivative fair value income (loss), as reported: | $ | 64,556 | $ | 202,004 | $ | (11,334 | ) | $ | 290,052 | |||||||||||||||
Cash settlements on derivative financial instruments – (gain) loss: | ||||||||||||||||||||||||
Natural gas | (35,822 | ) | (80,675 | ) | (205,985 | ) | (223,603 | ) | ||||||||||||||||
NGLs | (8,514 | ) | (16,047 | ) | (25,395 | ) | (31,608 | ) | ||||||||||||||||
Crude Oil | (8,777 | ) | (41,207 | ) | (29,277 | ) | (105,434 | ) | ||||||||||||||||
Total change in fair value related to derivatives prior to settlement, a non-GAAP measure | $ | 11,443 | $ | 64,075 | $ | (271,991 | ) | $ | (70,593 | ) | ||||||||||||||
Transportation, gathering, processing and compression components: | ||||||||||||||||||||||||
Natural gas | $ | 99,465 | $ | 87,886 | $ | 288,355 | $ | 247,744 | ||||||||||||||||
NGLs | 39,299 | 11,748 | 112,516 | 36,514 | ||||||||||||||||||||
Total transportation, gathering, processing and compression, as reported | $ | 138,764 | $ | 99,634 | $ | 400,871 | $ | 284,258 | ||||||||||||||||
Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | ||||||||||||||||||||||||
Natural gas sales | $ | 233,298 | $ | 269,788 | $ | 670,083 | $ | 813,120 | ||||||||||||||||
NGL sales | 83,773 | 47,113 | 224,272 | 163,430 | ||||||||||||||||||||
Oil sales | 40,519 | 73,093 | 104,872 | 219,696 | ||||||||||||||||||||
Total | $ | 357,590 | $ | 389,994 | -8 | % | 999,227 | 1,196,246 | -16 | % | ||||||||||||||
Production of oil and gas during the periods (a): | ||||||||||||||||||||||||
Natural gas (mcf) | 93,466,385 | 97,273,739 | -4 | % | 261,331,126 | 265,511,105 | -2 | % | ||||||||||||||||
NGL (bbl) | 6,739,161 | 4,985,092 | 35 | % | 19,579,843 | 15,449,495 | 27 | % | ||||||||||||||||
Oil (bbl) | 810,878 | 958,628 | -15 | % | 2,504,757 | 3,187,005 | -21 | % | ||||||||||||||||
Gas equivalent (mcfe) (b) | 138,766,619 | 132,936,059 | 4 | % | 393,838,726 | 377,330,105 | 4 | % | ||||||||||||||||
Production of oil and gas – average per day (a): | ||||||||||||||||||||||||
Natural gas (mcf) | 1,015,939 | 1,057,323 | -4 | % | 953,763 | 972,568 | -2 | % | ||||||||||||||||
NGL (bbl) | 73,252 | 54,186 | 35 | % | 71,459 | 56,592 | 26 | % | ||||||||||||||||
Oil (bbl) | 8,814 | 10,420 | -15 | % | 9,141 | 11,674 | -22 | % | ||||||||||||||||
Gas equivalent (mcfe) (b) | 1,508,333 | 1,444,957 | 4 | % | 1,437,368 | 1,382,162 | 4 | % | ||||||||||||||||
Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | ||||||||||||||||||||||||
Natural gas (mcf) | $ | 2.11 | $ | 1.94 | 9 | % | $ | 1.78 | $ | 2.22 | -20 | % | ||||||||||||
NGL (bbl) | $ | 11.17 | $ | 6.23 | 79 | % | $ | 10.16 | $ | 8.53 | 19 | % | ||||||||||||
Oil (bbl) | $ | 39.15 | $ | 33.26 | 18 | % | $ | 30.18 | $ | 35.85 | -16 | % | ||||||||||||
Gas equivalent (mcfe) (b) | $ | 2.19 | $ | 1.89 | 16 | % | $ | 1.88 | $ | 2.21 | -15 | % | ||||||||||||
Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | ||||||||||||||||||||||||
Natural gas (mcf) | $ | 2.50 | $ | 2.77 | -10 | % | $ | 2.56 | $ | 3.06 | -16 | % | ||||||||||||
NGL (bbl) | $ | 12.43 | $ | 9.45 | 32 | % | $ | 11.45 | $ | 10.58 | 8 | % | ||||||||||||
Oil (bbl) | $ | 49.97 | $ | 76.25 | -34 | % | $ | 41.87 | $ | 68.93 | -39 | % | ||||||||||||
Gas equivalent (mcfe) (b) | $ | 2.58 | $ | 2.93 | -12 | % | $ | 2.54 | $ | 3.17 | -20 | % | ||||||||||||
Average prices, including cash-settled hedges and derivatives: (d) | ||||||||||||||||||||||||
Natural gas (mcf) | $ | 1.43 | $ | 1.87 | -24 | % | $ | 1.46 | $ | 2.13 | -31 | % | ||||||||||||
NGL (bbl) | $ | 6.60 | $ | 7.09 | -7 | % | $ | 5.71 | $ | 8.21 | -30 | % | ||||||||||||
Oil (bbl) | $ | 49.97 | $ | 76.25 | -34 | % | $ | 41.87 | $ | 68.93 | -39 | % | ||||||||||||
Gas equivalent (mcfe) (b) | $ | 1.58 | $ | 2.18 | -28 | % | $ | 1.52 | $ | 2.42 | -37 | % | ||||||||||||
Transportation, gathering and compression expense per mcfe | $ | 1.00 | $ | 0.75 | 33 | % | $ | 1.02 | $ | 0.75 | 35 | % |
(a) Represents volumes sold regardless of when produced.
(b) Oil and NGLs are converted at the rate of one barrel equals six mcfe based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
(c) Excluding third party transportation, gathering and compression costs.
(d) Net of transportation, gathering, processing and compression costs.
RANGE RESOURCES CORPORATION | |||||||||||||||||||||||
RECONCILIATION OF INCOME BEFORE INCOME TAXES AS REPORTED TO INCOME BEFORE INCOME TAXES EXCLUDING CERTAIN ITEMS, a non-GAAP measure |
|
||||||||||||||||||||||
(Unaudited, in thousands, except per share data) | |||||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2016 | 2015 | % | 2016 | 2015 | % | ||||||||||||||||||
Loss before income taxes, as reported | $ | (55,676 | ) | $ | (435,729 | ) | 87 | % | $ | (545,848 | ) | $ | (566,248 | ) | -4 | % | |||||||
Adjustment for certain special items: | |||||||||||||||||||||||
Loss (gain) on sale of assets | 2,597 | 681 | 7,544 | (2,053 | ) | ||||||||||||||||||
(Gain) loss on ARO settlements | 6 | 5 | 14 | (23 | ) | ||||||||||||||||||
Change in fair value related to derivatives prior to settlement | (11,443 | ) | (64,075 | ) | 271,991 | 70,593 | |||||||||||||||||
Abandonment and impairment of unproved properties | 6,082 | 12,366 | 23,769 | 36,187 | |||||||||||||||||||
Loss on early extinguishment of debt | – | 22,495 | – | 22,495 | |||||||||||||||||||
Impairment of proved property | – | 502,233 | 43,040 | 502,233 | |||||||||||||||||||
Lawsuit settlements | 120 | 1,278 | 1,444 | 2,012 | |||||||||||||||||||
Fees paid to exchange senior subordinated notes | 6,600 | – | 6,600 | – | |||||||||||||||||||
DEP penalty | – | – | – | 2,500 | |||||||||||||||||||
Memorial merger expenses | 33,791 | – | 36,412 | – | |||||||||||||||||||
Termination costs | 136 | (76 | ) | 303 | 4,570 | ||||||||||||||||||
Termination costs – non-cash stock-based compensation | – | (1 | ) | – | 1,720 | ||||||||||||||||||
Brokered natural gas and marketing – non-cash stock-based compensation | 455 | 618 | 1,349 | 1,743 | |||||||||||||||||||
Direct operating – non-cash stock-based compensation | 497 | 609 | 1,781 | 2,149 | |||||||||||||||||||
Exploration expenses – non-cash stock-based compensation | 608 | 688 | 1,669 | 2,171 | |||||||||||||||||||
General & administrative – non-cash stock-based compensation | 11,126 | 11,512 | 37,682 | 38,545 | |||||||||||||||||||
Deferred compensation plan – non-cash adjustment | (11,636 | ) | (43,705 | ) | 30,166 | (56,611 | ) | ||||||||||||||||
(Loss) income before income taxes, as adjusted | (16,737 | ) | 8,899 | NM | (82,084 | ) | 61,983 | NM | |||||||||||||||
Income tax expense, as adjusted | |||||||||||||||||||||||
Current | – | – | – | – | |||||||||||||||||||
Deferred (a) | (6,367 | ) | 3,436 | (31,333 | ) | 23,346 | |||||||||||||||||
Net (loss) income excluding certain items, a non-GAAP measure | $ | (10,370 | ) | $ | 5,463 | NM | $ | (50,751 | ) | $ | 38,637 | NM | |||||||||||
Non-GAAP (loss) income per common share | |||||||||||||||||||||||
Basic | $ | (0.06 | ) | $ | 0.03 | NM | $ | (0.30 | ) | $ | 0.23 | NM | |||||||||||
Diluted | $ | (0.06 | ) | $ | 0.03 | NM | $ | (0.30 | ) | $ | 0.23 | NM | |||||||||||
Non-GAAP diluted shares outstanding, if dilutive | 180,683 | 166,517 | 171,571 | 166,685 | |||||||||||||||||||
(a) Deferred taxes are estimated to be approximately 38%.
NM = Not meaningful
RANGE RESOURCES CORPORATION
HEDGING POSITION AS OF October 21, 2016
(Unaudited) –
Daily Volume | Hedge Price | |||||||||||
Gas | ||||||||||||
4Q 2016 Swaps (2) | 901,739 Mmbtu | $ | 3.32 | |||||||||
4Q 2016 Puts (1) (2) | 218,478 Mmbtu | $ | 3.20 | |||||||||
4Q 2016 Collars (2) | 32,609 Mmbtu | $4.00 x $4.71 | ||||||||||
2017 Swaps (2) | 610,691 Mmbtu | $ | 3.18 | |||||||||
2017 Puts (1) (2) | 175,890 Mmbtu | $ | 3.17 | |||||||||
2017 Collars (2) | 34,521 Mmbtu | $4.00 x $5.06 | ||||||||||
2018 Swaps | 130,000 Mmbtu | $ | 2.98 | |||||||||
Oil | ||||||||||||
4Q 2016 Swaps (2) | 8,640 bbls | $ | 69.49 | |||||||||
4Q 2016 Collars (2) | 848 bbls | $80.00 x $99.70 | ||||||||||
2017 Swaps | 5,666 bbls | $ | 57.04 | |||||||||
2018 Swaps | 750 bbls | $ | 54.42 | |||||||||
C2 Ethane | ||||||||||||
4Q 2016 Swaps (2) | 5,839 bbls | $0.46/gallon | ||||||||||
2017 Swaps | 3,000 bbls | $0.27/gallon | ||||||||||
C3 Propane | ||||||||||||
4Q 2016 Swaps (2) | 11,142 bbls | $0.75/gallon | ||||||||||
2017 Swaps | 5,500 bbls | $0.53/gallon | ||||||||||
C4 Normal Butane | ||||||||||||
4Q 2016 Swaps (2) | 6,071 bbls | $0.72/gallon | ||||||||||
2017 Swaps | 2,500 bbls | $0.68/gallon | ||||||||||
IC4 ISO Butane | ||||||||||||
4Q 2016 Swaps (2) | 1,969 bbls | $1.21/gallon | ||||||||||
C5 Natural Gasoline | ||||||||||||
4Q 2016 Swaps (2) | 8,142 bbls | $1.36/gallon | ||||||||||
2017 Swaps | 2,750 bbls | $01.01/gallon | ||||||||||
(1) Net of deferred premiums
(2) Includes derivative instruments assumed in connection with the Memorial Merger
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
Investor Contacts:Laith Sando , Vice President – Investor Relations 817-869-4267 lsando@rangeresources.comDavid Amend , Investor Relations Manager 817-869-4266 damend@rangeresources.comMichael Freeman , Senior Financial Analyst 817-869-4264 mfreeman@rangeresources.comJosh Stevens , Financial Analyst 817-869-1564 jrstevens@rangeresources.com Media Contact:Matt Pitzarella , Director of Corporate Communications 724-873-3224 mpitzarella@rangeresources.com www.rangeresources.com