Range Reports 2015 Earnings, Announces 2016 Capital Plans
Highlights -
- Fourth quarter unit costs reduced by 15%, or
$0.46 per mcfe compared to prior-year quarter - Fourth quarter natural gas differential improved
$0.20 , or 35%, compared to prior-year quarter, driven by additional takeaway projects - Record annual average daily production of 1.4 Bcfe per day
- Reserve replacement of 436% at
$0.37 per mcfe drill-bit finding cost - Peer-leading
Marcellus EURs and well costs on a normalized lateral length basis - Completed Nora asset sale for cash proceeds of
$865 million , used to reduce debt at year-end - Mariner East in final commissioning phase, expected to improve NGL netbacks
- Signed agreement to sell
Bradford County non-operated interest for approximately$112 million - 2016 capital budget set at
$495 million ; within expected cash flow and anticipated 2016 asset sales
Commenting,
"As a result of excellent well performance, reduced capital and operating costs and improved differentials across all products, Range continues to achieve accretive returns on our Marcellus acreage. We have set our 2016 capital budget at
Financial Discussion
(Except for generally accepted accounting principles ("GAAP") reported amounts, specific expense categories exclude non-cash impairments, unrealized mark-to-market 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 and compression, production and ad valorem taxes, general and administrative, interest and depletion, depreciation and amortization costs divided by production. See "Non-GAAP Financial Measures" for a definition of each of the non-GAAP financial measures and the tables that reconcile each of the non-GAAP measures to their most directly comparable GAAP financial measure.)
Full Year 2015
GAAP revenues for 2015 totaled
Non-GAAP revenues for 2015 totaled
Expenses | Full Year 2015 (per mcfe) |
Full Year 2014 (per mcfe) |
Increase (Decrease) | ||||
Direct operating | $ 0.26 | $ 0.34 | (24%) | ||||
Transportation, gathering and compression | 0.78 | 0.77 | 1% | ||||
Production and ad valorem taxes | 0.07 | 0.11 | (36%) | ||||
General and administrative | 0.27 | 0.35 | (23%) | ||||
Interest expense | 0.33 | 0.40 | (18%) | ||||
Total cash unit costs | 1.71 | 1.97 | (13%) | ||||
Depletion, depreciation and amortization | 1.14 | 1.30 | (12%) | ||||
Total unit costs | $ 2.85 | $ 3.27 | (13%) | ||||
The Company announced its full year 2015 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts' estimates) averaged
- Production and realized prices by each commodity for 2015 were: natural gas - 994 Mmcf per day (
$3.07 per mcf), NGLs - 55,770 barrels per day ($10.73 per barrel) and crude oil and condensate - 11,189 barrels per day ($71.28 per barrel). - The 2015 average natural gas price, before all hedging settlements, decreased to
$2.13 per mcf as compared to$3.99 per mcf in the prior year. NYMEX natural gas financial hedges increased realizations$0.94 per mcf for 2015. The average Company natural gas price differential including the impact of basis hedging was($0.52) per mcf compared to($0.48) per mcf in the prior year. - Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was
$10.73 per barrel compared to$24.31 in the prior year. Hedging increased NGL prices by$2.06 per barrel in 2015 compared to$0.72 in the prior year. - Crude oil and condensate price realizations, before hedges, for the year averaged
$34.28 per barrel, or$14.93 below West Texas Intermediate ("WTI"), compared to$14.84 below WTI in the prior year. Hedging added$37.00 per barrel in 2015 as hedging gains offset substantially lower oil prices, compared to hedge gains of$1.95 per barrel in the prior year.
Fourth Quarter 2015
GAAP revenues for the fourth quarter of 2015 totaled
Non-GAAP revenues for fourth quarter 2015 totaled
Expenses | 4Q 2015 (per mcfe) |
4Q 2014 (per mcfe) |
Increase (Decrease) | ||||
Direct operating | $ 0.22 | $ 0.32 | (31%) | ||||
Transportation, gathering and compression | 0.85 | 0.76 | 12% | ||||
Production and ad valorem taxes | 0.06 | 0.10 | (40%) | ||||
General and administrative | 0.22 | 0.33 | (33%) | ||||
Interest expense | 0.31 | 0.33 | (6%) | ||||
Total cash unit costs | 1.66 | 1.84 | (10%) | ||||
Depletion, depreciation and amortization | 0.97 | 1.25 | (22%) | ||||
Total unit costs | $ 2.63 | $ 3.09 | (15%) | ||||
Fourth quarter 2015 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which correspond to analysts' estimates) averaged
- Production and realized prices by each commodity for fourth quarter 2015 were: natural gas - 1,056 Mmcf per day (
$3.08 per mcf), NGLs - 53,333 barrels per day ($11.23 per barrel) and crude oil and condensate - 9,751 barrels per day ($79.62 per barrel). - The fourth quarter average natural gas price, before all hedging settlements, decreased to
$1.89 per mcf as compared to$3.24 per mcf in the prior year. NYMEX natural gas financial hedges increased realizations$1.18 per mcf in the fourth quarter of 2015. The average Company natural gas price differential including the impact of basis hedges for the fourth quarter improved to($0.37) per mcf compared to($0.57) per mcf in the prior year. - Total NGL pricing per barrel including ethane and processing expenses after realized cash-settled hedging was
$11.23 for the fourth quarter compared to$23.33 per barrel in the prior year. Hedging increased NGL prices by$2.12 per barrel in the fourth quarter compared to$5.37 per barrel in the prior year. - Crude oil and condensate price realizations, before realized hedges, for the fourth quarter averaged
$28.70 per barrel, or$13.52 below WTI, compared to$15.08 below WTI in the prior year. Hedging added$50.92 per barrel compared to$19.67 in the prior year, as hedging offset substantially lower oil prices.
Financial Position and Liquidity
During 2015, Range decreased total debt by
Range's senior subordinated notes include a provision that potentially limits the amount of total debt the Company can incur under its revolving credit facility. The calculation is based on
Range's Board of Directors also declared a quarterly cash dividend on the Company's common stock for the first quarter 2016. A dividend of
In early February, Range signed a purchase and sale agreement covering its non-operating Marcellus interest in
Capital Spending Plans and Cost Overview/Outlook
Range has set its 2016 capital spending budget at
Fourth quarter 2015 drilling expenditures of
Total unit costs for fourth quarter 2015 decreased by 15% compared to the prior-year quarter. The improving unit costs were led by a 33% decline in general and administrative expense to
Operational Discussion
Range has updated its investor presentation with updated economic sensitivity analysis for the Marcellus. Please see www.rangeresources.com under the Investors tab, "Company Presentations" area, for the presentation entitled, "Company Presentation -
Production for the fourth quarter of 2015 averaged approximately 1,275 net Mmcfe per day for the
Range has updated well economics and type curves for the planned 2016 Marcellus drilling program, which can be found on the Company's website in the most recent investor presentation. Consistent with the prior year, updated type curves reflect expected flow restrictions that result from infrastructure and facility constraints. The Company manages development of its Marcellus assets in order to maximize project returns. As a result, early production from prolific Marcellus wells is often constrained, resulting in flatter decline curves, and is reflected in the type curves. As seen in the presentation slides, wells turned in line ("TIL") over the past two years continue to perform in line with type curve expectations. These results demonstrate the quality of acreage as the Company continues development across its core position in southwest
The table below summarizes the 2015 activity and estimates for 2016 regarding the number of wells to sales, average lateral lengths, well costs, EURs by area and Range's current net acreage for the Marcellus only.
|
Wells TIL in 2015 | Average 2015 Lateral Length | Planned Wells TIL in 2016 | Expected Average 2016 Lateral Length | ||||
SW PA Super-Rich | 25 | 5,367 ft. | 13 | 6,660 ft. | ||||
SW PA Wet | 49 | 5,955 ft. | 38 | 6,970 ft. | ||||
SW PA Dry | 33 | 6,798 ft. | 38 | 7,000 ft. | ||||
NE PA Dry | 19 | 5,663 ft. | 14 | 5,660 ft. | ||||
Total Marcellus | 126 | 103 | ||||||
Expected 2016 Well Costs | Projected EURs for 2016 Wells | Net Acreage by Area (Marcellus only) |
||||||
SW PA Super-Rich | $5.9 million | 16.0 Bcfe | 110,000 | |||||
SW PA Wet | $5.8 million | 20.6 Bcfe | 225,000 | |||||
SW PA Dry | $5.2 million | 17.6 Bcf | 180,000 | |||||
NE PA Dry | $2.9 million | 14.1 Bcf | 110,000 | |||||
Total Marcellus | 625,000 | |||||||
In 2015, the Company completed its second successful
Marcellus Shale Marketing and Transportation
The Mariner East project started the commissioning process for ethane in late 2015, commissioned the refrigeration system in January and introduced ethane into the pipeline for the first time in early February.
Range's marketing team has also put in place strategic outlets for natural gas that are currently being realized, as demonstrated by improved natural gas differentials during the fourth quarter. Specifically, the Company had a full quarter of utilizing Spectra's
During the second half of 2015, Range initiated a new marketing arrangement for condensate sales and improved the Company's oil differentials from approximately
Guidance - 2016
Production per day Guidance
Production for the entire 2016 year is expected to average 1,390 to 1,420 Mmcfe per day. This equates to an 8% to 10% production growth for the year on a pro forma basis, adjusted for asset sales. Production for the first quarter of 2016 is expected to be approximately 1,350 Mmcfe per day with 30% to 32% liquids.
1Q 2016 Expense Guidance
Direct operating expense: | $0.25 - $0.27 per mcfe | |
Transportation, gathering and compression expense: | $1.03 - $1.05 per mcfe | |
Production tax expense: | $0.06 - $0.07 per mcfe | |
Exploration expense: | $5.0 - $7.0 million | |
Unproved property impairment expense: | $11.0 - $13.0 million | |
G&A expense: | $0.24 - $0.26 per mcfe | |
Interest expense: | $0.30 - $0.31 per mcfe | |
DD&A expense: | $0.97 - $0.99 per mcfe | |
2016 Differentials
Based on current market pricing indications, Range would expect to receive the following pre-hedge differentials for its production in 2016.
Natural Gas: | NYMEX minus $0.40 - $0.45 | |
Natural Gas Liquids (including ethane): | 23% - 25% of WTI | |
Oil/Condensate: | WTI minus $13 - $14 | |
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 approximately 80% of its expected 2016 natural gas production hedged at a weighted average floor price of
Range has also hedged Marcellus and other basis differentials covering 120,000 Mmbtu per day from January through
Conference Call Information
A conference call to review the financial results is scheduled on
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
Non-GAAP Financial Measures
Adjusted net income comparable to analysts' estimates as set forth in this release represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed in the accompanying table) less income taxes. We believe adjusted net income comparable to analysts' estimates is calculated on the same basis as analysts' estimates and that many investors use this published research in making investment decisions and evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income comparable to analysts' estimates on a diluted per share basis. A table is included which reconciles income or loss from operations to adjusted net income comparable to analysts' estimates and diluted earnings per share (adjusted). On its website, the Company provides additional comparative information on prior periods along with non-GAAP revenue disclosures.
Cash flow from operations before changes in working capital (sometimes referred to as "adjusted cash flow") as defined in this release represents net cash provided by operations before changes in working capital and exploration expense adjusted for certain non-cash compensation items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. A table is included which reconciles Net cash provided by operations to Cash flow from operations before changes in working capital as used in this release. On its website, the Company provides additional comparative information on prior periods for cash flow, cash margins and non-GAAP earnings as used in this release.
The cash prices realized for oil and natural gas production including the amounts realized on cash-settled derivatives and net of transportation, gathering 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 income statement. The Company believes that it is important to furnish a table reflecting the details of the various components of each income statement line to better inform the reader of the details of each amount and provide a summary of the realized cash-settled amounts and third-party transportation, gathering and compression expense which historically were reported as natural gas, NGLs and oil sales. This information is intended to bridge the gap between various readers' understanding and fully disclose the information needed.
The Company discloses in this release the detailed components of many of the single line items shown in the GAAP financial statements included in the Company's Annual Report on Form 10-K. The Company believes that it is important to furnish this detail of the various components comprising each line of the Statements of Operations to better inform the reader of the details of each amount, the changes between periods and the effect on its financial results.
Range has disclosed two primary metrics in this release to measure our ability to establish a long-term trend of adding reserves at a reasonable cost -- a reserve replacement ratio and finding and development cost per unit. The reserve replacement ratio is an indicator of our ability to replace annual production volumes and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced. We believe the ability to develop a competitive advantage over other natural gas and oil companies is dependent on adding reserves in our core areas at lower costs than our competition. The reserve replacement ratio is calculated by dividing production for the year into the total of proved reserve extensions, discoveries and additions and proved reserves revisions, excluding PUD removals based on the
Finding and development cost per unit is a non-GAAP metric used in the exploration and production industry by companies, investors and analysts. The calculations presented by the Company are based on estimated and unaudited costs incurred excluding asset retirement obligations and divided by proved reserve additions (extensions, discoveries and additions) adjusted for the changes in proved reserves for acquisitions, performance revisions and/or price revisions and including or excluding acreage costs as stated in each instance in the release. Drill-bit development cost per mcfe is based on estimated and unaudited drilling, development and exploration costs incurred divided by the total of reserve additions, performance and price revisions. These calculations do not include the future development costs required for the development of proved undeveloped reserves. The
The reserve replacement ratio and finding and development cost per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio can be limited because it may vary widely based on the extent and timing of new discoveries and the varying effects of changes in prices and well performance. In addition, since the reserve replacement ratio and finding and development cost per unit do not consider the cost or timing of future production of new reserves, such measures may not be an adequate measure of value creation. These reserves metrics may not be comparable to similarly titled measurements used by other companies.
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 liquidity, production growth, completion of ethane projects, estimated gas in place, future rates of return, future low costs, low reinvestment risk, future earnings and per-share value, future capital spending plans, expected future sales of assets, increasing capital efficiency, well-positioned, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas prices, acreage quality, access to multiple gas markets, expected drilling and development plans, improved capital efficiency, future financial position, future technical improvements, future marketing opportunities 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. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range's filings with the
The
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-K (Unaudited, in thousands, except per share data) | ||||||||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||||
2015 | 2014 | % | 2015 | 2014 | % | |||||||||||||||||
Revenues and other income: | ||||||||||||||||||||||
Natural gas, NGLs and oil sales (a) | $ | 254,043 | $ | 416,388 | $ | 1,089,644 | $ | 1,911,989 | ||||||||||||||
Derivative fair value (loss)/income | 126,312 | 412,422 | 416,364 | 383,520 | ||||||||||||||||||
Brokered natural gas, marketing and other (b) | 30,100 | 31,424 | 90,922 | 123,065 | ||||||||||||||||||
Equity method investment (b) | - | - | - | (277 | ) | |||||||||||||||||
ARO settlement (b) | 80 | 8,196 | 103 | 7,545 | ||||||||||||||||||
Other (b) | 192 | 24 | 1,035 | 215 | ||||||||||||||||||
Total revenues and other income | 410,727 | 868,454 | -53 | % | 1,598,068 | 2,426,057 | -34 | % | ||||||||||||||
Costs and expenses: | ||||||||||||||||||||||
Direct operating | 28,757 | 37,262 | 133,583 | 146,275 | ||||||||||||||||||
Direct operating - non-cash stock-based compensation (c) | 631 | 699 | 2,780 | 4,208 | ||||||||||||||||||
Transportation, gathering and compression | 112,481 | 89,542 | 396,739 | 325,289 | ||||||||||||||||||
Production and ad valorem taxes | 7,354 | 11,923 | 33,860 | 44,555 | ||||||||||||||||||
Brokered natural gas and marketing | 34,553 | 31,161 | 113,734 | 126,457 | ||||||||||||||||||
Brokered natural gas and marketing - non-cash stock-based compensation (c) | 389 | 1,209 | 2,132 | 3,523 | ||||||||||||||||||
Exploration | 3,446 | 22,477 | 18,421 | 58,979 | ||||||||||||||||||
Exploration - non-cash stock-based compensation (c) | 814 | 1,161 | 2,985 | 4,569 | ||||||||||||||||||
Abandonment and impairment of unproved properties | 11,432 | 14,308 | 47,619 | 47,079 | ||||||||||||||||||
General and administrative | 29,476 | 39,034 | 136,290 | 148,888 | ||||||||||||||||||
General and administrative - non-cash stock-based compensation (c) | 11,142 | 11,526 | 49,687 | 55,382 | ||||||||||||||||||
General and administrative - lawsuit settlements | 1,226 | 804 | 3,238 | 3,007 | ||||||||||||||||||
General and administrative - bad debt expense | 1,700 | - | 2,300 | 250 | ||||||||||||||||||
General and administrative - legal contingency (DEP penalty in prior year) | - | 999 | 2,500 | 5,899 | ||||||||||||||||||
Termination costs | 10,283 | 5,372 | 14,853 | 5,372 | ||||||||||||||||||
Termination costs - non-cash stock-based compensation (c) | (1,503 | ) | 2,999 | 217 | 2,999 | |||||||||||||||||
Deferred compensation plan (d) | (21,016 | ) | (36,836 | ) | (77,627 | ) | (74,550 | ) | ||||||||||||||
Interest expense | 40,849 | 38,900 | 166,439 | 168,977 | ||||||||||||||||||
Loss on early extinguishment of debt | - | - | 22,495 | 24,596 | ||||||||||||||||||
Depletion, depreciation and amortization | 127,977 | 146,539 | 581,155 | 551,032 | ||||||||||||||||||
Impairment of proved properties and other assets | 87,941 | 3,033 | 590,174 | 28,024 | ||||||||||||||||||
Loss (gain) on sale of assets | 408,909 | (3,760 | ) | 406,856 | (285,638 | ) | ||||||||||||||||
Total costs and expenses | 896,841 | 418,352 | 114 | % | 2,650,430 | 1,395,172 | 90 | % | ||||||||||||||
(Loss) income before income taxes | (486,114 | ) | 450,102 | -208 | % | (1,052,362 | ) | 1,030,885 | -202 | % | ||||||||||||
Income tax (benefit) expense: | ||||||||||||||||||||||
Current | 29 | (4 | ) | 29 | 1 | |||||||||||||||||
Deferred | (164,316 | ) | 166,052 | (338,706 | ) | 396,502 | ||||||||||||||||
(164,287 | ) | 166,048 | (338,677 | ) | 396,503 | |||||||||||||||||
Net (loss) income | $ | (321,827 | ) | $ | 284,054 | -213 | % | $ | (713,685 | ) | $ | 634,382 | -213 | % | ||||||||
Net (Loss) Income Per Common Share: | ||||||||||||||||||||||
Basic | $ | (1.93 | ) | $ | 1.68 | $ | (4.29 | ) | $ | 3.81 | ||||||||||||
Diluted | $ | (1.93 | ) | $ | 1.68 | $ | (4.29 | ) | $ | 3.79 | ||||||||||||
Weighted average common shares outstanding, as reported: | ||||||||||||||||||||||
Basic | 166,573 | 165,877 | 0 | % | 166,389 | 163,625 | 2 | % | ||||||||||||||
Diluted | 166,573 | 166,164 | 0 | % | 166,389 | 164,403 | 1 | % | ||||||||||||||
(a) | See separate natural gas, NGLs and oil sales information table. | |
(b) | Included in Brokered natural gas, marketing and other revenues in the 10-K. | |
(c) | Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct personnel costs, which are combined with the cash costs in the 10-K. | |
(d) | Reflects the change in market value of the vested Company stock held in the deferred compensation plan. | |
RANGE RESOURCES CORPORATION |
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BALANCE SHEETS | ||||||||||
(In thousands) | December 31, | December 31, | ||||||||
2015 | 2014 | |||||||||
(Audited) | (Audited) | |||||||||
Assets | ||||||||||
Current assets | $ | 157,530 | $ | 207,243 | ||||||
Derivative assets | 288,762 | 403,363 | ||||||||
Natural gas and oil properties, successful efforts method | 6,361,305 | 7,977,573 | ||||||||
Transportation and field assets | 19,455 | 37,581 | ||||||||
Other | 72,979 | 78,844 | ||||||||
$ | 6,900,031 | $ | 8,704,604 | |||||||
Liabilities and Stockholders' Equity | ||||||||||
Current liabilities | $ | 335,513 | $ | 624,610 | ||||||
Asset retirement obligations | 15,071 | 15,067 | ||||||||
Derivative liabilities | 1,136 | - | ||||||||
Bank debt | 86,427 | 713,221 | ||||||||
Senior notes | 738,101 | - | ||||||||
Senior subordinated notes | 1,826,775 | 2,317,603 | ||||||||
2,651,303 | 3,030,824 | |||||||||
Deferred tax liability | 777,947 | 1,113,081 | ||||||||
Derivative liabilities | 21 | - | ||||||||
Deferred compensation liability | 104,792 | 178,599 | ||||||||
Asset retirement obligations and other liabilities | 254,590 | 284,994 | ||||||||
1,137,350 | 1,576,674 | |||||||||
Common stock and retained earnings | 2,761,903 | 3,460,517 | ||||||||
Common stock held in treasury stock | (2,245 | ) | (3,088 | ) | ||||||
Total stockholders' equity | 2,759,658 | 3,457,429 | ||||||||
$ | 6,900,031 | $ | 8,704,604 | |||||||
RECONCILIATION OF TOTAL REVENUES AND OTHER INCOME TO TOTAL REVENUE EXCLUDING CERTAIN ITEMS, a non-GAAP measure | ||||||||||||||||||||
(Unaudited, in thousands) | Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||
2015 | 2014 | % | 2015 | 2014 | % | |||||||||||||||
Total revenues and other income, as reported | $ | 410,727 | $ | 868,454 | -53 | % | $ | 1,598,068 | $ | 2,426,057 | -34 | % | ||||||||
Adjustment for certain special items: | ||||||||||||||||||||
Total change in fair value related to derivatives prior to settlement (gain) loss | 45,165 | (341,197 | ) | 115,758 | (426,154 | ) | ||||||||||||||
ARO settlement (gain) loss | (80 | ) | (8,196 | ) | (103 | ) | (7,545 | ) | ||||||||||||
Total revenues, as adjusted, non-GAAP | $ | 455,812 | $ | 519,061 | -12 | % | $ | 1,713,723 | $ | 1,992,358 | -14 | % | ||||||||
RANGE RESOURCES CORPORATION | |||||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||||
(Unaudited, in thousands) | Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||||||
Net (loss) income | $ | (321,827 | ) | $ | 284,054 | $ | (713,685 | ) | $ | 634,382 | |||||||||
Adjustments to reconcile net cash provided from continuing operations: | |||||||||||||||||||
(Gain) loss from equity method investment, net of distributions | - | (1 | ) | - | 3,095 | ||||||||||||||
Deferred income tax (benefit) expense | (164,316 | ) | 166,052 | (338,706 | ) | 396,502 | |||||||||||||
Depletion, depreciation, amortization and impairment | 215,918 | 149,572 | 1,171,329 | 579,056 | |||||||||||||||
Exploration dry hole costs | 1 | 16,144 | 88 | 16,145 | |||||||||||||||
Abandonment and impairment of unproved properties | 11,432 | 14,308 | 47,619 | 47,079 | |||||||||||||||
Derivative fair value (income) loss | (126,312 | ) | (412,422 | ) | (416,364 | ) | (383,520 | ) | |||||||||||
Cash settlements on derivative financial instruments that do not qualify for hedge accounting | 171,477 | 71,225 | 532,122 | (42,634 | ) | ||||||||||||||
Allowance for bad debts | 1,700 | - | 2,300 | 250 | |||||||||||||||
Amortization of deferred issuance costs, loss on extinguishment of debt, and other | 1,811 | (6,736 | ) | 29,383 | 24,694 | ||||||||||||||
Deferred and stock-based compensation | (9,732 | ) | (19,781 | ) | (20,411 | ) | (4,295 | ) | |||||||||||
(Gain) loss on sale of assets and other | 408,909 | (3,760 | ) | 406,856 | (285,638 | ) | |||||||||||||
Changes in working capital: | |||||||||||||||||||
Accounts receivable | (14,744 | ) | (18,427 | ) | 64,704 | (5,329 | ) | ||||||||||||
Inventory and other | (7,795 | ) | 814 | (14,868 | ) | (4,521 | ) | ||||||||||||
Accounts payable | (13,039 | ) | 12,332 | (26,197 | ) | (1,023 | ) | ||||||||||||
Accrued liabilities and other | 14,657 | 45,823 | (40,470 | ) | (20,108 | ) | |||||||||||||
Net changes in working capital | (20,921 | ) | 40,542 | (16,831 | ) | (30,981 | ) | ||||||||||||
Net cash provided from operating activities | $ | 168,140 | $ | 299,197 | $ | 683,700 | $ | 954,135 | |||||||||||
RECONCILIATION OF NET CASH PROVIDED FROM OPERATING ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP measure | |||||||||||||||||
(Unaudited, in thousands) | Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||||
Net cash provided from operating activities, as reported | $ | 168,140 | $ | 299,197 | $ | 683,700 | $ | 954,135 | |||||||||
Net changes in working capital | 20,921 | (40,542 | ) | 16,831 | 30,981 | ||||||||||||
Exploration expense | 3,445 | 6,333 | 18,333 | 42,834 | |||||||||||||
Lawsuit settlements | 1,226 | 804 | 3,238 | 3,007 | |||||||||||||
Legal contingency/DEP penalty | - | 999 | 2,500 | 5,899 | |||||||||||||
Equity method investment distribution / intercompany elimination | - | - | - | (2,819 | ) | ||||||||||||
Termination costs | 10,140 | 5,372 | 14,710 | 5,372 | |||||||||||||
Non-cash compensation adjustment | 216 | 661 | 852 | 907 | |||||||||||||
Cash flow from operations before changes in working capital - a non-GAAP measure | $ | 204,088 | $ | 272,824 | $ | 740,164 | $ | 1,040,316 | |||||||||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | |||||||||||||||||
(Unaudited, in thousands) | Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||||
Basic: | |||||||||||||||||
Weighted average shares outstanding | 169,371 | 168,705 | 169,183 | 166,439 | |||||||||||||
Stock held by deferred compensation plan | (2,798 | ) | (2,828 | ) | (2,794 | ) | (2,814 | ) | |||||||||
Adjusted basic | 166,573 | 165,877 | 166,389 | 163,625 | |||||||||||||
Dilutive: | |||||||||||||||||
Weighted average shares outstanding | 169,371 | 168,705 | 169,183 | 166,439 | |||||||||||||
Dilutive stock options under treasury method | (2,798 | ) | (2,541 | ) | (2,794 | ) | (2,036 | ) | |||||||||
Adjusted dilutive | 166,573 | 166,164 | 166,389 | 164,403 | |||||||||||||
RANGE RESOURCES CORPORATION | |||||||||||||||||||||
RECONCILIATION OF NATURAL GAS, NGLs AND OIL SALES AND DERIVATIVE FAIR VALUE INCOME (LOSS) TO CALCULATED CASH REALIZED NATURAL GAS, NGLs AND OIL PRICES WITH AND WITHOUT THIRD PARTY TRANSPORTATION, GATHERING AND COMPRESSION FEES, a non-GAAP measure | |||||||||||||||||||||
(Unaudited, in thousands, except per unit data) | Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||
2015 | 2014 | % | 2015 | 2014 | % | ||||||||||||||||
Natural gas, NGL and oil sales components: | |||||||||||||||||||||
Natural gas sales | $ | 183,576 | $ | 266,475 | $ | 773,093 | $ | 1,140,989 | |||||||||||||
NGL sales | 44,724 | 88,792 | 176,546 | 444,152 | |||||||||||||||||
Oil sales | 25,743 | 61,479 | 140,005 | 316,625 | |||||||||||||||||
Cash-settled hedges (effective): | |||||||||||||||||||||
Natural gas | - | (2,074 | ) | - | 4,686 | ||||||||||||||||
Crude oil | - | 1,716 | - | 5,537 | |||||||||||||||||
Total oil and gas sales, as reported | $ | 254,043 | $ | 416,388 | -39 | % | $ | 1,089,644 | $ | 1,911,989 | -43 | % | |||||||||
Derivative fair value income (loss), as reported: | $ | 126,312 | $ | 412,422 | $ | 416,364 | $ | 383,520 | |||||||||||||
Cash settlements on derivative financial instruments - (gain) loss: | |||||||||||||||||||||
Natural gas | (115,428 | ) | (25,541 | ) | (339,031 | ) | 58,442 | ||||||||||||||
NGLs | (10,366 | ) | (26,551 | ) | (41,974 | ) | (13,437 | ) | |||||||||||||
Crude Oil | (45,683 | ) | (19,133 | ) | (151,117 | ) | (2,371 | ) | |||||||||||||
Total change in fair value related to derivatives prior to settlement, a non-GAAP measure | $ | (45,165 | ) | $ | 341,197 | $ | (115,758 | ) | $ | 426,154 | |||||||||||
Transportation, gathering and compression components: | |||||||||||||||||||||
Natural gas | $ | 95,849 | $ | 76,682 | $ | 343,593 | $ | 282,447 | |||||||||||||
NGLs | 16,632 | 12,860 | 53,146 | 42,842 | |||||||||||||||||
Total transportation, gathering and compression, as reported | $ | 112,481 | $ | 89,542 | $ | 396,739 | $ | 325,289 | |||||||||||||
Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | |||||||||||||||||||||
Natural gas sales | $ | 299,004 | $ | 289,942 | $ | 1,112,124 | $ | 1,087,233 | |||||||||||||
NGL sales | 55,090 | 115,343 | 218,520 | 457,589 | |||||||||||||||||
Oil sales | 71,426 | 82,328 | 291,122 | 324,533 | |||||||||||||||||
Total | $ | 425,520 | $ | 487,613 | -13 | % | $ | 1,621,766 | $ | 1,869,355 | -13 | % | |||||||||
Production of oil and gas during the periods (a): | |||||||||||||||||||||
Natural gas (mcf) | 97,175,602 | 81,481,720 | 19 | % | 362,686,707 | 286,926,099 | 26 | % | |||||||||||||
NGL (bbl) | 4,906,615 | 4,943,309 | -1 | % | 20,356,110 | 18,820,526 | 8 | % | |||||||||||||
Oil (bbl) | 897,064 | 1,059,514 | -15 | % | 4,084,069 | 4,069,568 | 0 | % | |||||||||||||
Gas equivalent (mcfe) (b) | 131,997,676 | 117,498,658 | 12 | % | 509,327,781 | 424,266,663 | 20 | % | |||||||||||||
Production of oil and gas - average per day (a): | |||||||||||||||||||||
Natural gas (mcf) | 1,056,257 | 885,671 | 19 | % | 993,662 | 786,099 | 26 | % | |||||||||||||
NGL (bbl) | 53,333 | 53,732 | -1 | % | 55,770 | 51,563 | 8 | % | |||||||||||||
Oil (bbl) | 9,751 | 11,516 | -15 | % | 11,189 | 11,150 | 0 | % | |||||||||||||
Gas equivalent (mcfe) (b) | 1,434,757 | 1,277,159 | 12 | % | 1,395,419 | 1,162,374 | 20 | % | |||||||||||||
Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | |||||||||||||||||||||
Natural gas (mcf) | $ | 1.89 | $ | 3.24 | -42 | % | $ | 2.13 | $ | 3.99 | -47 | % | |||||||||
NGL (bbl) | $ | 9.12 | $ | 17.96 | -49 | % | $ | 8.67 | $ | 23.60 | -63 | % | |||||||||
Oil (bbl) | $ | 28.70 | $ | 59.65 | -52 | % | $ | 34.28 | $ | 79.16 | -57 | % | |||||||||
Gas equivalent (mcfe) (b) | $ | 1.92 | $ | 3.54 | -46 | % | $ | 2.14 | $ | 4.51 | -53 | % | |||||||||
Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | |||||||||||||||||||||
Natural gas (mcf) | $ | 3.08 | $ | 3.56 | -14 | % | $ | 3.07 | $ | 3.79 | -19 | % | |||||||||
NGL (bbl) | $ | 11.23 | $ | 23.33 | -52 | % | $ | 10.73 | $ | 24.31 | -56 | % | |||||||||
Oil (bbl) | $ | 79.62 | $ | 77.70 | 2 | % | $ | 71.28 | $ | 79.75 | -11 | % | |||||||||
Gas equivalent (mcfe) (b) | $ | 3.22 | $ | 4.15 | -22 | % | $ | 3.18 | $ | 4.41 | -28 | % | |||||||||
Average prices, including cash-settled hedges and derivatives: (d) | |||||||||||||||||||||
Natural gas (mcf) | $ | 2.09 | $ | 2.62 | -20 | % | $ | 2.12 | $ | 2.80 | -24 | % | |||||||||
NGL (bbl) | $ | 7.84 | $ | 20.73 | -62 | % | $ | 8.12 | $ | 22.04 | -63 | % | |||||||||
Oil (bbl) | $ | 79.62 | $ | 77.70 | 2 | % | $ | 71.28 | $ | 79.75 | -11 | % | |||||||||
Gas equivalent (mcfe) (b) | $ | 2.37 | $ | 3.39 | -30 | % | $ | 2.41 | $ | 3.64 | -34 | % | |||||||||
Transportation, gathering and compression expense per mcfe | $ | 0.85 | $ | 0.76 | 12 | % | $ | 0.78 | $ | 0.77 | 2 | % | |||||||||
(a) | Represents volumes sold regardless of when produced. | |
(b) | Oil and NGLs are converted at the rate of one barrel equals six mcfe based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices. | |
(c) | Excluding third party transportation, gathering and compression costs. | |
(d) | Net of transportation, gathering and compression costs. | |
RANGE RESOURCES CORPORATION | |||||||||||||||||||||
RECONCILIATION OF (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AS REPORTED TO INCOME FROM OPERATIONS BEFORE INCOME TAXES EXCLUDING CERTAIN ITEMS, a non-GAAP measure | |||||||||||||||||||||
(Unaudited, in thousands, except per share data) | Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||||
2015 | 2014 | % | 2015 | 2014 | % | ||||||||||||||||
(Loss) income from operations before income taxes, as reported | $ | (486,114 | ) | $ | 450,102 | -208 | % | $ | (1,052,362 | ) | $ | 1,030,885 | -202 | % | |||||||
Adjustment for certain special items: | |||||||||||||||||||||
Loss (gain) on sale of assets | 408,909 | (3,760 | ) | 406,856 | (285,638 | ) | |||||||||||||||
(Gain) loss on ARO settlements | (80 | ) | (8,196 | ) | (103 | ) | (7,545 | ) | |||||||||||||
Change in fair value related to derivatives prior to settlement | 45,165 | (341,197 | ) | 115,758 | (426,154 | ) | |||||||||||||||
Abandonment and impairment of unproved properties | 11,432 | 14,308 | 47,619 | 47,079 | |||||||||||||||||
Loss on early extinguishment of debt | - | - | 22,495 | 24,596 | |||||||||||||||||
Impairment of proved property and other assets | 87,941 | 3,033 | 590,174 | 28,024 | |||||||||||||||||
Lawsuit settlements | 1,226 | 804 | 3,238 | 3,007 | |||||||||||||||||
DEP penalty | - | 999 | - | 5,899 | |||||||||||||||||
Legal contingency | - | - | 2,500 | - | |||||||||||||||||
Termination costs | 10,283 | 5,372 | 14,853 | 5,372 | |||||||||||||||||
Termination costs - non-cash stock-based compensation | (1,503 | ) | 2,999 | 217 | 2,999 | ||||||||||||||||
Brokered natural gas and marketing - non-cash stock-based compensation | 389 | 1,209 | 2,132 | 3,523 | |||||||||||||||||
Direct operating - non-cash stock-based compensation | 631 | 699 | 2,780 | 4,208 | |||||||||||||||||
Exploration expenses - non-cash stock-based compensation | 814 | 1,161 | 2,985 | 4,569 | |||||||||||||||||
General & administrative - non-cash stock-based compensation | 11,142 | 11,526 | 49,687 | 55,382 | |||||||||||||||||
Deferred compensation plan - non-cash adjustment | (21,016 | ) | (36,836 | ) | (77,627 | ) | (74,550 | ) | |||||||||||||
Income from operations before income taxes, as adjusted | 69,219 | 102,223 | -32 | % | 131,202 | 421,656 | -69 | % | |||||||||||||
Income tax expense, as adjusted | |||||||||||||||||||||
Current | 29 | (4 | ) | 29 | 1 | ||||||||||||||||
Deferred | 27,431 | 37,680 | 50,777 | 161,460 | |||||||||||||||||
Net income excluding certain items, a non-GAAP measure | $ | 41,759 | $ | 64,547 | -35 | % | $ | 80,396 | $ | 260,195 | -69 | % | |||||||||
Non-GAAP income per common share | |||||||||||||||||||||
Basic | $ | 0.25 | $ | 0.39 | -36 | % | $ | 0.48 | $ | 1.59 | -70 | % | |||||||||
Diluted | $ | 0.25 | $ | 0.39 | -36 | % | $ | 0.48 | $ | 1.58 | -70 | % | |||||||||
Non-GAAP diluted shares outstanding, if dilutive | 166,881 | 166,164 | 166,432 | 164,403 | |||||||||||||||||
RANGE RESOURCES CORPORATION |
HEDGING POSITION AS OF
(Unaudited)
Daily Volume | Hedge Price | |||
Gas (Mmbtu) | ||||
2016 Swaps | 745,874 | $3.24 | ||
2017 Swaps | 20,000 | $3.49 | ||
Oil (Bbls) | ||||
2016 Swaps | 4,247 | $65.27 | ||
2017 Swaps | 500 | $55.00 | ||
C3 Propane (Bbls) | ||||
2016 Swaps | 5,500 | $0.60 | ||
C4 Normal Butane (Bbls) | ||||
2016 Swaps | 2,688 | $0.71 | ||
C5 Natural Gasoline (Bbls) | ||||
2016 Swaps | 2,749 | $1.20 | ||
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS |
Investor Contacts:
Senior Vice President
817-869-4258
rwaller@rangeresources.com
Vice President - Investor Relations
817-869-4267
lsando@rangeresources.com
Investor Relations Manager
817-869-4266
damend@rangeresources.com
Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
Media Contact:
Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
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