Range Reports Outstanding 2014 Results
2014 Highlights -
- Record annual average daily production of 1,162 Mmcfe per day, an increase of 24% over 2013
- Record adjusted annual cash flow of
$1 billion , an increase of 10% over 2013 - Unit costs reduced by
$0.35 per mcfe or 10% versus 2013 - Total proved reserves increased by 26% to 10.3 Tcfe
- Reserve replacement of 581% at
$0.64 per mcfe all-in finding and development cost - Unrisked resource potential increased to a range of 66 to 87 Tcfe
- Reported net income for 2014 was
$634 million versus$116 million in 2013
Production for 2014 averaged 1,162 Mmcfe per day with 32% liquids, a 24% increase over 2013. Fourth quarter 2014 production increased 26% over the prior-year period to 1,277 Mmcfe per day with 31% liquids, another record high for Range and was 6% higher than third quarter 2014. Oil and natural gas liquid ("NGL") production increased 53% over the prior-year fourth quarter.
Proved reserves increased 26% year-over-year to 10.3 Tcfe, driven by a 1.2 Tcfe increase in proved developed producing reserves. All-in finding and development cost averaged
Commenting,
While we begin 2015 with lower commodity prices, we are well positioned. Besides beginning the year with lower debt, we have extended our credit facility providing over
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 tax, 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 2014
GAAP revenues for 2014 totaled
Non-GAAP revenues for 2014 totaled
The Company announced its full year 2014 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 2014 were: natural gas - 786 Mmcf per day (
$3.79 per mcf), NGLs - 51,563 barrels per day ($24.31 per barrel) and crude oil and condensate - 11,150 barrels per day ($79.75 per barrel). - The 2014 average natural gas price improved
$0.37 per mcf, before hedging settlements, as compared to the prior year. Financial hedges based upon NYMEX decreased realizations$0.11 per mcf while financial basis hedges decreased realizations$0.09 per mcf primarily driven by extreme cold weather in first quarter 2014. The average Company natural gas differential including the settled financial basis hedges but before NYMEX hedging for 2014 was($0.48) per mcf compared to($0.06) per mcf in the prior year. - NGL pricing, before hedges, was 26% of the West Texas Intermediate index ("WTI") for 2014 compared to 35% of WTI in 2013. The change was primarily a result of removing ethane from the gas stream and adding the production to the NGL mix near the start of 2014.
- Crude oil and condensate price realizations, before hedges, for the year averaged 84% of WTI compared to 88% in 2013.
Fourth Quarter
GAAP revenues for the fourth quarter of 2014 totaled
Non-GAAP revenues for fourth quarter 2014 totaled
Fourth quarter 2014 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 the fourth quarter of 2014 were: natural gas - 886 Mmcf per day (
$3.56 per mcf), NGLs - 53,732 barrels per day ($23.33 per barrel) and crude oil and condensate - 11,516 barrels per day ($77.70 per barrel). - The fourth quarter average natural gas price decreased
$0.13 per mcf, before hedging settlements, as compared to the prior-year quarter. Financial hedges based upon NYMEX increased realizations$0.12 per mcf while financial basis hedges increased realizations$0.17 per mcf during the quarter. The average Company natural gas differential including the settled financial basis hedges but before NYMEX hedging for the fourth quarter was($0.57) per mcf compared to($0.22) per mcf in the prior year. - NGL pricing, before hedges, was 25% of WTI for the fourth quarter compared to 37% of WTI in the prior-year quarter. The change was primarily a result of removing ethane from the gas stream and adding the production to the NGL mix near the start of 2014. Fourth quarter NGL price realizations as a percent of WTI improved compared to third quarter 2014 pricing of 23% of WTI. The improvement was largely a result of Range's ethane being priced mostly off natural gas prices.
- Crude oil and condensate price realizations, before hedges, for the fourth quarter averaged 79% of WTI compared to 86% in the prior-year quarter. Crude oil and condensate realizations for third quarter 2014 were 84% of WTI before hedges.
Financial Position and Liquidity
During 2014, Range decreased total debt by
Capital Spending and Cost Overview
Fourth quarter drilling expenditures of
Range has set its 2015 capital spending budget at
With the reduction in its 2015 capital budget in the Midcontinent, Range has elected to consolidate its
Total unit costs for 2014 full year decreased by 10%. Direct operating expense, production taxes and transportation expenses totaled
Total unit costs for the fourth quarter of 2014 decreased by 11% compared to the prior-year quarter. The improving unit costs were led by a 31% decline in interest 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 averaged approximately 1,082 net Mmcfe per day for the
Range has updated well economics and type curves for the planned 2015 Marcellus drilling program, which can be found on the Company's website in the most recent investor presentation. The updated type curves reflect the expected flow restrictions that result from infrastructure and planned facility constraints. The Company manages the development of its Marcellus assets in order to maximize the return of the project. To accomplish this, the infrastructure and facilities are designed to optimize the long-term development of the play, not to maximize the initial production rates of the wells being drilled. As a result, early production from prolific Marcellus wells is often constrained, resulting in flatter decline curves and this is reflected in the updated type curves.
Southern Marcellus Shale Division -
Production for the fourth quarter averaged 823 net Mmcfe per day for the division, a 37% increase over the prior year. The division's fourth quarter net production included 467 Mmcf per day of gas, 50,006 barrels per day of NGLs and 9,271 barrels per day of condensate.
During the fourth quarter, the division brought on line 33 Marcellus wells in southwest
In the super-rich area of southwest
In the wet area of southwest
In the dry area of southwest
In 2014, the Company also drilled a successful
Northern Marcellus Shale Division -
In northeast
Range is currently running one rig in northeast
Marcellus Shale Marketing and Transportation Review -
In
Range also announced that the Company entered into a multi-year contract to sell 5,000 barrels per day of ethane on the
The ATEX pipeline issued a force majeure notice on
Southern Appalachia Division -
Production for the fourth quarter averaged 108 net Mmcf per day for the division, a 48% increase from the prior year due to the mid-year property exchange.
In 2014, Range gained complete operational control over its
Capital spending for Southern Appalachia Division will be targeted to roughly maintain its production levels for the year. The division has the lowest natural decline rate of any of Range's operating areas due to its CBM production.
Midcontinent Division -
Production for the fourth quarter averaged 82 net Mmcfe per day for the division, an 8% decrease from the prior year. The division's fourth quarter production included 47.9 Mmcf per day of gas, 3,625 barrels per day of NGLs and 2,112 barrels per day of oil.
In 2014, Range continued to test the geologic modeling of its Mississippian Chat acreage along the Nemaha Ridge, successfully expanding the play to the north. The division turned 16 Mississippian Chat wells to sales in 2014. The 2014 wells had 30 day rates that were 30% better than 2013 as the Company improved its geological targeting and refined its completion design. In 2015 the Company plans to bring eight Mississippian Chat wells on line.
Guidance - 2015
Production per day Guidance:
Production growth for 2015 is targeted at 20% year-over-year. Production for the first quarter of 2015 is expected to be approximately 1.30 Bcfe per day.
Guidance for 2015 Activity:
Under the current plan, Range expects to turn to sales approximately 148 wells during 2015, as shown below.
Planned Wells to Sales in 2015 | ||||||
Super-Rich area | 26 | |||||
Wet area | 40 | |||||
Dry area (NE & SW) | 49 | |||||
Total Marcellus | 115 | |||||
Nora area | 25 | |||||
Midcontinent | 8 | |||||
Total | 148 | |||||
1Q 2015 Expense Guidance:
Direct operating expense: | $0.31 - $0.33 per mcfe | ||
Transportation, gathering and compression expense: | $0.78 - $0.82 per mcfe | ||
Production tax expense: | $0.09 - $0.10 per mcfe | ||
Exploration expense: | $9 - $11 million | ||
Unproved property impairment expense: | $12 - $14 million | ||
G&A expense: | $0.33 - $0.35 per mcfe | ||
Interest expense: | $0.33 - $0.34 per mcfe | ||
DD&A expense: | $1.24 - $1.26 per mcfe | ||
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 60% of its expected 2015 natural gas production hedged at a weighted average floor price of
Range has also hedged Marcellus and other basis differentials covering 95,000 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 below and 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 will serve 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 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 extensions, discoveries and additions and proved reserves added by performance revisions.
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 shown in the table) adjusted for the changes in proved reserves for acreage, acquisitions, performance revisions and/or price revisions 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 and performance 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.
Year-end pre-tax discounted present value is considered a non-GAAP financial measure as defined by the
Reconciliation of PV-10 ($ in millions) (unaudited) |
|||
December 31, 2014 | |||
Standardized measure of discounted future net of cash flows | $ | 7,593 |
|
Discounted future cash flows for income taxes | 2,477 | ||
Discounted future net cash flows before income taxes (PV-10) | $ | 10,070 | |
Range has disclosed a debt-adjusted per share metric in this release to measure per-share growth of production and reserves. This debt-adjusted metric keeps the debt-to-capitalization ratio unchanged during the calculation period. To achieve a constant debt-to-capitalization ratio, the share count is adjusted to increase/decrease equity from the actual end-of-year to the beginning of period level debt-to-capitalization. This adjustment is made by dividing the necessary increase/decrease in equity by the average common share price during the year for production (year-end price for reserves) to arrive at shares issued/repurchased. The production or reserves are then divided by this adjusted share count to reach the debt-adjusted per share results.
Hedging and Derivatives
In this news release, Range has reclassified within total revenues its financial reporting of the cash settlement of its commodity derivatives. Under this presentation those hedges considered "effective" under ASC 815 are included in "Natural gas, NGLs and oil sales" when settled. For those hedges designated to regions where the historical correlation between NYMEX and regional prices is "non-highly effective" or is "volumetric ineffective" due to sale of the underlying reserves, they are deemed to be "derivatives" and the cash settlements are included in a separate line item shown as "Derivative fair value income (loss)" in the consolidated statements of operations included in the Company's Form 10-K along with the change in mark-to-market valuations of open derivative positions. The Company has provided additional information regarding natural gas, NGLs and oil sales in a supplemental table included with this release, which would correspond to amounts shown by analysts for natural gas, NGLs and oil sales realized, including cash-settled derivatives.
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, 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 and Section 21E of the Securities Exchange Act of 1934. 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 INCOME | |||||||||||||||||||||
Based on GAAP reported earnings with additional | |||||||||||||||||||||
details of items included in each line in Form 10-K | |||||||||||||||||||||
(Audited, in thousands, except per share data) | |||||||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||
2014 | 2013 | % | 2014 | 2013 | % | ||||||||||||||||
Revenues and other income: | |||||||||||||||||||||
Natural gas, NGLs and oil sales (a) | $ | 416,388 | $ | 448,545 | $ | 1,911,989 | $ | 1,715,676 | |||||||||||||
Derivative fair value income/(loss) | 412,422 | (59,355 | ) | 383,520 | (61,825 | ) | |||||||||||||||
Gain on sale of assets | 3,760 | 3,162 | 285,638 | 92,291 | |||||||||||||||||
Brokered natural gas, marketing and other (b) | 31,424 | 14,809 | 123,065 | 55,546 | |||||||||||||||||
Brokered natural gas - blending (b) | - | 22,535 | - | 62,751 | |||||||||||||||||
Equity method investment (b) | - | (79 | ) | (277 | ) | 462 | |||||||||||||||
ARO settlement gain (loss) (b) | 8,196 | (1,924 | ) | 7,545 | (2,938 | ) | |||||||||||||||
Other (b) | 24 | 393 | 215 | 756 | |||||||||||||||||
Total revenues and other income | 872,214 | 428,086 | 104 | % | 2,711,695 | 1,862,719 | 46 | % | |||||||||||||
Costs and expenses: | |||||||||||||||||||||
Direct operating | 37,262 | 33,661 | 146,275 | 125,336 | |||||||||||||||||
Direct operating - non-cash stock-based compensation (c) | 699 | 699 | 4,208 | 2,755 | |||||||||||||||||
Transportation, gathering and compression | 89,542 | 66,820 | 325,289 | 256,242 | |||||||||||||||||
Production and ad valorem taxes | 11,923 | 11,290 | 44,555 | 45,240 | |||||||||||||||||
Brokered natural gas and marketing | 31,161 | 15,344 | 126,457 | 60,113 | |||||||||||||||||
Brokered natural gas and marketing - non-cash stock-based compensation (c) | 1,209 |
542 |
3,523 |
1,852 |
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Brokered natural gas and marketing - blending | - | 25,806 | - | 69,821 | |||||||||||||||||
Exploration | 22,477 | 13,053 | 58,979 | 60,384 | |||||||||||||||||
Exploration - non-cash stock-based compensation (c) | 1,161 | 1,012 | 4,569 | 4,025 | |||||||||||||||||
Abandonment and impairment of unproved properties | 14,308 | 5,852 | 47,079 | 51,918 | |||||||||||||||||
General and administrative | 39,034 | 38,740 | 148,888 | 143,265 | |||||||||||||||||
General and administrative - non-cash stock-based compensation (c) | 11,526 |
21,137 |
55,382 |
55,737 |
|||||||||||||||||
General and administrative - lawsuit settlements | 804 | 330 | 3,007 | 91,919 | |||||||||||||||||
General and administrative - bad debt expense | - | - | 250 | 250 | |||||||||||||||||
General and administrative - DEP penalty | 999 | - | 5,899 | - | |||||||||||||||||
Termination costs | 5,372 | - | 5,372 | - | |||||||||||||||||
Termination costs - non-cash stock-based compensation (c) | 2,999 | - | 2,999 | - | |||||||||||||||||
Deferred compensation plan (d) | (36,836 | ) | 22,039 | (74,550 | ) | 55,296 | |||||||||||||||
Interest expense | 38,900 | 44,955 | 168,977 | 176,557 | |||||||||||||||||
Loss on early extinguishment of debt | - | - | 24,596 | 12,280 | |||||||||||||||||
Depletion, depreciation and amortization | 146,539 | 126,958 | 551,032 | 492,397 | |||||||||||||||||
Impairment of proved properties and other assets | 3,033 | - | 28,024 | 7,753 | |||||||||||||||||
Total costs and expenses | 422,112 | 428,238 | -1 | % | 1,680,810 | 1,713,140 | -2 | % | |||||||||||||
Income before income taxes | 450,102 | (152 | ) | nm | 1,030,885 | 149,579 | 589 | % | |||||||||||||
Income tax expense (benefit): | |||||||||||||||||||||
Current | (4 | ) | (143 | ) | 1 | (143 | ) | ||||||||||||||
Deferred | 166,052 | (28,180 | ) | 396,502 | 34,000 | ||||||||||||||||
166,048 | (28,323 | ) | 396,503 | 33,857 | |||||||||||||||||
Net income | $ | 284,054 | $ | 28,171 | 908 | % | $ | 634,382 | $ | 115,722 | 448 | % | |||||||||
Net Income Per Common Share: | |||||||||||||||||||||
Basic | $ | 1.68 | $ | 0.17 | $ | 3.81 | $ | 0.71 | |||||||||||||
Diluted | $ | 1.68 | $ | 0.17 | $ | 3.79 | $ | 0.70 | |||||||||||||
Weighted average common shares outstanding, as reported: | |||||||||||||||||||||
Basic | 165,877 | 160,555 | 3 | % | 163,625 | 160,438 | 2 | % | |||||||||||||
Diluted | 166,164 | 161,496 | 3 | % | 164,403 | 161,407 | 2 | % | |||||||||||||
(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 directpersonnel costs, and 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, | ||||||||
2014 | 2013 | |||||||||
(Audited) | (Audited) | |||||||||
Assets | ||||||||||
Current assets | $ | 207,243 | $ | 192,466 | ||||||
Derivative assets | 363,049 | 4,421 | ||||||||
Deferred tax assets | - | 51,414 | ||||||||
Natural gas and oil properties, successful efforts method | 7,977,573 | 6,758,437 | ||||||||
Transportation and field assets | 37,581 | 32,784 | ||||||||
Other | 161,334 | 259,564 | ||||||||
$ | 8,746,780 | $ | 7,299,086 | |||||||
Liabilities and Stockholders' Equity | ||||||||||
Current liabilities | $ | 740,197 | $ | 464,326 | ||||||
Asset retirement obligations | 15,067 | 5,037 | ||||||||
Derivative liabilities | - | 26,198 | ||||||||
Bank debt | 723,000 | 500,000 | ||||||||
Subordinated notes | 2,350,000 | 2,640,516 | ||||||||
3,073,000 | 3,140,516 | |||||||||
Deferred tax liability | 997,494 | 771,980 | ||||||||
Derivative liabilities | - | 25 | ||||||||
Deferred compensation liability | 178,599 | 247,537 | ||||||||
Asset retirement obligations and other liabilities | 284,994 | 229,015 | ||||||||
1,461,087 | 1,248,557 | |||||||||
Common stock and retained earnings | 3,460,517 | 2,411,853 | ||||||||
Common stock held in treasury stock | (3,088 | ) | (3,637 | ) | ||||||
3,457,429 | 2,408,216 | |||||||||
Accumulated other comprehensive income | - | 6,236 | ||||||||
Total stockholders' equity | 3,457,429 | 2,414,452 | ||||||||
$ | 8,746,780 | $ | 7,299,086 | |||||||
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, | |||||||||||||||||
2014 | 2013 | % | 2014 | 2013 | % | ||||||||||||||
Total revenues and other income, as reported | $ | 872,214 | $ | 428,086 | 104 | % | $ | 2,711,695 | $ | 1,862,719 | 46 | % | |||||||
Adjustment for certain special items: | |||||||||||||||||||
Total change in fair value related to derivatives prior to settlement (gain) loss | (341,197 | ) | 56,434 | (426,154 | ) | 30,569 | |||||||||||||
ARO settlement (gain) loss | (8,196 | ) | 1,924 | (7,545 | ) | 2,938 | |||||||||||||
(Gain) loss on sale of assets | (3,760 | ) | (3,162 | ) | (285,638 | ) | (92,291 | ) | |||||||||||
Brokered natural gas - blending | - | (22,535 | ) | - | (62,751 | ) | |||||||||||||
Total revenues, as adjusted, non-GAAP | $ | 519,061 | $ | 460,747 | 13 | % | $ | 1,992,358 | $ | 1,741,184 | 14 | % | |||||||
RANGE RESOURCES CORPORATION | |||||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||||
(Audited, in thousands) | Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Net income | $ | 284,054 | $ | 28,171 | $ | 634,382 | $ | 115,722 | |||||||||||
Adjustments to reconcile net income to cash provided from continuing operations: | |||||||||||||||||||
(Gain) loss from equity investment, net of distributions | (1 | ) | (1,799 | ) | 3,095 | (2,973 | ) | ||||||||||||
Deferred income tax expense (benefit) | 166,052 | (28,180 | ) | 396,502 | 34,000 | ||||||||||||||
Depletion, depreciation, amortization and impairment | 149,572 | 126,958 | 579,056 | 500,150 | |||||||||||||||
Exploration dry hole and impairment costs | 16,144 | 1,795 | 16,145 | 5,699 | |||||||||||||||
Abandonment and impairment of unproved properties | 14,308 | 5,852 | 47,079 | 51,918 | |||||||||||||||
Derivative fair value (income) loss | (412,422 | ) | 59,355 | (383,520 | ) | 61,825 | |||||||||||||
Cash settlements on derivative financial instruments that do not qualify for hedge accounting | 71,225 | (2,921 | ) | (42,634 | ) | (31,256 | ) | ||||||||||||
Allowance for bad debts | - | - | 250 | 250 | |||||||||||||||
Amortization of deferred issuance costs, loss on extinguishment of debt and other | (6,736 | ) | 4,131 | 24,694 | 23,866 | ||||||||||||||
Deferred and stock-based compensation | (19,781 | ) | 45,211 | (4,295 | ) | 119,398 | |||||||||||||
Gain on sale of assets | (3,760 | ) | (3,162 | ) | (285,638 | ) | (92,291 | ) | |||||||||||
Changes in working capital: | |||||||||||||||||||
Accounts receivable | (18,427 | ) | (27,720 | ) | (5,329 | ) | (21,212 | ) | |||||||||||
Inventory and other | 814 | 526 | (4,521 | ) | 3,785 | ||||||||||||||
Accounts payable | 12,332 | 15,679 | (1,023 | ) | (13,555 | ) | |||||||||||||
Accrued liabilities and other | 45,823 | 16,776 | (20,108 | ) | (11,788 | ) | |||||||||||||
Net changes in working capital | 40,542 | 5,261 | (30,981 | ) | (42,770 | ) | |||||||||||||
Net cash provided from operating activities | $ | 299,197 | $ | 240,672 | $ | 954,135 | $ | 743,538 | |||||||||||
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, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
Net cash provided from operating activities, as reported | $ | 299,197 | $ | 240,672 | $ | 954,135 | $ | 743,538 | |||||||||
Net changes in working capital | (40,542 | ) | (5,261 | ) | 30,981 | 42,770 | |||||||||||
Exploration expense | 6,333 | 11,258 | 42,834 | 54,685 | |||||||||||||
Lawsuit settlements | 804 | 330 | 3,007 | 91,919 | |||||||||||||
DEP penalty | 999 | - | 5,899 | - | |||||||||||||
Equity method investment distribution / intercompany elimination | - | 1,877 | (2,819 | ) | 2,509 | ||||||||||||
Loss on gas blending | - | 3,271 | - | 7,070 | |||||||||||||
Termination costs | 5,372 | - | 5,372 | - | |||||||||||||
Non-cash compensation adjustment | 661 | 331 | 907 | 767 | |||||||||||||
Cash flow from operations before changes in working capital - a non-GAAP measure | $ | 272,824 | $ | 252,478 | $ | 1,040,316 | $ | 943,258 | |||||||||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | |||||||||||||||||
(Audited, in thousands) | Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
Basic: | |||||||||||||||||
Weighted average shares outstanding | 168,705 | 163,425 | 166,439 | 163,223 | |||||||||||||
Stock held by deferred compensation plan | (2,828 | ) | (2,870 | ) | (2,814 | ) | (2,785 | ) | |||||||||
Adjusted basic | 165,877 | 160,555 | 163,625 | 160,438 | |||||||||||||
Dilutive: | |||||||||||||||||
Weighted average shares outstanding | 168,705 | 163,425 | 166,439 | 163,223 | |||||||||||||
Dilutive stock options under treasury method | (2,541 | ) | (1,929 | ) | (2,036 | ) | (1,816 | ) | |||||||||
Adjusted dilutive | 166,164 | 161,496 | 164,403 | 161,407 | |||||||||||||
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 | ||||||||||||||||||
non-GAAP measures | ||||||||||||||||||
(Unaudited, in thousands, except per unit data) | Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||
2014 | 2013 | % | 2014 | 2013 | % | |||||||||||||
Natural gas, NGL and oil sales components: | ||||||||||||||||||
Natural gas sales | $ | 266,475 | $ | 236,497 | $ | 1,140,989 | $ | 954,673 | ||||||||||
NGL sales | 88,792 | 103,797 | 444,152 | 315,272 | ||||||||||||||
Oil sales | 61,479 | 86,125 | 316,625 | 329,182 | ||||||||||||||
Cash-settled hedges (effective): | ||||||||||||||||||
Natural gas | (2,074 | ) | 20,255 | 4,686 | 110,948 | |||||||||||||
Crude oil | 1,716 | 1,871 | 5,537 | 5,601 | ||||||||||||||
Total oil and gas sales, as reported | $ | 416,388 | $ | 448,545 | -7 | % | $ | 1,911,989 | $ | 1,715,676 | 11 | % | ||||||
Derivative fair value income (loss), as reported: | $ | 412,422 | $ | (59,355 | ) | $ | 383,520 | $ | (61,825 | ) | ||||||||
Cash settlements on derivative financial instruments - gain (loss): | ||||||||||||||||||
Natural gas | (25,541 | ) | (10,268 | ) | 58,442 | 8,090 | ||||||||||||
NGLs | (26,551 | ) | 10,807 | (13,437 | ) | 12,566 | ||||||||||||
Crude Oil | (19,133 | ) | 2,382 | (2,371 | ) | 10,600 | ||||||||||||
Total change in fair value related to derivatives prior to settlement, a non GAAP measure | $ | 341,197 | $ | (56,434 | ) | $ | 426,154 | $ | (30,569 | ) | ||||||||
Transportation, gathering and compression components: | ||||||||||||||||||
Natural gas | $ | 76,682 | $ | 63,556 | $ | 282,446 | $ | 243,127 | ||||||||||
NGLs | 12,860 | 3,264 | 42,843 | 13,115 | ||||||||||||||
Total transportation, gathering and compression, as reported | $ | 89,542 | $ | 66,820 | $ | 325,289 | $ | 256,242 | ||||||||||
Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | ||||||||||||||||||
Natural gas sales | $ | 289,942 | $ | 267,020 | $ | 1,087,233 | $ | 1,057,531 | ||||||||||
NGL sales | 115,343 | 92,990 | 457,589 | 302,706 | ||||||||||||||
Oil sales | 82,328 | 85,614 | 324,533 | 324,183 | ||||||||||||||
Total | $ | 487,613 | $ | 445,624 | 9 | % | $ | 1,869,355 | $ | 1,684,420 | 11 | % | ||||||
Production of oil and gas during the periods (a): | ||||||||||||||||||
Natural gas (mcf) | 81,481,720 | 69,553,207 | 17 | % | 286,926,099 | 264,528,254 | 8 | % | ||||||||||
NGL (bbl) | 4,943,309 | 2,887,548 | 71 | % | 18,820,526 | 9,254,801 | 103 | % | ||||||||||
Oil (bbl) | 1,059,514 | 1,032,299 | 3 | % | 4,069,568 | 3,827,491 | 6 | % | ||||||||||
Gas equivalent (mcfe) (b) | 117,498,658 | 93,072,289 | 26 | % | 424,266,663 | 343,022,006 | 24 | % | ||||||||||
Production of oil and gas - average per day (a): | ||||||||||||||||||
Natural gas (mcf) | 885,671 | 756,013 | 17 | % | 786,099 | 724,735 | 8 | % | ||||||||||
NGL (bbl) | 53,732 | 31,386 | 71 | % | 51,563 | 25,356 | 103 | % | ||||||||||
Oil (bbl) | 11,516 | 11,221 | 3 | % | 11,150 | 10,486 | 6 | % | ||||||||||
Gas equivalent (mcfe) (b) | 1,277,159 | 1,011,655 | 26 | % | 1,162,374 | 939,786 | 24 | % | ||||||||||
Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | ||||||||||||||||||
Natural gas (mcf) | $ | 3.24 | $ | 3.69 | -12 | % | $ | 3.99 | $ | 4.03 | -1 | % | ||||||
NGL (bbl) | $ | 17.96 | $ | 35.95 | -50 | % | $ | 23.60 | $ | 34.07 | -31 | % | ||||||
Oil (bbl) | $ | 59.65 | $ | 85.24 | -30 | % | $ | 79.16 | $ | 87.47 | -9 | % | ||||||
Gas equivalent (mcfe) (b) | $ | 3.54 | $ | 4.82 | -26 | % | $ | 4.51 | $ | 5.00 | -10 | % | ||||||
Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | ||||||||||||||||||
Natural gas (mcf) | $ | 3.56 | $ | 3.84 | -7 | % | $ | 3.79 | $ | 4.00 | -5 | % | ||||||
NGL (bbl) | $ | 23.33 | $ | 32.20 | -28 | % | $ | 24.31 | $ | 32.71 | -26 | % | ||||||
Oil (bbl) | $ | 77.70 | $ | 82.94 | -6 | % | $ | 79.75 | $ | 84.70 | -6 | % | ||||||
Gas equivalent (mcfe) (b) | $ | 4.15 | $ | 4.79 | -13 | % | $ | 4.41 | $ | 4.91 | -10 | % | ||||||
Average prices, including cash-settled hedges and derivatives: (d) | ||||||||||||||||||
Natural gas (mcf) | $ | 2.62 | $ | 2.93 | -11 | % | $ | 2.80 | $ | 3.08 | -9 | % | ||||||
NGL (bbl) | $ | 20.73 | $ | 31.07 | -33 | % | $ | 22.04 | $ | 31.29 | -30 | % | ||||||
Oil (bbl) | $ | 77.70 | $ | 82.94 | -6 | % | $ | 79.75 | $ | 84.70 | -6 | % | ||||||
Gas equivalent (mcfe) (b) | $ | 3.39 | $ | 4.07 | -17 | % | $ | 3.64 | $ | 4.16 | -13 | % | ||||||
Transportation, gathering and compression expense per mcfe | $ | 0.76 | $ | 0.72 | 6 | % | $ | 0.77 | $ | 0.75 | 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. | |
RANGE RESOURCES CORPORATION |
|||||||||||||||||||
RECONCILIATION OF INCOME (LOSS) BEFORE INCOME TAXES AS REPORTED TO INCOME BEFORE INCOME TAXES EXCLUDING CERTAIN ITEMS, a non-GAAP measure | |||||||||||||||||||
(Unaudited, in thousands, except per share data) | Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||||
2014 | 2013 | % | 2014 | 2013 | % | ||||||||||||||
Income (loss) before income taxes, as reported | $ | 450,102 | $ | (152 | ) | nm | $ | 1,030,885 | $ | 149,579 | 589 | % | |||||||
Adjustment for certain special items: | |||||||||||||||||||
(Gain) loss on sale of assets | (3,760 | ) | (3,162 | ) | (285,638 | ) | (92,291 | ) | |||||||||||
(Gain) loss on ARO settlements | (8,196 | ) | 1,924 | (7,545 | ) | 2,938 | |||||||||||||
Change in fair value related to derivatives prior to settlement | (341,197 | ) | 56,434 | (426,154 | ) | 30,569 | |||||||||||||
Abandonment and impairment of unproved properties | 14,308 | 5,852 | 47,079 | 51,918 | |||||||||||||||
Loss on gas blending - brokered natural gas and marketing | - | 3,271 | - | 7,070 | |||||||||||||||
Loss on early extinguishment of debt | - | - | 24,596 | 12,280 | |||||||||||||||
Impairment of proved property and other assets | 3,033 | - | 28,024 | 7,753 | |||||||||||||||
Lawsuit settlements | 804 | 330 | 3,007 | 91,919 | |||||||||||||||
DEP penalty | 999 | - | 5,899 | - | |||||||||||||||
Termination costs | 5,372 | - | 5,372 | - | |||||||||||||||
Termination costs - non-cash stock-based compensation | 2,999 | - | 2,999 | - | |||||||||||||||
Brokered natural gas and marketing - non-cash stock-based compensation | 1,209 |
542 |
3,523 |
1,852 |
|||||||||||||||
Direct operating - non-cash stock-based compensation | 699 | 699 | 4,208 | 2,755 | |||||||||||||||
Exploration expenses - non-cash stock-based compensation | 1,161 | 1,012 | 4,569 | 4,025 | |||||||||||||||
General & administrative - non-cash stock-based compensation | 11,526 | 21,137 | 55,382 | 55,737 | |||||||||||||||
Deferred compensation plan - non-cash adjustment | (36,836 | ) | 22,039 | (74,550 | ) | 55,296 | |||||||||||||
Income before income taxes, as adjusted | 102,223 | 109,926 | -7 | % | 421,656 | 381,400 | 11 | % | |||||||||||
Income tax expense (benefit), as adjusted | |||||||||||||||||||
Current | (4 | ) | (143 | ) | 1 | (143 | ) | ||||||||||||
Deferred | 37,680 | 41,772 | 161,460 | 147,705 | |||||||||||||||
Net income excluding certain items, a non-GAAP measure | $ | 64,547 | $ | 68,297 | -5 | % | $ | 260,195 | $ | 233,838 | 11 | % | |||||||
Non-GAAP income per common share | |||||||||||||||||||
Basic | $ | 0.39 | $ | 0.43 | -9 | % | $ | 1.59 | $ | 1.46 | 9 | % | |||||||
Diluted | $ | 0.39 | $ | 0.42 | -7 | % | $ | 1.58 | $ | 1.45 | 9 | % | |||||||
Non-GAAP diluted shares outstanding, if dilutive | 166,164 | 161,496 | 164,403 | 161,407 | |||||||||||||||
RANGE RESOURCES CORPORATION |
HEDGING POSITION AS OF
(Unaudited)
Daily Volume | Hedge Price | |||
Gas | ||||
2015 Swaps | 503,897 Mmbtu | $3.98 | ||
2015 Collars | 145,000 Mmbtu | $4.07 - $4.56 | ||
2016 Swaps | 340,000 Mmbtu | $3.61 | ||
Oil | ||||
2015 Swaps | 9,626 bbls | $90.57 | ||
2016 Swaps | 1,000 bbls | $91.43 | ||
C3 Propane | ||||
2015 Swaps | 10,473 bbls | $0.62/gallon | ||
C4 Normal Butane | ||||
2015 Swaps | 1,819 bbls | $0.70/gallon | ||
C5 Natural Gasoline | ||||
2015 Swaps | 1,942 bbls | $1.21/gallon | ||
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
Investor Contacts:
Senior Vice President
817-869-4258
rwaller@rangeresources.com
Investor Relations Manager
817-869-4266
damend@rangeresources.com
Research Manager
817-869-4267
lsando@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
Source: