Range Announces Second Quarter 2014 Results
Second Quarter Highlights -
- Production volumes reached a record high, averaging 1,105 Mmcfe per day, a 21% increase over the prior-year quarter.
- Unit costs declined
$0.41 per mcfe or 11% compared to the prior-year quarter. - Reported quarterly net income increased 19% to
$171 million . - Expanded marketing capabilities by adding 17 new customers, increasing future firm transportation capacity by 400,000 Mmbtu per day and signing two LNG supply agreements.
- Continuing improvement in well performance both in the wet and dry gas areas of the Marcellus.
- Completed the asset exchange of Permian properties for
Nora Field assets inVirginia and$145 million cash giving Range operating control of 350,000 net acres inVirginia and 111 Mmcf per day of production. - Estimated production for the year increased to 25%, the high-end of previous guidance.
Commenting on the announcement,
In the second quarter, Range was able to grow production and achieve production guidance despite significant midstream disruptions. This shows the value and importance of having a flexible portfolio of properties and transportation outlets. The Range team, working in conjunction with our midstream partners, did a great job minimizing the production impact and downtime experienced during the second quarter. As a result, all of our impacted liquids-rich production is now back on-line, allowing significant production growth in the second half of the year."
Operational Discussion
Range has updated its investor presentation. Please see www.rangeresources.com under the Investor Relations tab, "Presentations and Webcasts" area, for the presentation entitled, "Company Presentation -
Range produced a record average of 1,105 Mmcfe per day during the second quarter despite being negatively impacted by three events, two of which were unplanned. The first was a 200 Mmcf per day MarkWest plant being taken off-line for five weeks to repair damage due to severe weather. This resulted in liquids-rich production being shut in which negatively impacted condensate and NGL production. The second issue was extensive operational down time on Sunoco's Mariner West line which negatively impacted ethane netbacks. A third event during the quarter was the scheduled plant turnaround by MarkWest at its
Marcellus Shale Marketing, Transportation and Processing Update -
During the second quarter, the Company continued expanding its marketing efforts towards new customers outside the
Since discovering the Marcellus, Range has become the largest producer of natural gas liquids in
Southern Marcellus Shale Division -
Production for the second quarter averaged 848 (712 net) Mmcfe per day for the division, a 33% increase over the prior year. The division's second quarter net production included 404 Mmcf per day of gas, 43,640 barrels per day of NGLs and 7,810 barrels per day of condensate.
During the second quarter, the division brought on line 36 wells in southwest
In the dry gas area of southwest
In the wet and super-rich areas the Company continued its recent series of highly successful wells. As previously mentioned, the Company drilled the highest rate well in the southwest portion of the Marcellus to date by any operator. The well tested at a 24-hour rate of 6,357 (5,233 net) boe per day with 65% liquids, or 38.1 Mmcfe per day (1,356 barrels condensate, 2,781 barrels NGLs and 13.3 Mmcf gas per day). This well was part of a five well pad that had an average 30-day rate per well of 2,113 (1,740 net) boe per day with 64% liquids (388 barrels condensate, 981 barrels NGLs and 4.5 Mmcf gas per day).
Range expects to turn to sales a total of 71 wells in the southern Marcellus during the remainder of 2014. The wells drilled in the second half of the year are expected to have average lateral lengths of 5,877 feet and 29 frac stages. Of those wells, four will have lateral length targets of greater than 11,000 feet as the Company continues to optimize its lateral lengths and add more frac stages. Range has increased the expected average lateral length of its 2015 program as well. For 2014, Range will drill approximately 12% of its Marcellus wells on existing pads where it expects to benefit from improved landing target selection and completion techniques while at the same time lowering costs by up to
During the quarter, the Company spud its initial dry gas
Northern Marcellus Shale Division -
In northeast
Production from a four well pad mentioned in previous operating updates continues its strong performance. After 240 days, cumulative production from the four wells is over 9.7 Bcf, or a 240-day per well average of 10 Mmcf per day. Building on this success the division brought on another four well pad late in the second quarter that had a combined 24-hour IP that was constrained by surface facilities at 90 Mmcf per day. The 4 wells on the pad were drilled with an average lateral length of 5,353 feet and 27 frac stages. The best well on the pad averaged in excess of 25 Mmcf per day for the first 30 days, despite being constrained. This well is the highest 30-day production rate to date that Range has drilled in the Marcellus.
Midcontinent Division -
Production for the second quarter averaged 87 net Mmcfe per day for the division, a 2% increase over the prior year. The division's second quarter net production included 51.2 Mmcf per day of gas, 3,771 barrels per day of NGLs and 2,143 barrels per day of oil.
During the second quarter, the Midcontinent division continued drilling to further evaluate Range's horizontal Mississippian Chat acreage along the Nemaha Ridge, and to monitor the performance of recent wells completed using current completion designs and improved geological targeting. In the second quarter, the Company drilled its highest oil rate Mississippian Chat well. The well tested at a 24-hour rate of 1,263 boe per day with 92% liquids (1,062 barrels oil, 98 barrels NGLs and 618 mcf gas per day). Over the first 90 days of production the well has averaged over 400 barrels of oil per day. During the quarter a total of 3 (2.9 net) Mississippian Chat wells were turned to sales with an average lateral length of 3,326 feet with 16 frac stages. Average 24-hour IP rates for the completions were 753 (559 net) boe per day with 75% liquids. This is the highest IP average for any quarter reported by Range. For the remainder of 2014, the Company expects to bring on line five Mississippian Chat wells in northern Oklahoma and three additional tests in the Texas Panhandle.
Southern Appalachia Division -
Range recently gained complete operational control over its Nora assets in
Production for the second quarter averaged 76 net Mmcf per day for the division. Production at the end of the quarter with the completion of the exchange was approximately 111 Mmcf net per day. For the remainder of 2014, the Company expects to perform 20 coalbed methane (CBM) recompletions while also drilling vertical tight gas, CBM and horizontal shale wells. The division's capital budget for 2014 has been increased to
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.)
GAAP revenues for the second quarter of 2014 totaled
Several non-cash or non-recurring items impacted second quarter results. A
Non-GAAP revenues for second quarter 2014 totaled
Total unit costs improved by
Second quarter production volumes averaged 1,105 Mmcfe per day, a 21% increase over the prior-year quarter despite Marcellus production being significantly impacted by plant turnarounds and midstream downtime. Midstream downtime resulted in a reduction to cash flow of approximately
- Production and realized prices after hedging for each commodity for the second quarter of 2014 were: natural gas - 745 Mmcf per day (
$3.88 per mcf), NGLs - 49,130 barrels per day ($24.34 per barrel) and crude oil and condensate - 10,875 barrels per day ($80.63 per barrel). - The second quarter average natural gas realized price before hedging settlements was
$4.07 . Financial hedges based upon NYMEX decreased realizations by$0.21 per mcf while financial basis hedges increased realizations by$0.02 per mcf during the quarter. The average Company natural gas differential including the settled financial basis hedges but before NYMEX hedging, for the second quarter was$(0.58) per mcf compared to$(0.24) per mcf for the first quarter 2014. (See the schedule below which details the components of the non-GAAP average realized natural gas price for the quarter and the tables presented elsewhere that reconcile the non-GAAP measures to their most directly comparable GAAP financial measure.) - NGL pricing before the impact of hedging was 24% of WTI or
$24.60 per barrel for the second quarter of 2014. Ethane was approximately 50% of the total composite barrel in the Marcellus during the quarter. - Crude oil and condensate price realizations, before financial hedges, for the second quarter averaged 85% of WTI or
$87.79 per barrel.
Capital Expenditures
Second quarter drilling expenditures of
Guidance - Third Quarter 2014
Production Guidance:
Production growth for 2014 is now targeted at 25% year-over-year. Average daily production for the third quarter is expected to be approximately 1.20 Bcfe per day, with 30% liquids and fourth quarter production is expected to be approximately 1.35 Bcfe per day, with 30% liquids.
Guidance for 2014 Activity:
Under the current plan, which will be subject to change during the year, Range expects to turn to sales approximately 206 wells in the Marcellus, Nora and Midcontinent during 2014, as shown below:
Total Wells to Sales in 1H 2014 | Remaining 2014 Wells | Planned Total Wells to Sales in 2014 | ||||||
Super-Rich area | 25 | 27 | 52 | |||||
Wet area | 18 | 33 | 51 | |||||
Dry area-SW | 6 | 11 | 17 | |||||
Dry area-NE | 6 | 12 | 18 | |||||
Total Marcellus | 55 | 83 | 138 | |||||
Nora area | 9 | 38 | 47 | |||||
Midcontinent | 13 | 8 | 21 | |||||
Total | 77 | 129 | 206 | |||||
3Q 2014 Expense per mcfe Guidance:
Direct operating expense: $0.31 - $0.33 per mcfe | |
Transportation, gathering and compression expense: $0.78 - $0.80 per mcfe | |
Production tax expense: $0.12 - $0.14 per mcfe | |
Exploration expense: $16 - $18 million | |
Unproved property impairment expense: $10 - $12 million | |
G&A expense: $0.36 - $0.38 per mcfe | |
Interest expense: $0.35 - $0.37 per mcfe | |
DD&A expense: $1.30 - $1.33 per mcfe | |
Non-GAAP Natural Gas Price Realizations and Differentials
Range continues to hedge a significant portion of its estimated future production in order to lock in prices and returns which provide certainty of cash flow to execute our capital plans. During the second quarter, most Appalachian price indices weakened as additional supply growth temporarily outpaced regional demand and infrastructure to export natural gas out of the basin. Range offsets some of this regional weakness by hedging basis differentials, as reflected in the
Corporate Differential Disclosure | 2Q 2013 | 3Q 2013 | 4Q 2013 | 1Q 2014 | 2Q 2014 | ||||||
NYMEX Index average price | $4.09 | $3.60 | $3.62 | $4.92 | $4.67 | ||||||
Differential | $0.04 | ($0.17) | ($0.22) | $0.66 | ($0.60) | ||||||
Cash settled basis hedging | $0.00 | $0.00 | ($0.01) | ($0.90) | $0.02 | ||||||
Differential including basis hedging | $0.04 | ($0.17) | ($0.23) | ($0.24) | ($0.58) | ||||||
Average price before NYMEX hedges | $4.13 | $3.43 | $3.39 | $4.68 | $4.09 | ||||||
Cash settled NYMEX hedges | $0.07 | $0.45 | $0.45 | ($0.49) | ($0.21) | ||||||
Average price including all hedges | $4.20 | $3.88 | $3.84 | $4.19 | $3.88 | ||||||
Basis Differentials:
Based upon the contracts that Range has in place for the periods disclosed and the future basis differential indications from quotations on ICE (the "Intercontinental Exchange") as of
Calculated Differentials by Quarter | |||||||||||
3Q2014 | 4Q2014 | 1Q2015 | |||||||||
Differential by Division | |||||||||||
Based on NYMEX except as indicated | |||||||||||
Marcellus | |||||||||||
SW PA | $ | (0.34) | $ | (0.30) | $ | + 0.30 | |||||
NE PA | Leidy + 0.45 | Leidy + 0.40 | Leidy + 0.80 | ||||||||
Nora (1) | + 0.15 | + 0.20 | + 0.25 | ||||||||
Midcontinent (2) | (0.92) | (0.97) | (0.85) | ||||||||
Basis Hedging | |||||||||||
MTM 7/24/14 $MM | $ | 12.282 | $ | 9.332 | $ | (8.144) | |||||
(1) | Nora has historically reported its natural gas realizations net of gathering and transportation received from a third party. After the exchange, gathering and transportation will be reported separately as brokerage expense since Range is supplying gathering and transportation for third parties. Therefore, the realized price will reflect the actual sales of the natural gas without any netted amounts. |
(2) | Midcontinent processing, gathering and transportation costs are netted against the realized price received from a third party. |
NYMEX 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 80% of its remaining 2014 natural gas production hedged at a weighted average floor price of
As of
For calendar year 2015, Range has hedged 432,000 Mmbtu per day of its expected natural gas production at a weighted average floor price of
Effective
Conference Call 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 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 unaudited 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.
Hedging and Derivatives
As discussed 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 undesignated hedges and 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-Q along with the change in mark-to-market valuations of such unrealized derivatives. Effective
All statements, except for statements of historical fact, made in this release such as expected future growth in production, future transportation capacity and sales, expected midstream additions, future cash flow growth, future commodity prices, expected demand growth, future capital spending levels, cost structure improvements, expected capital efficiency gains, expected improvements in well results, expected future efficiencies, expected price realizations, expected future customers, expected timing of well results, future rates of return 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 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
RANGE RESOURCES CORPORATION | ||||||||||||||||||||||
STATEMENTS OF OPERATIONS | ||||||||||||||||||||||
Based on GAAP reported earnings with additional | ||||||||||||||||||||||
details of items included in each line in Form 10-Q | ||||||||||||||||||||||
(Unaudited, in thousands, except per share data) | ||||||||||||||||||||||
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||||||||
2014 | 2013 | % | 2014 | 2013 | % | |||||||||||||||||
Revenues and other income: | ||||||||||||||||||||||
Natural gas, NGLs and oil sales (a) | $ | 477,517 | $ | 437,678 | $ | 1,049,534 | $ | 835,917 | ||||||||||||||
Derivative fair value (loss)/income | (24,109 | ) | 137,760 | (170,959 | ) | 37,885 | ||||||||||||||||
Gain on sale of assets | 282,064 | 83,287 | 281,711 | 83,121 | ||||||||||||||||||
Brokered natural gas, marketing and other (b) | 30,274 | 10,466 | 63,523 | 31,524 | ||||||||||||||||||
Brokered natural gas - blending (b) | - | 3,938 | - | 3,938 | ||||||||||||||||||
Equity method investment (b) | (144 | ) | 353 | (277 | ) | 273 | ||||||||||||||||
ARO settlement loss (b) | (127 | ) | (182 | ) | (786 | ) | (182 | ) | ||||||||||||||
Other (b) | 49 | 56 | 120 | 119 | ||||||||||||||||||
Total revenues and other income | 765,524 | 673,356 | 14 | % | 1,222,866 | 992,595 | 23 | % | ||||||||||||||
Costs and expenses: | ||||||||||||||||||||||
Direct operating | 32,998 | 31,940 | 71,941 | 61,467 | ||||||||||||||||||
Direct operating - non-cash stock-based compensation (c) | 1,937 | 696 | 2,789 | 1,357 | ||||||||||||||||||
Transportation, gathering and compression | 76,809 | 66,048 | 150,970 | 128,464 | ||||||||||||||||||
Production and ad valorem taxes | 10,844 | 11,113 | 22,522 | 22,496 | ||||||||||||||||||
Brokered natural gas and marketing | 33,645 | 12,115 | 67,246 | 34,181 | ||||||||||||||||||
Brokered natural gas and marketing - non-cash stock-based compensation (c) | 1,130 | 530 | 1,658 | 779 | ||||||||||||||||||
Brokered natural gas and marketing - blending | - | 4,017 | - | 4,017 | ||||||||||||||||||
Exploration | 12,399 | 12,108 | 26,092 | 27,818 | ||||||||||||||||||
Exploration - non-cash stock-based compensation (c) | 1,222 | 960 | 2,375 | 2,030 | ||||||||||||||||||
Abandonment and impairment of unproved properties | 9,332 | 19,156 | 19,327 | 34,374 | ||||||||||||||||||
General and administrative | 35,399 | 35,607 | 72,599 | 70,961 | ||||||||||||||||||
General and administrative - non-cash stock-based compensation (c) | 20,696 | 13,263 | 32,300 | 23,569 | ||||||||||||||||||
General and administrative - lawsuit settlements | 543 | 52,867 | 951 | 91,265 | ||||||||||||||||||
General and administrative - bad debt expense | 250 | 250 | 250 | 250 | ||||||||||||||||||
Deferred compensation plan (d) | 10,519 | (6,878 | ) | 8,484 | 35,482 | |||||||||||||||||
Interest expense | 45,488 | 45,071 | 90,889 | 87,281 | ||||||||||||||||||
Loss on early extinguishment of debt | 24,596 | 12,280 | 24,596 | 12,280 | ||||||||||||||||||
Depletion, depreciation and amortization | 133,361 | 119,995 | 262,043 | 235,096 | ||||||||||||||||||
Impairment of proved properties and other assets | 24,991 | 741 | 24,991 | 741 | ||||||||||||||||||
Total costs and expenses | 476,159 | 431,879 | 10 | % | 882,023 | 873,908 | 1 | % | ||||||||||||||
Income from operations before income taxes | 289,365 | 241,477 | 20 | % | 340,843 | 118,687 | 187 | % | ||||||||||||||
Income tax expense (benefit): | ||||||||||||||||||||||
Current | (1 | ) | (25 | ) | 5 | - | ||||||||||||||||
Deferred | 117,977 | 97,519 | 136,928 | 50,314 | ||||||||||||||||||
117,976 | 97,494 | 136,933 | 50,314 | |||||||||||||||||||
Net income | $ | 171,389 | $ | 143,983 | 19 | % | $ | 203,910 | $ | 68,373 | 198 | % | ||||||||||
Net Income Per Common Share: | ||||||||||||||||||||||
Basic | $ | 1.04 | $ | 0.88 | $ | 1.24 | $ | 0.42 | ||||||||||||||
Diluted | $ | 1.04 | $ | 0.88 | $ | 1.24 | $ | 0.42 | ||||||||||||||
Weighted average common shares outstanding, as reported: | ||||||||||||||||||||||
Basic | 161,909 | 160,565 | 1 | % | 161,354 | 160,346 | 1 | % | ||||||||||||||
Diluted | 162,813 | 161,414 | 1 | % | 162,323 | 161,223 | 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-Q. |
(c) | Costs associated with stock compensation and restricted stock amortization, which have been reflected in the categories associated with the direct personnel costs, which are combined with the cash costs in the 10-Q. |
(d) | Reflects the change in market value of the vested Company stock held in the deferred compensation plan. |
RANGE RESOURCES CORPORATION | ||||||||||
BALANCE SHEETS | ||||||||||
(In thousands) | June 30, | December 31, | ||||||||
2014 | 2013 | |||||||||
(Unaudited) | (Audited) | |||||||||
Assets | ||||||||||
Current assets | $ | 202,705 | $ | 192,466 | ||||||
Derivative assets | 5,463 | 4,421 | ||||||||
Deferred tax assets | 39,411 | 51,414 | ||||||||
Natural gas and oil properties, successful efforts method | 7,395,344 | 6,758,437 | ||||||||
Transportation and field assets | 38,664 | 32,784 | ||||||||
Other | 118,971 | 259,564 | ||||||||
$ | 7,800,558 | $ | 7,299,086 | |||||||
Liabilities and Stockholders' Equity | ||||||||||
Current liabilities | $ | 490,868 | $ | 464,326 | ||||||
Asset retirement obligations | 5,037 | 5,037 | ||||||||
Derivative liabilities | 62,965 | 26,198 | ||||||||
Bank debt | 480,000 | 500,000 | ||||||||
Subordinated notes | 2,350,000 | 2,640,516 | ||||||||
2,830,000 | 3,140,516 | |||||||||
Deferred tax liability | 894,115 | 771,980 | ||||||||
Derivative liabilities | 7,101 | 25 | ||||||||
Deferred compensation liability | 240,787 | 247,537 | ||||||||
Asset retirement obligations and other liabilities | 249,511 | 229,015 | ||||||||
1,391,514 | 1,248,557 | |||||||||
Common stock and retained earnings | 3,021,320 | 2,411,853 | ||||||||
Common stock held in treasury stock | (3,096 | ) | (3,637 | ) | ||||||
3,018,224 | 2,408,216 | |||||||||
Accumulated other comprehensive income | 1,950 | 6,236 | ||||||||
Total stockholders' equity | 3,020,174 | 2,414,452 | ||||||||
$ | 7,800,558 | $ | 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 June 30, |
Six Months Ended June 30, |
||||||||||||||||||||
2014 | 2013 | % | 2014 | 2013 | % | ||||||||||||||||
Total revenues and other income, as reported | $ | 765,524 | $ | 673,356 | 14 | % | $ | 1,222,866 | $ | 992,595 | 23 | % | |||||||||
Adjustment for certain special items: | |||||||||||||||||||||
Total change in fair value related to derivatives prior to settlement (gain) loss | (2,069 | ) | (159,526 | ) | 40,197 | (59,269 | ) | ||||||||||||||
ARO settlement loss | 127 | 182 | 786 | 182 | |||||||||||||||||
(Gain) loss on sale of assets | (282,064 | ) | (83,287 | ) | (281,711 | ) | (83,121 | ) | |||||||||||||
Brokered natural gas - blending | - | (3,938 | ) | - | (3,938 | ) | |||||||||||||||
Total revenues, as adjusted, non-GAAP | $ | 481,518 | $ | 426,787 | 13 | % | $ | 982,138 | $ | 846,449 | 16 | % | |||||||||
RANGE RESOURCES CORPORATION | |||||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES (Unaudited, in thousands) |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Net income | $ | 171,389 | $ | 143,983 | $ | 203,910 | $ | 68,373 | |||||||||||
Adjustments to reconcile net cash provided from continuing operations: | |||||||||||||||||||
(Gain) loss from equity investment, net of distributions | 364 | (2,162 | ) | 3,096 | (1,552 | ) | |||||||||||||
Deferred income tax expense (benefit) | 117,977 | 97,519 | 136,928 | 50,314 | |||||||||||||||
Depletion, depreciation, amortization and impairment | 158,352 | 120,736 | 287,034 | 235,837 | |||||||||||||||
Exploration dry hole costs | - | - | 1 | (159 | ) | ||||||||||||||
Abandonment and impairment of unproved properties | 9,332 | 19,156 | 19,327 | 34,374 | |||||||||||||||
Derivative fair value loss (income) | 24,109 | (137,760 | ) | 170,959 | (37,885 | ) | |||||||||||||
Cash settlements on derivative financial instruments that do not qualify for hedge accounting | (26,178 | ) | (21,766 | ) | (130,762 | ) | (21,384 | ) | |||||||||||
Allowance for bad debts | 250 | 250 | 250 | 250 | |||||||||||||||
Amortization of deferred issuance costs, loss on extinguishment of debt, and other | 26,939 | 14,582 | 29,812 | 16,662 | |||||||||||||||
Deferred and stock-based compensation | 35,319 | 8,334 | 47,912 | 63,325 | |||||||||||||||
(Gain) loss on sale of assets and other | (282,064 | ) | (83,287 | ) | (281,711 | ) | (83,121 | ) | |||||||||||
Changes in working capital: | |||||||||||||||||||
Accounts receivable | 42,918 | (3,435 | ) | 1,275 | (2,143 | ) | |||||||||||||
Inventory and other | (1,514 | ) | 1,379 | (6,872 | ) | 1,545 | |||||||||||||
Accounts payable | 10,118 | (27,442 | ) | 20,115 | (10,381 | ) | |||||||||||||
Accrued liabilities and other | (27,009 | ) | (51,447 | ) | (59,751 | ) | (34,166 | ) | |||||||||||
Net changes in working capital | 24,513 | (80,945 | ) | (45,233 | ) | (45,145 | ) | ||||||||||||
Net cash provided from operating activities | $ | 260,302 | $ | 78,640 | $ | 441,523 | $ | 279,889 | |||||||||||
RECONCILIATION OF NET CASH PROVIDED FROM OPERATING | |||||||||||||||||
ACTIVITIES, AS REPORTED, TO CASH FLOW FROM OPERATIONS | |||||||||||||||||
BEFORE CHANGES IN WORKING CAPITAL, a non-GAAP measure (Unaudited, in thousands) |
|||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
Net cash provided from operating activities, as reported | $ | 260,302 | $ | 78,640 | $ | 441,523 | $ | 279,889 | |||||||||
Net changes in working capital | (24,513 | ) | 80,945 | 45,233 | 45,145 | ||||||||||||
Exploration expense | 12,398 | 12,108 | 26,090 | 27,977 | |||||||||||||
Lawsuit settlements | 543 | 52,867 | 951 | 91,265 | |||||||||||||
Equity method investment distribution / intercompany elimination | (219 | ) | 1,809 | (2,819 | ) | 1,278 | |||||||||||
Loss on gas blending | - | 79 | - | 79 | |||||||||||||
Loss on ARO | 128 | 182 | 787 | 182 | |||||||||||||
Non-cash compensation adjustment | 179 | 247 | (845 | ) | 41 | ||||||||||||
Cash flow from operations before changes in working capital - a non-GAAP measure | $ | 248,818 | $ | 226,877 | $ | 510,920 | $ | 445,856 | |||||||||
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | |||||||||||||||||
(Unaudited, in thousands) | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||
Basic: | |||||||||||||||||
Weighted average shares outstanding | 164,664 | 163,211 | 164,139 | 163,027 | |||||||||||||
Stock held by deferred compensation plan | (2,755 | ) | (2,646 | ) | (2,785 | ) | (2,681 | ) | |||||||||
Adjusted basic | 161,909 | 160,565 | 161,354 | 160,346 | |||||||||||||
Dilutive: | |||||||||||||||||
Weighted average shares outstanding | 164,664 | 163,211 | 164,139 | 163,027 | |||||||||||||
Dilutive stock options under treasury method | (1,851 | ) | (1,797 | ) | (1,816 | ) | (1,804 | ) | |||||||||
Adjusted dilutive | 162,813 | 161,414 | 162,323 | 161,223 | |||||||||||||
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 June 30, | Six Months Ended June 30, | |||||||||||||||||||||
2014 | 2013 | % | 2014 | 2013 | % | |||||||||||||||||
Natural gas, NGL and oil sales components: | ||||||||||||||||||||||
Natural gas sales | $ | 275,726 | $ | 268,069 | $ | 621,952 | $ | 485,157 | ||||||||||||||
NGL sales | 109,998 | 66,587 | 245,502 | 134,158 | ||||||||||||||||||
Oil sales | 86,881 | 72,504 | 175,002 | 149,584 | ||||||||||||||||||
Cash-settled hedges (effective): | ||||||||||||||||||||||
Natural gas | 3,626 | 29,345 | 4,794 | 64,823 | ||||||||||||||||||
Crude oil | 1,286 | 1,173 | 2,284 | 2,195 | ||||||||||||||||||
Total oil and gas sales, as reported | $ | 477,517 | $ | 437,678 | 9 | % | $ | 1,049,534 | $ | 835,917 | 26 | % | ||||||||||
Derivative fair value income (loss), as reported: | $ | (24,109 | ) | $ | 137,760 | $ | (170,959 | ) | $ | 37,885 | ||||||||||||
Cash settlements on derivative financial instruments - (gain) loss: | ||||||||||||||||||||||
Natural gas | 16,637 | 24,698 | 103,745 | 23,319 | ||||||||||||||||||
NGLs | 1,165 | (3,043 | ) | 14,437 | (2,148 | ) | ||||||||||||||||
Crude Oil | 8,376 | 111 | 12,580 | 213 | ||||||||||||||||||
Total change in fair value related to derivatives prior to settlement, a non GAAP measure | $ | 2,069 | $ | 159,526 | $ | (40,197 | ) | $ | 59,269 | |||||||||||||
Transportation, gathering and compression components: | ||||||||||||||||||||||
Natural gas | $ | 68,280 | $ | 62,754 | $ | 133,578 | $ | 121,995 | ||||||||||||||
NGLs | 8,529 | 3,294 | 17,392 | 6,469 | ||||||||||||||||||
Total transportation, gathering and compression, as reported | $ | 76,809 | $ | 66,048 | $ | 150,970 | $ | 128,464 | ||||||||||||||
Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | ||||||||||||||||||||||
Natural gas sales | $ | 262,715 | $ | 272,716 | $ | 523,001 | $ | 526,661 | ||||||||||||||
NGL sales | 108,833 | 69,630 | 231,065 | 136,306 | ||||||||||||||||||
Oil sales | 79,791 | 73,566 | 164,706 | 151,566 | ||||||||||||||||||
Total | $ | 451,339 | $ | 415,912 | 9 | % | $ | 918,772 | $ | 814,533 | 13 | % | ||||||||||
Production of oil and gas during the periods (a): | ||||||||||||||||||||||
Natural gas (mcf) | 67,761,616 | 64,926,278 | 4 | % | 129,779,197 | 126,950,234 | 2 | % | ||||||||||||||
NGL (bbl) | 4,470,854 | 2,115,489 | 111 | % | 8,942,335 | 4,004,913 | 123 | % | ||||||||||||||
Oil (bbl) | 989,609 | 864,517 | 14 | % | 2,024,754 | 1,777,179 | 14 | % | ||||||||||||||
Gas equivalent (mcfe) (b) | 100,524,394 | 82,806,314 | 21 | % | 195,581,731 | 161,642,786 | 21 | % | ||||||||||||||
Production of oil and gas - average per day (a): | ||||||||||||||||||||||
Natural gas (mcf) | 744,633 | 713,476 | 4 | % | 717,012 | 701,383 | 2 | % | ||||||||||||||
NGL (bbl) | 49,130 | 23,247 | 111 | % | 49,405 | 22,127 | 123 | % | ||||||||||||||
Oil (bbl) | 10,875 | 9,500 | 14 | % | 11,186 | 9,819 | 14 | % | ||||||||||||||
Gas equivalent (mcfe) (b) | 1,104,664 | 909,959 | 21 | % | 1,080,562 | 893,054 | 21 | % | ||||||||||||||
Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | ||||||||||||||||||||||
Natural gas (mcf) | $ | 4.12 | $ | 4.58 | -10 | % | $ | 4.83 | $ | 4.33 | 11 | % | ||||||||||
NGL (bbl) | $ | 24.60 | $ | 31.48 | -22 | % | $ | 27.45 | $ | 33.50 | -18 | % | ||||||||||
Oil (bbl) | $ | 89.09 | $ | 85.22 | 5 | % | $ | 87.56 | $ | 85.40 | 3 | % | ||||||||||
Gas equivalent (mcfe) (b) | $ | 4.75 | $ | 5.29 | -10 | % | $ | 5.37 | $ | 5.17 | 4 | % | ||||||||||
Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | ||||||||||||||||||||||
Natural gas (mcf) | $ | 3.88 | $ | 4.20 | -8 | % | $ | 4.03 | $ | 4.15 | -3 | % | ||||||||||
NGL (bbl) | $ | 24.34 | $ | 32.91 | -26 | % | $ | 25.84 | $ | 34.03 | -24 | % | ||||||||||
Oil (bbl) | $ | 80.63 | $ | 85.09 | -5 | % | $ | 81.35 | $ | 85.28 | -5 | % | ||||||||||
Gas equivalent (mcfe) (b) | $ | 4.49 | $ | 5.02 | -11 | % | $ | 4.70 | $ | 5.04 | -7 | % | ||||||||||
Average prices, including cash-settled hedges and derivatives: (d) | ||||||||||||||||||||||
Natural gas (mcf) | $ | 2.87 | $ | 3.23 | -11 | % | $ | 3.00 | $ | 3.19 | -6 | % | ||||||||||
NGL (bbl) | $ | 22.43 | $ | 31.36 | -28 | % | $ | 23.89 | $ | 32.42 | -26 | % | ||||||||||
Oil (bbl) | $ | 80.63 | $ | 85.09 | -5 | % | $ | 81.35 | $ | 85.28 | -5 | % | ||||||||||
Gas equivalent (mcfe) (b) | $ | 3.73 | $ | 4.23 | -12 | % | $ | 3.93 | $ | 4.24 | -8 | % | ||||||||||
Transportation, gathering and compression expense per mcfe | $ | 0.76 | $ | 0.80 | -4 | % | $ | 0.77 | $ | 0.79 | -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) 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 June 30, | Six Months Ended June 30, | ||||||||||||||||||
2014 | 2013 | % | 2014 | 2013 | % | |||||||||||||||
Income from operations before income taxes, as reported | $ | 289,365 | $ | 241,477 | 20 | % | $ | 340,843 | $ | 118,687 | 187 | % | ||||||||
Adjustment for certain special items: | ||||||||||||||||||||
(Gain) loss on sale of assets | (282,064 | ) | (83,287 | ) | (281,711 | ) | (83,121 | ) | ||||||||||||
Loss on ARO settlements | 127 | 182 | 786 | 182 | ||||||||||||||||
Change in fair value related to derivatives prior to settlement | (2,069 | ) | (159,526 | ) | 40,197 | (59,269 | ) | |||||||||||||
Abandonment and impairment of unproved properties | 9,332 | 19,156 | 19,327 | 34,374 | ||||||||||||||||
Loss on gas blending - brokered natural gas and marketing | - | 79 | - | 79 | ||||||||||||||||
Loss on early extinguishment of debt | 24,596 | 12,280 | 24,596 | 12,280 | ||||||||||||||||
Impairment of proved property and other assets | 24,991 | 741 | 24,991 | 741 | ||||||||||||||||
Lawsuit settlements | 543 | 52,867 | 951 | 91,265 | ||||||||||||||||
Brokered natural gas and marketing - non cash stock-based compensation | 1,130 |
530 |
1,658 |
779 |
||||||||||||||||
Direct operating - non-cash stock-based compensation | 1,937 | 696 | 2,789 | 1,357 | ||||||||||||||||
Exploration expenses - non-cash stock-based compensation | 1,222 | 960 | 2,375 | 2,030 | ||||||||||||||||
General & administrative - non-cash stock-based compensation | 20,696 | 13,263 | 32,300 | 23,569 | ||||||||||||||||
Deferred compensation plan - non-cash adjustment | 10,519 | (6,878 | ) | 8,484 | 35,482 | |||||||||||||||
Income from operations before income taxes, as adjusted | 100,325 | 92,540 | 8 | % | 217,586 | 178,435 | 22 | % | ||||||||||||
Income tax expense, as adjusted | ||||||||||||||||||||
Current | (1 | ) | (25 | ) | 5 | - | ||||||||||||||
Deferred | 40,905 | 37,378 | 84,084 | 70,371 | ||||||||||||||||
Net income excluding certain items, a non-GAAP measure | $ | 59,421 | $ | 55,187 | 8 | % | $ | 133,497 | $ | 108,064 | 24 | % | ||||||||
Non-GAAP income per common share | ||||||||||||||||||||
Basic | $ | 0.37 | $ | 0.34 | 9 | % | $ | 0.83 | $ | 0.67 | 24 | % | ||||||||
Diluted | $ | 0.36 | $ | 0.34 | 6 | % | $ | 0.82 | $ | 0.67 | 22 | % | ||||||||
Non-GAAP diluted shares outstanding, if dilutive | 162,813 | 161,414 | 162,323 | 161,223 | ||||||||||||||||
RANGE RESOURCES CORPORATION | ||||
HEDGING POSITION AS OF JULY 28, 2014 - | ||||
(Unaudited) | ||||
Daily Volume | Hedge Price | |||
Gas (Mmbtu) | ||||
3Q 2014 Swaps | 260,000 | $4.18 | ||
3Q 2014 Collars | 447,500 | $3.84 - $4.48 | ||
4Q 2014 Swaps | 260,000 | $4.18 | ||
4Q 2014 Collars | 447,500 | $3.84 - $4.48 | ||
2015 Swaps | 287,432 | $4.22 | ||
2015 Collars | 145,000 | $4.07 - $4.56 | ||
2016 Swaps | 90,000 | $4.21 | ||
Oil (Bbls) | ||||
3Q 2014 Swaps | 9,500 | $94.35 | ||
3Q 2014 Collars | 2,000 | $85.55 - $100.00 | ||
4Q 2014 Swaps | 9,500 | $94.35 | ||
4Q 2014 Collars | 2,000 | $85.55 - $100.00 | ||
2015 Swaps | 9,626 | $90.57 | ||
2016 Swaps | 1,000 | $91.43 | ||
C3 Propane (Bbls) | ||||
3Q 2014 Swaps | 12,000 | $1.018 | ||
4Q 2014 Swaps | 12,000 | $1.018 | ||
2015 Swaps | 496 | $1.100 | ||
C4 Normal Butane (Bbls) | ||||
3Q 2014 Swaps | 4,000 | $1.344 | ||
4Q 2014 Swaps | 4,000 | $1.344 | ||
C5 Natural Gasoline (Bbls) | ||||
3Q 2014 Swaps | 3,500 | $2.168 | ||
4Q 2014 Swaps | 3,500 | $2.168 | ||
2015 Swaps | 123 | $2.140 |
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
Financial Analyst
817-869-4264
mfreeman@rangeresources.com
or
Media Contact:
Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
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