Range Announces Second Quarter 2015 Results
Highlights --
- Production volumes reached a record high, averaging 1,373 Mmcfe per day, a 24% increase over the prior-year quarter.
- Unit costs declined
$0.36 per mcfe, or 11% compared to the prior-year quarter. - Two Marcellus dry gas wells in southwest
Pennsylvania were turned in line, each at 34.2 Mmcf per day, 1.8 Bcf per well of cumulative production in 90 days. - Full-year 2015 capital budget of
$870 million is on track to deliver 20% annual growth. - Spectra's
Uniontown to Gas City project is anticipated to open ahead of schedule allowing Range as anchor shipper to move approximately 170 Mmcf per day of net natural gas production, or approximately 28% of its average net second quarter production in the southwest Marcellus, to Midwest markets with improved realized prices. - Mariner East I expected to start the commissioning process in late third quarter expanding Range's access to NGL markets outside the Appalachian basin with Range being the only producer directly holding capacity on the project.
Commenting, Jeff Ventura , Range's Chairman, President and CEO, said, "Operational results in the second quarter continued to be excellent, as we lowered costs, improved capital efficiencies, exceeded production guidance and achieved great drilling results, especially in the dry gas area. Conversely, the oversupply of natural gas and NGLs in Appalachia challenged commodity prices during the quarter. Importantly, Range expects relief later this year as two key marketing events are projected to commence -- Mariner East I which is expected to improve our NGL pricing in the fourth quarter and Spectra's Uniontown to Gas City project which is expected to improve our natural gas pricing is anticipated to commence ahead of schedule on August 1st . The Spectra project is expected to be impactful since that capacity would equate to about 28% of our second quarter average net production in our Southern Marcellus Division when it comes on line, while Mariner East I is expected to cover almost all of our propane production and add a major ethane market to our already industry-leading ethane sales portfolio. Both projects are expected to provide substantial pricing improvements for Range.
"Range is on track to spend $870 million in 2015, approximately $700 million less than 2014, while still generating 20% year-over-year production growth. We believe this makes Range one of the most capital efficient producers in the industry. This capital efficient growth combined with our dry, wet and super-rich drilling inventory across the Marcellus, Utica and Upper Devonian give us great optionality to maximize returns throughout any commodity cycle. We believe this inventory, coupled with our capital discipline and diversified portfolio of marketing arrangements, allows Range to create value as we move forward into an expected better market that balances supply, demand and infrastructure."
Capital Expenditures
Second quarter drilling expenditures of $262 million funded the drilling and recompletion of 68 (66 net) wells with a 100% drilling success rate. In addition, during the second quarter, $23 million was expended on acreage, $2 million on gas gathering systems and $4 million for exploration expense. Range is on target with its $870 million capital budget for 2015. Similar to recent years, the 2015 capital budget is front-end loaded and has been redirected to more dry gas drilling to maximize expected rates of return. The Company started the year running 15 rigs and is now down to 10 and expects to finish the year with six rigs. The number of wells expected to be turned in line in 2015 has been increased by 19, as operational improvements have allowed for some planned early 2016 wells to be turned in line in late 2015. Range expects sequential production growth throughout 2015 and a strong inventory of wells waiting on completion at the end of the year. Those wells are expected to be brought on line early in 2016 when regional pricing is anticipated to be seasonally stronger along with improved transportation.
Range has updated its investor presentation with expected well economics, rates of return and other operational information. Please see www.rangeresources.com under the "Investors" tab, "Company Presentations" area, for the presentation entitled, "Company Presentation - July 28, 2015 ."
Range has developed tremendous improvements in capital efficiencies over the last four years as lateral lengths increased and completion techniques have been optimized. These improvements, combined with the added benefit of lower service costs, have lowered well cost per lateral foot about 60% in the Marcellus over that time frame. In addition to these industry leading well costs, Range also has some of the highest estimated ultimate recoveries (EUR) on a normalized basis (per 1,000 feet of lateral), as shown in the chart below.
| Marcellus Area | EUR (Bcfe) | Well Cost | ||
| per 1,000 ft. | per 1,000 ft. | |||
| SW Dry | 2.52 | $883,000 | ||
| SW Wet | 2.95 | $991,000 | ||
| SW Super rich | 2.40 | $1,100,000 | ||
| NE Dry | 2.67 | $865,000 | ||
Southern Marcellus Shale Division --
Production for the second quarter averaged 963 net Mmcfe per day for the division, a 35% increase over the prior year. The division's second quarter net production included 585 Mmcf per day of gas, 53,238 barrels per day of NGLs and 9,807 barrels per day of condensate. During the second quarter, 41 wells were turned in line in southwest Pennsylvania , with four wells in the super-rich area, 25 wells in the wet gas area and 12 wells in the dry gas area. For Marcellus wells brought on line in the second quarter, the average working interest was 97% net, and the average net revenue interest was 81%.
The Company brought on two dry gas wells in eastern Washington County during the second quarter. The 24-hour production rates for the two new wells averaged 34.2 Mmcf per day per well. The average lateral length of the wells was 9,074 feet with an average of 45 stages. The average seven-day and 30-day rates for the two wells were 30.1 Mmcf per day and 21.9 Mmcf per day, respectively, constrained by the production facilities and the gathering system. These two wells have been on production for 90 days and have produced approximately 1.8 Bcf each.
The previously announced Utica Shale well in Washington County, Pennsylvania continues to produce on an interruptible basis as permanent infrastructure is being constructed. The Company is currently completing its second Utica well on the same pad and expects to produce it, on a rate-restricted basis, into the newly constructed infrastructure. Similar to the first test, the second well has a 5,450 foot lateral and was completed with 32 stages last week. The Company plans to spud an additional Utica well before year-end at a location just east of these two wells. Range holds approximately 400,000 net acres in southwest Pennsylvania , considered prospective for Utica dry gas.
The current investor presentation on Range's website provides updated well economics with pricing as of June 30, 2015 for wells expected to be drilled in the second half of 2015. Rates of return in the Southwest dry area increased to 60% with improvement in expected realized natural gas prices, net of local basis and transportation contracts. With a reduction in the near term NGL pricing, the rates of return for the wet area decreased to 28% and the super-rich area to 26%. These rates of return for the liquid areas do not incorporate potential pricing improvement from selling NGLs in the international markets later in the year when Mariner East I is expected to commence operations.
During the second quarter, Range continued to realize operational efficiencies by averaging 6.3 frac stages per day which was up 21% compared to the 2014 average of 5.2 frac stages per day. Drilling efficiencies also continued in the second quarter as Range drilled an average lateral length of 5,938 feet in 15 days. This was a 13% decrease in days while drilling a 21% longer lateral compared to 2014 (17.2 days to drill 4,915 feet).
Northern Marcellus Shale Division --
In northeast Pennsylvania , production for the second quarter averaged 231 net Mmcf per day for the division, a 15% increase over the prior year. In the second quarter, 10 wells were turned in line, with an average working interest of 100% and average net revenue interest of 85%. The 10 new wells were turned in line throughout the month of June. Range is currently running one rig in order to satisfy the drilling obligations on larger leases. The Company anticipates turning four wells in line to sales for the remainder of 2015.
Updated pricing as of June 30, 2015 for Range's expected rates of return for wells drilled in the second half of 2015 are reflected in Range's current investor presentation on its website. Updated rates of return in the northeast dry area increased to 64% with improvement in expected realized natural gas pricing, net of local basis and transportation contracts.
Southern Appalachia Division --
Production for the second quarter averaged 109 net Mmcf per day for the division, a 42% increase over the prior year, primarily due to the increased volumes resulting from the Nora/Conger exchange with EQT, completed in June 2014 . The division drilled four coalbed methane (CBM) wells and completed nine CBM wells, three tight gas wells and one horizontal Huron well in the second quarter 2015. A total of 15 wells were turned in line in the quarter. The division continued development of the multi-pay horizons on its 465,000 net acre position while introducing new completion techniques and well designs, resulting in improved well performance. Because of these improvements, the CBM wells completed in 2014 and 2015 continue to be the best group of CBM wells in over 25 years in the Nora field. In addition to these new completion techniques resulting in higher production and higher rates of return, Range receives the added economic benefit of owning the royalty for wells drilled on its fee mineral acreage. The Virginia assets also receive a premium gas price due to their close proximity to the growing southeast markets along the Atlantic Coast . The division's 2015 budget is primarily designed to maintain its production.
Midcontinent Division --
The Midcontinent properties are now being operated out of the Fort Worth office. The current operating team has had some early success in reducing well costs, while testing improvements in targeting and completion design. During the quarter, four wells were turned to sales in the Mississippian Chat, where the team continues to high-grade the play northward along the Nemaha Ridge. Production rates for the most recent completions in the Horizontal Mississippian Chat play were comparable to past results. Importantly, the average completed well cost of the two wells drilled in the second quarter was $2.2 million , which is a reduction of 31% from the average $3.2 million well cost from a year ago. There is one additional well planned to be turned in line to sales in 2015.
Marcellus Shale Marketing and Transportation Update --
One of the most impactful changes in Range's marketing portfolio for the near term is the anticipated startup of the Mariner East I project to the Marcus Hook export facilities on the Atlantic Coast . Range will be the only producer holding capacity on the project. Range has 80% of the propane capacity (20,000 barrels per day) and 50% of the ethane capacity (20,000 barrels per day) on the project. Range believes that having direct access to these facilities will be an important competitive advantage in accessing new markets at better realizations.
Historically, pricing for Appalachian NGLs is lower in the summer months, as demand for summer propane is largely driven by storage needs, rather than heating demand. This summer has been no exception as netback prices for local Appalachian NGLs have been challenged. During summer months, Appalachian NGL products are transported further from the wellhead to reach incremental demand sales points. The increased cost of transport and lower gross sale prices are reflected in Range's pre-hedge NGL pricing of $8.02 per barrel for the quarter. While these historically low NGL prices are currently challenging Appalachian and domestic NGL producers, the situation highlights the distinct advantage that Mariner East I is expected to provide Range later this year.
Mariner East I is an ethane/propane pipeline that transports NGL products from southwest Pennsylvania to the Marcus Hook export facilities near Philadelphia . By contracting for propane capacity on Mariner East I, Range has effectively locked in a transportation cost that is much lower than what is currently being paid. Importantly, Mariner East I covers the vast majority of the Company's current propane production. Range expects that it will be able to market propane either domestically or internationally at equal to or better pricing than alternatives available in Appalachia . The expected pricing, combined with the transportation savings, should differentiate Range's NGL barrel realizations, especially during the summer of 2016. Transportation cost savings alone could approximate $50 million in additional cash flow on an annualized basis. Furthermore, by moving propane to the export facilities, Range will have the option to sell propane year-round to either domestic or international customers. Range believes that since its propane will be at an international purity standard of 97.5% rather than the domestic propane purity standard of 95%, the Company can attract certain international customers with higher purity standards. In addition, certain international customers will have advantaged shipping expenses via the Marcus Hook facility when compared to alternatives along the Gulf Coast . As the anchor shipper for the propane segment of Mariner East I, this opportunity is expected to translate into additional cash flow for Range in the interim while the Company seeks additional markets both domestically and internationally.
While the commencement of Mariner East I is expected to have a major impact on Range's net propane price, it will also add another outlet to Range's diversified ethane sales contract portfolio. Range expects that the optionality within its total ethane sales portfolio will improve the ability to consistently flow ethane production at the highest realizations available to any domestic producer. The Company's ethane contracts are expected to yield a sizeable uplift in revenue when compared to leaving ethane in the gas stream.
In addition to moving NGL production to better markets at lower costs with the commissioning of Mariner East I, Range is anticipating another tranche of natural gas transportation to come into service on August 1st . Range is the anchor shipper on Spectra's Uniontown to Gas City ("U2GC") project and has gross capacity of approximately 200 Mmcf per day, which is roughly half of the project. This additional capacity will afford Range the opportunity to move natural gas to the Midwest where pricing is at a substantial premium compared to southwest Pennsylvania markets where the natural gas is currently being sold. Based on current index pricing, Range would expect the sales price for the U2GC production to increase by more than $1.00 per Mmbtu after transportation costs for September and from $0.75 to $1.00 during the fourth quarter depending on actual winter pricing in the alternate local Appalachian markets. Approximately two-thirds of this basis improvement has been locked in for the coming twelve months with basis hedges and physical contracts. Currently, the 170 Mmcf per day capacity net to Range would equate to approximately 28% of Range's southwest Marcellus net natural gas production in the second quarter. This uplift has been included in the calculated fourth quarter 2015 corporate differential of an estimated $(0.34) based on current strip pricing and relative basis forecasts, which can be found in the Supplemental Tables on the Company's website. If realized, this would be an improvement of approximately $0.30 over second quarter differentials.
Financial Discussion
(Except for generally accepted accounting principles ("GAAP") reported amounts, specific expense categories exclude non-cash impairments, derivative fair value income/(loss), non-cash stock compensation and other items shown separately on the attached tables. "Total 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. "Total unit cash costs" are the same as "Total unit costs", except depletion, depreciation and amortization costs is excluded. 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 2015 totaled $248 million (a 68% decrease as compared to second quarter 2014), GAAP net cash provided from operating activities including changes in working capital reached $160 million and GAAP earnings was a loss of $119 million ($0.71 loss per diluted share) versus earnings of $171 million ($1.04 per diluted share) in the prior-year quarter. Second quarter 2015 results included $35 million in derivative losses due to increases in future commodity prices, compared to a $24 million loss in the second quarter of 2014. Second quarter 2015 results included a $3 million gain on the sale of assets compared to a gain of $282 million in second quarter 2014, when the Permian properties exchange was completed. Second quarter 2015 results also included a $7.3 million gain in the deferred compensation plan due to decreases in the Company's stock price compared to an expense of $10.5 million in second quarter 2014.
Non-GAAP revenues for second quarter 2015 totaled $405 million (a 16% decrease compared to second quarter 2014) and cash flow from operations before changes in working capital, a non-GAAP measure, was $161 million . Adjusted net income comparable to analysts' estimates, a non-GAAP measure, was $2 million ($0.01 per diluted share) for the second quarter 2015, compared to $59 million ($0.36 per diluted share) in the prior-year quarter. The Company's total unit cash costs of $1.75 per mcfe in second quarter 2015 decreased by $0.25 per mcfe or 13% compared to the prior-year quarter. The Company's total unit costs in second quarter 2015 decreased by $0.36 per mcfe or 11% compared to the prior-year quarter.
| Expenses | 2Q 2015 (per mcfe) | 2Q 2014 (per mcfe) | Increase (Decrease) | |||||
| Direct operating | $ | 0.27 | $ | 0.33 | -18% | |||
| Transportation, gathering and compression | 0.76 | 0.76 | - | |||||
| Production and ad valorem taxes | 0.07 | 0.11 | -36% | |||||
| General and administrative | 0.30 | 0.35 | -14% | |||||
| Interest | 0.35 | 0.45 | -22% | |||||
| $ | 1.75 | $ | 2.00 | -13% | ||||
| Depletion, depreciation and amortization | 1.22 | 1.33 | -8% | |||||
| $ | 2.97 | $ | 3.33 | -11% | ||||
Second 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 $3.07 per mcfe, a 32% decrease from the prior-year quarter. Additional detail on commodity price realizations can be found in the Supplemental Tables provided on the Company's website.
- Production and realized prices for each commodity for the second quarter of 2015 without the effect of hedging were: natural gas -- 964 Mmcf per day (
$1.96 per mcf); NGLs -- 56,100 barrels per day ($8.02 per barrel) and crude oil and condensate -- 11,972 barrels per day ($41.71 per barrel). - The second quarter average natural gas price decreased to
$2.95 per mcf (including the impact of cash-settled hedges), as compared to the prior-year quarter of$3.88 per mcf. Financial hedges based upon NYMEX increased realizations$0.97 per mcf while financial basis hedges increased realizations$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($0.66) per mcf, compared to($0.58) per mcf in the previous year. - NGL pricing, before hedges, but net of processing and transportation costs, was
$8.02 per barrel. NGL hedging increased prices$1.95 to $9.97 per barrel. - Crude oil and condensate price realizations, before hedges, for the second quarter averaged
$16.17 below West Texas Intermediate ("WTI"), or$41.71 . This compared to$16.19 below WTI in the first quarter of 2015 and$15.18 below WTI in the prior-year quarter. Hedging for the second quarter added$25.89 per barrel.
Financial Position and Liquidity
As previously announced on March 23 , Range's existing $3 billion borrowing base and $2 billion commitment amount under its $4 billion bank credit facility were unanimously reaffirmed by its 29 bank lending group. Under the terms of the credit agreement, the borrowing base will be renewed annually, with the current borrowing base in effect through May 1, 2016 . The facility has a maximum amount of $4 billion and matures in October 2019 . Liquidity at quarter-end stood at $1.5 billion under the commitment and the Company is comfortably in compliance with all the covenants under the facility.
In May 2015 , the Company issued $750 million of 4.875% senior notes due 2025 at par, representing the lowest yield of any non-investment grade energy or power sector issuer of any maturity term in 2015. The net proceeds from the senior notes were used to repay borrowings under the bank credit facility pending the redemption of higher cost senior subordinated notes. The call for redemption of all $500 million in outstanding principal of its 6.75% Senior Subordinated Notes due 2020 was announced in July. The notes will be redeemed at a price of 103.375% of the principal amount plus accrued interest on August 3, 2015 using borrowings under the Company's bank credit facility.
Guidance - Third Quarter 2015
Production Guidance:
Production growth for 2015 is targeted at 20% year-over-year. Average daily production for the third quarter of 2015 is expected to be 1.39 to 1.40 Bcfe per day with 28% liquids.
| Expense per mcfe Guidance: | ||||
| Direct operating expense: | $0.29 - $0.31 per mcfe | |||
| Transportation, gathering and compression expense(a) | $0.77 - $0.79 per mcfe | |||
| Production tax expense: | $0.08 - $0.09 per mcfe | |||
| Exploration expense: | $10 - $12 million | |||
| Unproved property impairment expense: | $12 - $14 million | |||
| G&A expense: | $0.30 - $0.32 per mcfe | |||
| Interest expense: | $0.33 - $0.34 per mcfe | |||
| DD&A expense: | $1.21 - $1.23 per mcfe | |||
Based on historical trends, base net expense for brokered natural gas and marketing activity is expected to be $5 million net expense per quarter.
| (a) | Start-up of Sunoco Logistics' Mariner East I project is expected during late September which will not fully impact transportation costs until 4Q 2015. |
Guidance for 2015 Activity:
Updated well economics can be found in the latest Company Presentation, located on the Range website at www.rangeresources.com. Average lateral lengths for Marcellus wells in 2015 are still expected to increase compared to 2014, averaging over 6,000 feet.
Under the current projection, Range expects to turn in line approximately 169 wells during 2015, as shown below. The number of wells expected to be turned in line has increased slightly during the year as cost savings have allowed additional wells to be completed, offset by the reduction in NGLs from Mariner East I not commencing operations in July as we originally expected. Additional dry gas production has replaced the expected additional NGL production.
| Wells turned in line - First Half 2015 | Expected remaining wells to turn in line 2015 | Total planned wells to turn in line for 2015 | ||||||
| Super-Rich area | 21 | 4 | 25 | |||||
| Wet area | 39 | 18 | 57 | |||||
| Dry- SW | 16 | 18 | 34 | |||||
| Dry- NE | 13 | 4 | 17 | |||||
| Total Marcellus/Utica | 89 | 44 | 133 | |||||
| Nora area | 21 | 4 | 25 | |||||
| Midcontinent | 10 | 1 | 11 | |||||
| Total | 120 | 49 | 169 | |||||
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 85% of its remaining 2015 natural gas production hedged at a weighted average floor price of $3.70 per Mmbtu. Similarly, Range has hedged approximately 90% of its remaining 2015 projected crude oil and condensate production at a floor price of $85.87 per barrel and over half of its remaining composite NGL production.
For calendar year 2016, Range has hedged 630,000 Mmbtu per day of its expected natural gas production at a weighted average price of $3.42 per Mmbtu and has started hedging 2017 gas volumes. Similarly, Range has hedged 3,000 barrels per day of its 2016 projected crude oil production at an average price of $70.54 per barrel and 10,500 barrels per day of its expected NGL production. Please see Range's detailed hedging schedule posted at the end of the financial tables below and on its website at www.rangeresources.com.
Basis Hedging Status
In addition to the collars and swaps above, at June 30, 2015 , Range had natural gas basis swap contracts which lock in the differential between NYMEX and certain physical pricing indices, primarily in Appalachia . These contracts settle monthly through March 2017 and the hedges cover 50,565,000 Mmbtu. The fair value of these contracts was an asset of $5.9 million at June 30, 2015 .
Conference Call Information
A conference call to review the financial results is scheduled on Wednesday, July 29 at 9:00 a.m., Eastern Time . To participate in the call, please dial 877-407-0778 and ask for the Range Resources second quarter 2015 financial results conference call. A replay of the call will be available through August 29 . To access the phone replay dial 877-660-6853. The conference ID is 13612457.
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 August 29 .
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 in 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.
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, future market improvements, maximizing future rates of return, strong inventory of uncompleted wells, expectation to create future value, expected lower well costs, acreage prospective for other horizons 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 Securities and Exchange Commission ("SEC"), which are incorporated by reference.
The SEC permits oil and gas companies, in filings made with the SEC , to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves. Range has elected not to disclose the Company's probable and possible reserves in its filings with the SEC . Range uses certain broader terms such as "resource potential," "unrisked resource potential," "unproved resource potential" or "upside" or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC's rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of actually being realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unproven resource potential has not been fully risked by Range's management. "EUR," or estimated ultimate recovery, refers to our management's estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System or the SEC's oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially. Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling and completion services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling and completion results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data.
In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street , Suite 1200,Fort Worth, Texas 76102. You can also obtain this Form 10-K on the SEC's website at www.sec.gov or by calling the SEC at 1-800-SEC -0330.
| 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, | ||||||||||||||||||||||
| 2015 | 2014 | % | 2015 | 2014 | % | ||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||
| Natural gas, NGLs and oil sales (a) | $ | 258,053 | $ | 477,517 | $ | 583,536 | $ | 1,049,534 | |||||||||||||||
| Derivative fair value (loss)/income | (34,791 | ) | (24,109 | ) | 88,048 | (170,959 | ) | ||||||||||||||||
| Gain on sale of assets | 2,909 | 282,064 | 2,734 | 281,711 | |||||||||||||||||||
| Brokered natural gas, marketing and other (b) | 21,248 | 30,274 | 35,681 | 63,523 | |||||||||||||||||||
| Equity method investment (b) | - | (144 | ) | - | (277 | ) | |||||||||||||||||
| ARO settlement gain (loss) (b) | 30 | (127 | ) | 28 | (786 | ) | |||||||||||||||||
| Other (b) | 61 | 49 | 115 | 120 | |||||||||||||||||||
| Total revenues and other income | 247,510 | 765,524 | -68 | % | 710,142 | 1,222,866 | -42 | % | |||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Direct operating | 34,126 | 32,998 | 70,377 | 71,941 | |||||||||||||||||||
| Direct operating - non-cash stock-based compensation (c) | 654 | 1,937 | 1,540 | 2,789 | |||||||||||||||||||
| Transportation, gathering and compression | 95,198 | 76,809 | 184,624 | 150,970 | |||||||||||||||||||
| Production and ad valorem taxes | 9,242 | 10,844 | 19,170 | 22,522 | |||||||||||||||||||
| Brokered natural gas and marketing | 26,412 | 33,645 | 47,468 | 67,246 | |||||||||||||||||||
| Brokered natural gas and marketing - non-cash stock- | 619 | 1,130 | 1,125 | 1,658 | |||||||||||||||||||
| based compensation (c) | |||||||||||||||||||||||
| Exploration | 4,274 | 12,399 | 11,428 | 26,092 | |||||||||||||||||||
| Exploration - non-cash stock-based compensation (c) | 751 | 1,222 | 1,483 | 2,375 | |||||||||||||||||||
| Abandonment and impairment of unproved properties | 12,330 | 9,332 | 23,821 | 19,327 | |||||||||||||||||||
| General and administrative | 37,113 | 35,399 | 73,776 | 72,599 | |||||||||||||||||||
| General and administrative - non-cash stock-based | 15,953 | 20,696 | 27,033 | 32,300 | |||||||||||||||||||
| compensation (c) | |||||||||||||||||||||||
| General and administrative - lawsuit settlements | 398 | 543 | 734 | 951 | |||||||||||||||||||
| General and administrative - bad debt expense | - | 250 | 250 | 250 | |||||||||||||||||||
| General and administrative - legal contingency | 2,500 | - | 2,500 | - | |||||||||||||||||||
| Termination costs | (17 | ) | - | 4,646 | - | ||||||||||||||||||
| Termination costs - non-cash stock-based compensation (c) | 434 | - | 1,721 | - | |||||||||||||||||||
| Deferred compensation plan (d) | (7,282 | ) | 10,519 | (12,906 | ) | 8,484 | |||||||||||||||||
| Interest expense | 43,479 | 45,488 | 82,686 | 90,889 | |||||||||||||||||||
| Loss on early extinguishment of debt | - | 24,596 | - | 24,596 | |||||||||||||||||||
| Depletion, depreciation and amortization | 151,895 | 133,361 | 299,185 | 262,043 | |||||||||||||||||||
| Impairment of proved properties and other assets | - | 24,991 | - | 24,991 | |||||||||||||||||||
| Total costs and expenses | 428,079 | 476,159 | -10 | % | 840,661 | 882,023 | -5 | % | |||||||||||||||
| (Loss) income before income taxes | (180,569 | ) | 289,365 | -162 | % | (130,519 | ) | 340,843 | -138 | % | |||||||||||||
| Income tax (benefit) expense: | |||||||||||||||||||||||
| Current | - | (1 | ) | - | 5 | ||||||||||||||||||
| Deferred | (61,975 | ) | 117,977 | (39,609 | ) | 136,928 | |||||||||||||||||
| (61,975 | ) | 117,976 | (39,609 | ) | 136,933 | ||||||||||||||||||
| Net (loss) income | $ | (118,594 | ) | $ | 171,389 | -169 | % | $ | (90,910 | ) | $ | 203,910 | -145 | % | |||||||||
| Net (Loss) Income Per Common Share: | |||||||||||||||||||||||
| Basic | $ | (0.71 | ) | $ | 1.04 | $ | (0.55 | ) | $ | 1.24 | |||||||||||||
| Diluted | $ | (0.71 | ) | $ | 1.04 | $ | (0.55 | ) | $ | 1.24 | |||||||||||||
| Weighted average common shares outstanding, as reported: | |||||||||||||||||||||||
| Basic | 166,421 | 161,909 | 3 | % | 166,230 | 161,354 | 3 | % | |||||||||||||||
| Diluted | 166,421 | 162,813 | 2 | % | 166,230 | 162,323 | 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-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, | ||||||||
| 2015 | 2014 | |||||||||
| (Unaudited) | (Audited) | |||||||||
| Assets | ||||||||||
| Current assets | $ | 136,441 | $ | 207,243 | ||||||
| Derivative assets | 237,167 | 363,049 | ||||||||
| Natural gas and oil properties, successful efforts method | 8,240,358 | 7,977,573 | ||||||||
| Transportation and field assets | 32,614 | 37,581 | ||||||||
| Other | 159,351 | 161,334 | ||||||||
| $ | 8,805,931 | $ | 8,746,780 | |||||||
| Liabilities and Stockholders' Equity | ||||||||||
| Current liabilities | $ | 489,063 | $ | 740,197 | ||||||
| Asset retirement obligations | 17,689 | 15,067 | ||||||||
| Bank debt | 364,000 | 723,000 | ||||||||
| Senior notes | 750,000 | - | ||||||||
| Senior subordinated notes | 2,350,000 | 2,350,000 | ||||||||
| 3,464,000 | 3,073,000 | |||||||||
| Deferred tax liability | 999,532 | 997,494 | ||||||||
| Derivative liabilities | 125 | - | ||||||||
| Deferred compensation liability | 156,460 | 178,599 | ||||||||
| Asset retirement obligations and other liabilities | 297,648 | 284,994 | ||||||||
| 1,453,765 | 1,461,087 | |||||||||
| Common stock and retained earnings | 3,383,772 | 3,460,517 | ||||||||
| Common stock held in treasury stock | (2,358 | ) | (3,088 | ) | ||||||
| Total stockholders' equity | 3,381,414 | 3,457,429 | ||||||||
| $ | 8,805,931 | $ | 8,746,780 | |||||||
| 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, | |||||||||||||||||
| 2015 | 2014 | % | 2015 | 2014 | % | ||||||||||||||
| Total revenues and other income, as reported | $ | 247,510 | $ | 765,524 | -68% | $ | 710,142 | $ | 1,222,866 | -42% | |||||||||
| Adjustment for certain special items: | |||||||||||||||||||
| Total change in fair value related to derivatives prior to settlement (gain) loss | 160,017 | (2,069 | ) | 134,668 | 40,197 | ||||||||||||||
| ARO settlement (gain) loss | (30 | ) | 127 | (28 | ) | 786 | |||||||||||||
| (Gain) loss on sale of assets | (2,909 | ) | (282,064 | ) | (2,734 | ) | (281,711 | ) | |||||||||||
| Total revenues, as adjusted, non-GAAP | $ | 404,588 | $ | 481,518 | -16% | $ | 842,048 | $ | 982,138 | -14% | |||||||||
| RANGE RESOURCES CORPORATION | |||||||||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||||
| (Unaudited, in thousands) | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||||||
| Net (loss) income | $ | (118,594 | ) | $ | 171,389 | $ | (90,910 | ) | $ | 203,910 | |||||||||
| Adjustments to reconcile net cash provided from continuing operations: | |||||||||||||||||||
| Loss (gain) from equity method investment, net of distributions | - | 364 | - | 3,096 | |||||||||||||||
| Deferred income tax (benefit) expense | (61,975 | ) | 117,977 | (39,609 | ) | 136,928 | |||||||||||||
| Depletion, depreciation, amortization and impairment | 151,895 | 158,352 | 299,185 | 287,034 | |||||||||||||||
| Exploration dry hole costs | 3 | - | 106 | 1 | |||||||||||||||
| Abandonment and impairment of unproved properties | 12,330 | 9,332 | 23,821 | 19,327 | |||||||||||||||
| Derivative fair value loss (income) | 34,791 | 24,109 | (88,048 | ) | 170,959 | ||||||||||||||
| Cash settlements on derivative financial instruments that do not qualify for hedge accounting | 125,226 | (26,178 | ) | 222,716 | (130,762 | ) | |||||||||||||
| Allowance for bad debts | - | 250 | 250 | 250 | |||||||||||||||
| Amortization of deferred issuance costs, loss on extinguishment of debt, and other | 1,732 | 26,939 | 3,090 | 29,812 | |||||||||||||||
| Deferred and stock-based compensation | 10,574 | 35,319 | 19,792 | 47,912 | |||||||||||||||
| (Gain) loss on sale of assets and other | (2,909 | ) | (282,064 | ) | (2,734 | ) | (281,711 | ) | |||||||||||
| Changes in working capital: | |||||||||||||||||||
| Accounts receivable | 19,260 | 42,918 | 73,695 | 1,275 | |||||||||||||||
| Inventory and other | (2,677 | ) | (1,514 | ) | (3,749 | ) | (6,872 | ) | |||||||||||
| Accounts payable | (3,606 | ) | 10,118 | 3,492 | 20,115 | ||||||||||||||
| Accrued liabilities and other | (6,546 | ) | (27,009 | ) | (50,955 | ) | (59,751 | ) | |||||||||||
| Net changes in working capital | 6,431 | 24,513 | 22,483 | (45,233 | ) | ||||||||||||||
| Net cash provided from operating activities | $ | 159,504 | $ | 260,302 | $ | 370,142 | $ | 441,523 | |||||||||||
| 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, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||||
| Net cash provided from operating activities, as reported | $ | 159,504 | $ | 260,302 | $ | 370,142 | $ | 441,523 | |||||||||
| Net changes in working capital | (6,431 | ) | (24,513 | ) | (22,483 | ) | 45,233 | ||||||||||
| Exploration expense | 4,271 | 12,399 | 11,322 | 26,091 | |||||||||||||
| Lawsuit settlements | 398 | 543 | 734 | 951 | |||||||||||||
| Legal contingency | 2,500 | - | 2,500 | - | |||||||||||||
| Equity method investment distribution / intercompany elimination | - | (220 | ) | - | (2,519 | ) | |||||||||||
| Loss on gas blending | - | - | - | - | |||||||||||||
| Termination costs | (17 | ) | - | 4,646 | - | ||||||||||||
| Non-cash compensation adjustment | 693 | 308 | 590 | (358 | ) | ||||||||||||
| Cash flow from operations before changes in working capital - a non-GAAP measure | $ | 160,918 | $ | 248,819 | $ | 367,451 | $ | 510,921 | |||||||||
| ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING | |||||||||||||||||
| (Unaudited, in thousands) | Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | ||||||||||||||
| Basic: | |||||||||||||||||
| Weighted average shares outstanding | 169,199 | 164,664 | 169,030 | 164,139 | |||||||||||||
| Stock held by deferred compensation plan | (2,778 | ) | (2,755 | ) | (2,800 | ) | (2,785 | ) | |||||||||
| Adjusted basic | 166,421 | 161,909 | 166,230 | 161,354 | |||||||||||||
| Dilutive: | |||||||||||||||||
| Weighted average shares outstanding | 169,199 | 164,664 | 169,030 | 164,139 | |||||||||||||
| Dilutive stock options under treasury method | (2,778 | ) | (1,851 | ) | (2,800 | ) | (1,816 | ) | |||||||||
| Adjusted dilutive | 166,421 | 162,813 | 166,230 | 162,323 | |||||||||||||
| 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 June 30, | Six Months Ended June 30, | |||||||||||||||||||
| 2015 | 2014 | % | 2015 | 2014 | % | ||||||||||||||||
| Natural gas, NGL and oil sales components: | |||||||||||||||||||||
| Natural gas sales | $ | 171,664 | $ | 275,726 | $ | 400,404 | $ | 621,952 | |||||||||||||
| NGL sales | 40,945 | 109,998 | 100,756 | 245,502 | |||||||||||||||||
| Oil sales | 45,444 | 86,881 | 82,376 | 175,002 | |||||||||||||||||
| Cash-settled hedges (effective): | |||||||||||||||||||||
| Natural gas | - | 3,626 | - | 4,794 | |||||||||||||||||
| Crude oil | - | 1,286 | - | 2,284 | |||||||||||||||||
| Total oil and gas sales, as reported | $ | 258,053 | $ | 477,517 | -46% | $ | 583,536 | $ | 1,049,534 | -44% | |||||||||||
| Derivative fair value income (loss), as reported: | $ | (34,791 | ) | $ | (24,109 | ) | $ | 88,048 | $ | (170,959 | ) | ||||||||||
| Cash settlements on derivative financial instruments - (gain) loss: | |||||||||||||||||||||
| Natural gas | (87,059 | ) | 16,637 | (142,928 | ) | 103,745 | |||||||||||||||
| NGLs | (9,966 | ) | 1,165 | (15,561 | ) | 14,437 | |||||||||||||||
| Crude Oil | (28,201 | ) | 8,376 | (64,227 | ) | 12,580 | |||||||||||||||
| Total change in fair value related to derivatives prior to settlement, a non GAAP measure | $ | (160,017 | ) | $ | 2,069 | $ | (134,668 | ) | $ | (40,197 | ) | ||||||||||
| Transportation, gathering and compression components: | |||||||||||||||||||||
| Natural gas | $ | 83,331 | $ | 68,280 | $ | 159,858 | $ | 133,579 | |||||||||||||
| NGLs | 11,867 | 8,529 | 24,766 | 17,391 | |||||||||||||||||
| Total transportation, gathering and compression, as reported | $ | 95,198 | $ | 76,809 | $ | 184,624 | $ | 150,970 | |||||||||||||
| Natural gas, NGL and oil sales, including cash-settled derivatives: (c) | |||||||||||||||||||||
| Natural gas sales | $ | 258,723 | $ | 262,715 | $ | 543,332 | $ | 523,001 | |||||||||||||
| NGL sales | 50,911 | 108,833 | 116,317 | 231,065 | |||||||||||||||||
| Oil sales | 73,645 | 79,791 | 146,603 | 164,706 | |||||||||||||||||
| Total | $ | 383,279 | $ | 451,339 | -15% | $ | 806,252 | $ | 918,772 | -12% | |||||||||||
| Production of oil and gas during the periods (a): | |||||||||||||||||||||
| Natural gas (mcf) | 87,737,330 | 67,761,616 | 29% | 168,237,366 | 129,779,197 | 30% | |||||||||||||||
| NGL (bbl) | 5,105,127 | 4,470,854 | 14% | 10,464,403 | 8,942,335 | 17% | |||||||||||||||
| Oil (bbl) | 1,089,417 | 989,609 | 10% | 2,228,377 | 2,024,754 | 10% | |||||||||||||||
| Gas equivalent (mcfe) (b) | 124,904,594 | 100,524,394 | 24% | 244,394,046 | 195,581,731 | 25% | |||||||||||||||
| Production of oil and gas - average per day (a): | |||||||||||||||||||||
| Natural gas (mcf) | 964,146 | 744,633 | 29% | 929,488 | 717,012 | 30% | |||||||||||||||
| NGL (bbl) | 56,100 | 49,130 | 14% | 57,814 | 49,405 | 17% | |||||||||||||||
| Oil (bbl) | 11,972 | 10,875 | 10% | 12,311 | 11,186 | 10% | |||||||||||||||
| Gas equivalent (mcfe) (b) | 1,372,578 | 1,104,664 | 24% | 1,350,243 | 1,080,562 | 25% | |||||||||||||||
| Average prices, including cash-settled hedges that qualify for hedge accounting before third party transportation costs: | |||||||||||||||||||||
| Natural gas (mcf) | $ | 1.96 | $ | 4.12 | -53% | $ | 2.38 | $ | 4.83 | -51% | |||||||||||
| NGL (bbl) | $ | 8.02 | $ | 24.60 | -67% | $ | 9.63 | $ | 27.45 | -65% | |||||||||||
| Oil (bbl) | $ | 41.71 | $ | 89.09 | -53% | $ | 36.97 | $ | 87.56 | -58% | |||||||||||
| Gas equivalent (mcfe) (b) | $ | 2.07 | $ | 4.75 | -57% | $ | 2.39 | $ | 5.37 | -56% | |||||||||||
| Average prices, including cash-settled hedges and derivatives before third party transportation costs: (c) | |||||||||||||||||||||
| Natural gas (mcf) | $ | 2.95 | $ | 3.88 | -24% | $ | 3.23 | $ | 4.03 | -20% | |||||||||||
| NGL (bbl) | $ | 9.97 | $ | 24.34 | -59% | $ | 11.12 | $ | 25.84 | -57% | |||||||||||
| Oil (bbl) | $ | 67.60 | $ | 80.63 | -16% | $ | 65.79 | $ | 81.35 | -19% | |||||||||||
| Gas equivalent (mcfe) (b) | $ | 3.07 | $ | 4.49 | -32% | $ | 3.30 | $ | 4.70 | -30% | |||||||||||
| Average prices, including cash-settled hedges and derivatives: (d) | |||||||||||||||||||||
| Natural gas (mcf) | $ | 2.00 | $ | 2.87 | -30% | $ | 2.28 | $ | 3.00 | -24% | |||||||||||
| NGL (bbl) | $ | 7.65 | $ | 22.44 | -66% | $ | 8.75 | $ | 23.89 | -63% | |||||||||||
| Oil (bbl) | $ | 67.60 | $ | 80.63 | -16% | $ | 65.79 | $ | 81.35 | -19% | |||||||||||
| Gas equivalent (mcfe) (b) | $ | 2.31 | $ | 3.73 | -38% | $ | 2.54 | $ | 3.93 | -35% | |||||||||||
| Transportation, gathering and compression expense per mcfe | $ | 0.76 | $ | 0.76 | 0% | $ | 0.76 | $ | 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 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, | |||||||||||||||||||||
| 2015 | 2014 | % | 2015 | 2014 | % | ||||||||||||||||||
| (Loss) income from operations before income taxes, as reported | $ | (180,569 | ) | $ | 289,365 | -162 | % | $ | (130,519 | ) | $ | 340,843 | -138 | % | |||||||||
| Adjustment for certain special items: | |||||||||||||||||||||||
| (Gain) loss on sale of assets | (2,909 | ) | (282,064 | ) | (2,734 | ) | (281,711 | ) | |||||||||||||||
| (Gain) loss on ARO settlements | (30 | ) | 127 | (28 | ) | 786 | |||||||||||||||||
| Change in fair value related to derivatives prior to settlement | 160,017 | (2,069 | ) | 134,668 | 40,197 | ||||||||||||||||||
| Abandonment and impairment of unproved properties | 12,330 | 9,332 | 23,821 | 19,327 | |||||||||||||||||||
| Loss on early extinguishment of debt | - | 24,596 | - | 24,596 | |||||||||||||||||||
| Impairment of proved property and other assets | - | 24,991 | - | 24,991 | |||||||||||||||||||
| Lawsuit settlements | 398 | 543 | 734 | 951 | |||||||||||||||||||
| Legal contingency | 2,500 | - | 2,500 | - | |||||||||||||||||||
| Termination costs | (17 | ) | - | 4,646 | - | ||||||||||||||||||
| Termination costs - non-cash stock-based compensation | 434 | - | 1,721 | - | |||||||||||||||||||
| Brokered natural gas and marketing - non-cash stock-based compensation | 619 | 1,130 | 1,125 | 1,658 | |||||||||||||||||||
| Direct operating - non-cash stock-based compensation | 654 | 1,937 | 1,540 | 2,789 | |||||||||||||||||||
| Exploration expenses - non-cash stock-based compensation | 751 | 1,222 | 1,483 | 2,375 | |||||||||||||||||||
| General & administrative - non-cash stock-based compensation | 15,953 | 20,696 | 27,033 | 32,300 | |||||||||||||||||||
| Deferred compensation plan - non-cash adjustment | (7,282 | ) | 10,519 | (12,906 | ) | 8,484 | |||||||||||||||||
| Income from operations before income taxes, as adjusted | 2,849 | 100,325 | -97 | % | 53,084 | 217,586 | -76 | % | |||||||||||||||
| Income tax expense, as adjusted | |||||||||||||||||||||||
| Current | - | (1 | ) | - | 5 | ||||||||||||||||||
| Deferred | 611 | 40,905 | 19,910 | 84,084 | |||||||||||||||||||
| Net income excluding certain items, a non-GAAP measure | $ | 2,238 | $ | 59,421 | -96 | % | $ | 33,174 | $ | 133,497 | -75 | % | |||||||||||
| Non-GAAP income per common share | |||||||||||||||||||||||
| Basic | $ | 0.01 | $ | 0.37 | -97 | % | $ | 0.20 | $ | 0.83 | -76 | % | |||||||||||
| Diluted | $ | 0.01 | $ | 0.36 | -97 | % | $ | 0.20 | $ | 0.82 | -76 | % | |||||||||||
| Non-GAAP diluted shares outstanding, if dilutive | 166,617 | 162,813 | 168,832 | 162,323 | |||||||||||||||||||
| RANGE RESOURCES CORPORATION | ||||||
| HEDGING POSITION AS OF JULY 28, 2015 - | ||||||
| (Unaudited) | ||||||
| Daily Volume | Hedge Price | |||||
| Gas (Mmbtu) | ||||||
| 3Q 2015 Swaps | 747,500 | $3.63 | ||||
| 3Q 2015 Collars | 145,000 | $4.07 - $4.56 | ||||
| 4Q 2015 Swaps | 727,500 | $3.63 | ||||
| 4Q 2015 Collars | 145,000 | $4.07 - $4.56 | ||||
| 2016 Swaps | 630,000 | $3.42 | ||||
| 2017 Swaps | 20,000 | $3.49 | ||||
| Oil (Bbls) | ||||||
| 3Q 2015 Swaps | 11,250 | $85.87 | ||||
| 4Q 2015 Swaps | 11,250 | $85.87 | ||||
| 2016 Swaps | 3,000 | $70.54 | ||||
| C3 Propane (Bbls) | ||||||
| 3Q 2015 Swaps | 14,000 | $0.614 | ||||
| 4Q 2015 Swaps | 12,000 | $0.547 | ||||
| 2016 Swaps | 5,500 | $0.596 | ||||
| C4 Normal Butane (Bbls) | ||||||
| 3Q 2015 Swaps | 3,500 | $0.719 | ||||
| 4Q 2015 Swaps | 3,500 | $0.719 | ||||
| 2016 Swaps | 2,500 | $0.725 | ||||
| C5 Natural Gasoline (Bbls) | ||||||
| 3Q 2015 Swaps | 4,000 | $1,164 | ||||
| 4Q 2015 Swaps | 4,000 | $1.164 | ||||
| 2016 Swaps | 2,500 | $1.230 | ||||
NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS
Investor Contacts:
Rodney Waller
Senior Vice President
817-869-4258
rwaller@rangeresources.com
David Amend
Investor Relations Manager
817-869-4266
damend@rangeresources.com
Laith Sando
Research Manager
817-869-4267
lsando@rangeresources.com
Michael Freeman
Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
or
Media Contact:
Matt Pitzarella
Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
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
or
Media Contact:
Director of Corporate Communications
724-873-3224
mpitzarella@rangeresources.com
www.rangeresources.com
Source: Range Resources Corporation
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