SOURCE: Range Resources Corporation

Range Resources Corporation

July 28, 2014 17:01 ET

Range Announces Second Quarter 2014 Results

FORT WORTH, TX--(Marketwired - Jul 28, 2014) - RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its second quarter 2014 financial 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 in Virginia and $145 million cash giving Range operating control of 350,000 net acres in Virginia 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, Jeff Ventura, Range's President and CEO, said, "We have confidence in our ability to grow our net production to 3 Bcfe per day, nearly three times where we are today. The wells have been identified, the compression and plants have been scheduled, and the takeaway capacity to multiple markets has been secured. Our long range plan, based on current strip pricing, estimates our operations to be cash flow positive in 2016. We believe our growth should coincide with the increased demand for natural gas, which will further accelerate our cash flow growth as prices improve. In addition, we expect continued improvements in our operating cost structure, more efficient capital spending, greater cost efficiency on gathering as we drill in areas of existing infrastructure and better well results as we continue to drill longer laterals with enhanced completion designs.

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 - July 28, 2014." 

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 Houston complex which reduced the Company's quarterly liquids production. The combined effect of the unplanned events with the MarkWest plant and Sunoco pipeline disruptions was an estimated reduction of cash flow by approximately $19 million for the quarter. Range was able to grow its production despite these issues due to the flexibility of its portfolio of properties and transportation outlets. Range was able to divert production to alternate facilities as well as bring on new dry gas wells earlier than planned in areas not affected by the disruptions. The MarkWest plant is now back on-line and production has been restored with the Mariner West pipeline back to full operational capacity. With these midstream issues resolved, Range's current net production from our Marcellus Shale Divisions is approximately 1 Bcfe net per day.

Marcellus Shale Marketing, Transportation and Processing Update -

During the second quarter, the Company continued expanding its marketing efforts towards new customers outside the Appalachian Basin and announced several marketing arrangements to support its future natural gas and natural gas liquids production growth. Specifically, the Company signed its first two LNG supply agreements, two additional ethane sales contracts and an agreement to transport up to 400,000 Mmbtu per day on Energy Transfer's Rover pipeline. The Rover system will provide Range the flexibility to move Marcellus natural gas north to Dawn, Ontario and south to the Gulf Coast. Being a foundation shipper on the planned Rover system, residue natural gas will be picked up at the tailgate of a new processing plant to be built, thus eliminating any gathering cost to move residue gas from the plant to a large diameter take away pipeline. Range believes it now has sufficient firm transportation capacity to support its net production growth to 3 Bcfe per day. Importantly, Range has been able to secure its firm transportation and firm sales at an average cost of $0.28 per Mmbtu through 2016 as a result of being the first mover in the Marcellus Shale. Range believes it currently has one of the most diverse portfolios of interstate pipeline firm transportation arrangements with some of the lowest costs per mcf in the Marcellus but plans to continue to add firm capacity to the extent that additional markets with higher potential netbacks become available. The Company currently sells on 11 different interstate pipelines into 21 different indices. This portfolio of low cost firm transportation agreements allows the Company to move gas to its diverse customer base that stretches from the Northeast to the Upper Midwest, the Gulf Coast, Florida and the Atlantic Coast. By building a large base of natural gas customers, the Company expects to have a source of growing demand and better realizations as a larger percentage of gas is sold into areas of growing demand. Accordingly, the Company expects its Marcellus price realizations to improve in the years ahead as compared to current prices being received in the Appalachian Basin. 

Since discovering the Marcellus, Range has become the largest producer of natural gas liquids in Appalachia. Given the current level of NGL production (over 50,000 barrels per day gross) and future expectations for growth in the liquids rich Marcellus, the Company has sought to diversify its customer base and not rely solely on a single customer or transportation outlet for its NGLs. This diversity of price and customers is shown in the ethane agreements that have been signed by the Company. Altogether, these agreements provide Range the ability to sell ethane in Canada, Europe, Mont Belvieu and to future petrochemical facilities in the Appalachian Basin. The portfolio of ethane sale agreements is estimated to provide an uplift of greater than 25% to the Company's ethane revenue, as compared to leaving the ethane in the gas stream, net of all transportation and processing costs. This is a meaningful impact to the Company's bottom line, as ethane currently accounts for more than half of its Marcellus NGL production. The next largest component in the Company's NGL production is propane, making up approximately 25% of current liquids production. Being located in the Northeast provides Range greater flexibility in marketing its propane. In the winter, the Company can sell its propane in the Northeast when regional demand is high. In the summer, the Company can sell propane locally into storage and off-season demand, while at the same time moving its products to international markets through the Marcus Hook terminal. Range has been utilizing the Marcus Hook terminal for the last three summers to export propane by ship to international customers. The transportation of propane to the export facility is currently being facilitated through a combination of rail and pipeline. However, when the propane portion of Mariner East pipeline is completed (currently projected to be the first half of 2015), the Company expects to increase its propane netbacks by as much as 20% through a combination of both higher international propane prices and lower transportation charges. It is expected that as Range continues to grow, it will have the scale necessary to provide international customers with butane, natural gasoline and condensate production as well. 

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 Pennsylvania, with 21 wells in the super-rich area, 10 wells in the wet area and five wells in the dry area. The initial production rates of the new wells averaged 17.6 (14.4 net) Mmcfe per day with 55% liquids including the dry gas wells, with an average lateral length of 4,365 feet. The division has 14 wells waiting on pipeline connection. 

In the dry gas area of southwest Pennsylvania, Range and others in the industry continue to prove the potential for high-rate natural gas wells in this area. Historically, Range has been less active in this area because the leases are predominantly held by production and Range has focused on its liquids production to meet its ethane commitments. The Company did bring on line five wells in the dry gas area for the quarter. The average 24-hour IP per stage of the wells brought on in the dry gas area was almost 1 Mmcf per day per stage or an average 24-hour IP rate of 19.3 Mmcf per day per well. Three of the dry gas wells drilled in eastern Washington County had been on line for more than 30 days and had a combined 30-day rate of approximately 48 Mmcf per day. These wells were drilled with average lateral lengths of 4,785 feet and completed with 25 frac stages. 

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 $850,000 per well by utilizing existing pads and roads. The Company will realize additional savings from optimizing existing gathering and compression infrastructure during production. 

During the quarter, the Company spud its initial dry gas Utica/Point Pleasant test from an existing Marcellus pad in Washington County, Pennsylvania. The horizontal length is planned to be approximately 6,500 feet with 32 frac stages using a reduced cluster spacing completion. Range will be conducting extensive scientific tests and collecting data with this well and anticipates that the completion results will be available by year-end.

Northern Marcellus Shale Division - 

In northeast Pennsylvania, production for the second quarter averaged 235 (200 net) Mmcfe per day for the division, a 9% increase over the prior year. Range drilled seven wells in the second quarter and turned five wells to sales. The division's backlog of wells waiting on pipeline connection remained at nine at quarter-end. The Company anticipates drilling another 14 wells in the area and turning 12 wells to sales for the remainder of 2014.

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 Virginia with the recent acquisition of the remaining half of Nora and its gathering system in exchange for Range's Permian properties. The Company also received $145 million in cash as part of the exchange. A highlight of the Nora area is Range's ownership of the mineral interest under most of the acreage providing Range an added economic benefit. The Virginia properties also receive some of the highest gas prices in Appalachia and are strategically located to supply gas to the growing southeast markets along the Atlantic Coast. With full operational control, the division is expected to focus on the sizable inventory of low cost, high return recompletions and workovers over the next couple years, while also drilling a mix of coalbed methane, tight gas and horizontal Huron Shale wells. The division is also introducing some new completion techniques and well designs resulting in improved well performance. In the second quarter, Range drilled one of its highest quality vertical tight gas wells in Nora. The well had an average 30-day rate of over 1 Mmcf per day and has an estimated EUR of approximately 1.5 Bcf at a cost of $430,000, yielding an estimated IRR of over 100%. 

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 $40 million by transferring the remaining planned capital from the Permian properties. 

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 $766 million (14% increase as compared to second quarter 2013), GAAP net cash provided from operating activities including changes in working capital reached $260 million (231% increase as compared to second quarter 2013) and GAAP earnings were $171 million ($1.04 per diluted share) versus net income of $144 million ($0.88 per diluted share) in the second quarter 2013. 

Several non-cash or non-recurring items impacted second quarter results. A $280 million pre-tax gain was recorded on the Permian asset exchange. A $25 million loss on the early extinguishment of debt was recorded after calling our highest coupon bonds (8%). A $25 million impairment of proved properties was provided on some legacy properties. A $11 million mark-to-market expense due to the increase in value of the Company's common stock held in the Company deferred compensation plan (which was fully funded on the date of grant), and $25 million of non-cash stock compensation expenses were recorded. 

Non-GAAP revenues for second quarter 2014 totaled $482 million (13% increase as compared to second quarter 2013), cash flow from operations before changes in working capital, a non-GAAP measure ("adjusted cash flow"), reached $249 million (a 10% increase as compared to second quarter 2013). Adjusted net income, a non-GAAP measure, for second quarter 2014 was $59 million (an 8% increase as compared to second quarter 2013). 

Total unit costs improved by $0.41 per mcfe or 11% compared to the prior-year quarter as every unit cost measure decreased, led by general and administrative costs, interest expense and lease operating expense all falling by 15% or more.

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 $19 million for the quarter. Year-over-year oil and condensate production increased 14%, NGL production rose 111%, while natural gas production was up 4%. The second quarter 2014 natural gas, NGLs and oil price realizations (including the impact of cash-settled hedges and derivative settlements which would correspond to analysts' estimates, a non-GAAP measure) averaged $4.49 per mcfe, an 11% decrease over the prior-year quarter of $5.02 per mcfe. 

  • 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 $318 million funded the drilling of 79 (75 net) wells and the completion of previously drilled wells. A 100% drilling success rate was achieved. In addition, during the second quarter, $59 million was expended on acreage, $4 million on gas gathering systems and $12 million for exploration expense. Range is on track with its 2014 capital expenditure budget of $1.52 billion. For financial reporting purposes, the Company recorded a $280 million pre-tax gain on the Permian asset exchange, including the cash portion of the exchange, and recorded a fair value for accounting purposes of $550 million for the Nora exchanged properties.

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 $0.02 gain per mcf on basis hedging in the second quarter, resulting in a corporate differential of $0.58 below NYMEX. Range has hedged Marcellus differentials for 370,000 Mmbtu per day through October 2014 and another 90,000 Mmbtu per day from November 2014 through March 2015 of its expected production which should provide a partial offset to the weaker than normal summer pricing in the third quarter. The fair value of the basis hedges based upon future strip prices as of June 30, 2014 was a gain of $12.7 million for the third quarter 2014, a gain of $9.8 million for the fourth quarter 2014 and a loss of $8.1 million for the first quarter 2015. The table below shows the components of the non-GAAP measure of "average natural gas realized prices" for the last five quarters for comparative purposes as it would be calculated by analysts. A similar analysis is shown on the Company's website for NGLs and condensate and crude oil.

                     
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 July 24, 2014, the calculated differential in each division would be the amounts shown in the table below. Basis at the various receipt points which we sell natural gas are inherently volatile, have wide spreads between the bid and ask indications and change on a daily basis. The table below represents the Company's calculated differentials at a point in time (July 24, 2014) not an expected future realized price. The percentages of expected production to be sold by indices are shown in the corporate presentation posted on the website and should be used along with the table below in modeling the expected differentials by division adjusted for the weighted average change in the indices from July 24, 2014 to the measurement date for each month. For comparative purposes, a table of historical basis settlements and actual differentials by division is included in Table 9 of the Supplemental Tables for second quarter 2014 on the Company's website.

                   
      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 $3.96 per Mmbtu and a weighted average ceiling price of $4.38 per Mmbtu. Similarly, Range has hedged more than 90% of its remaining 2014 projected crude oil production at a floor price of $92.82 per barrel and approximately 50% of its composite NGL production. 

As of June 30, 2014, Range has basis hedge contracts covering approximately 215,693 Mmbtu per day of expected natural gas production for July 2014 through March 2015. This consists of 370,000 Mmbtu per day through October 2014 and another 90,000 Mmbtu per day from November 2014 through March 2015. The fair value of the basis hedges based upon future strip prices as of June 30, 2014 was a gain of $12.7 million for the third quarter and a gain of $9.8 million for the fourth quarter. 

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 $4.17 per Mmbtu and a weighted average ceiling price of $4.34 per Mmbtu. Similarly, Range has hedged 9,600 barrels per day of its 2015 projected crude oil production at a floor price of $90.57 per barrel with less than 5% of its expected NGL production hedged due to the backwardation of the future price curve. Please see Range's detailed hedging schedule posted at the end of the financial tables below and on its website at www.rangeresources.com

Effective March 1, 2013, Range elected to discontinue hedge accounting and moved to mark-to-market accounting for its derivative contracts. The mark-to-market accounting treatment may create fluctuations in earnings as commodity prices change both positively and negatively, however, such mark-to-market adjustments have no cash flow impact. The impact to cash flow will occur as the underlying contracts are settled. As of June 30, 2014, the Company expects to reclassify into earnings in the balance of 2014, $3.1 million of unrealized net gains frozen in accumulated other comprehensive income due to the discontinuance of hedge accounting.

Conference Call Information
A conference call to review the financial results is scheduled on Tuesday, July 29th at 9:00 a.m. ET. To participate in the call, please dial 877-407-0778 and ask for the Range Resources second quarter 2014 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 13585193.

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 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 March 1, 2013, the Company de-designated all commodity contracts and elected to discontinue hedge accounting prospectively. The Company has provided additional information regarding natural gas, NGLs and oil sales in a supplemental table included with this release, which would correspond to amounts shown by analysts for natural gas, NGLs and oil sales realized, including cash-settled derivatives.

RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading independent oil and natural gas producer with operations focused in Appalachia and the Midcontinent region of the United States. The Company pursues an organic growth strategy targeting high return, low-cost projects within its large inventory of low risk, development drilling opportunities. The Company is headquartered in Fort Worth, Texas. More information about Range can be found at rangeresources.com.

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 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," or "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 services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling 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. 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 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,
 
    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

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