Range Reports Outstanding 2012 Results

  Range Reports Outstanding 2012 Results

Business Wire

FORT WORTH, Texas -- February 26, 2013

RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its 2012 financial
results.

2012 Highlights –

  *Reports record annual production of 753 Mmcfe per day, an increase of 36%
    over 2011, with fourth quarter oil and NGL volumes increasing 41%
  *Reports 29% increase in total proved reserves to 6.5 Tcfe, with oil and
    NGL reserves increasing 64%
  *Drill bit reserve replacement of 773% at $0.86 per mcfe all-in finding and
    development cost
  *Fourth quarter adjusted non-GAAP cash flow of $1.54 per share exceeds
    average First Call consensus estimates by 18 cents
  *Fourth quarter adjusted non-GAAP earnings of $0.46 per share exceeds
    average First Call consensus estimates by 17 cents
  *Unit costs continue to decline, highlighted by 32% reduction in lease
    operating costs compared to 2011
  *Innovative marketing arrangements increased price realizations from
    propane exports
  *Unrisked resource potential increases to 48 - 68 Tcfe, including 2.3 – 3.5
    billion barrels of oil and NGLs
  *Asset sale agreement recently executed for $275 million

As previously reported, production for 2012 averaged 753 Mmcfe per day, a 36%
increase over 2011. Fourth quarter 2012 production volumes averaged 844 Mmcfe
per day, another record high for Range. Fourth quarter 2012 production
increased 35% over the prior-year period and was 7% higher than third quarter
2012. Oil and NGL production increased 41% during the fourth quarter
reflecting the Company’s focus on its high return, liquids-rich plays during
2012.

Proved reserves increased 29% year-over-year to 6.5 Tcfe, driven by a 64%
increase in liquids reserves. All-in finding and development cost averaged
$0.86 per mcfe, while replacing 773% of production from drilling. Drill bit
finding cost averaged $0.67 per mcfe. Production and reserves per share on a
debt-adjusted basis increased 29% and 22%, respectively. This represents the
seventh consecutive year of double-digit per-share growth for both production
and reserves. Range’s unrisked unproved resource potential at year-end 2012
increased to 48 - 68 Tcfe; including 2.3 - 3.5 billion barrels of NGLs and
crude oil.

Commenting, Jeff Ventura, the Company’s President and CEO, said, “Range had
outstanding operational results for 2012. The Marcellus Shale play that Range
discovered in 2004 became the largest producing field in the U.S. in 2012. Our
million acre position in Pennsylvania provides for future growth with low
reinvestment risk and strong rates of return. The Marcellus fueled our 29%
increase in proved reserves while increasing our liquids reserves by 64%.
Year-over-year production was up 36% while our liquids growth in the fourth
quarter was 41% compared to the prior year quarter. Our cost structure per
mcfe improved in each quarter of 2012. All-in finding and development costs
continue to be under a dollar per mcfe with our three year average being $0.82
per mcfe and our three year reserve replacement averaging 815%. Consistent low
finding costs are now visibly translating into lower DD&A rates in our
financial statements, with $1.46 per mcfe in the fourth quarter. The lower
rate will help drive future earnings. Our reserves per well in the Marcellus
continue to improve as we gain additional production history and continue to
optimize drilling and completion designs.

“Looking ahead, 2013 should be even better than 2012. We expect to grow
production in the 20% to 25% range utilizing our existing low-cost, high rate
of return inventory. Range’s liquids production is expected to grow
disproportionately greater than overall production in 2013 as we continue to
focus the majority of our capital in our liquids-rich areas. With the
continued ramp up in production volumes, we expect our cost structure to
improve further as volumes grow faster than our absolute costs. Importantly,
with our access to the growing global markets for NGLs through our innovative
Mariner West and East projects we are increasing our price realizations and
improving our profit margins. In addition to the Marcellus, our Horizontal
Mississippian oil play is gaining substantial momentum and should add to our
liquids production and reserves, while the Cline Shale, Wolfberry and Utica
plays have exciting liquids potential. We are looking for 2013 to be a year of
increasing production, reserves, cash flow and earnings which should translate
into higher per share value for all Range shareholders.”

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. We sold substantially all of our
Barnett Shale properties in April 2011. Under GAAP, activity for our Barnett
Shale properties was reclassified as “Discontinued operations.” As a result,
production, revenue and expenses associated with these properties were removed
from continuing operations and reclassified as discontinued operations. In
this release, supplemental Statements of Operations are presented to reconcile
the changes to the prior-year periods for the reclassification of our Barnett
Shale properties to discontinued operations. These supplemental non-GAAP
tables present the reported GAAP amounts and the amounts that would have been
reported if the Barnett Shale operations were included in continuing
operations. All variances discussed in this release include the Barnett Shale
operations as continuing operations in all prior year periods.)

Full Year 2012

GAAP revenues for 2012 totaled $1.5 billion (18% increase as compared to
2011), GAAP net cash provided from operating activities including changes in
working capital reached $647 million ($4.04 per diluted share) and GAAP
earnings were $13 million ($0.08 per diluted share) versus $58 million ($0.36
per diluted share) in 2011. 2012 results were driven by record high production
and a decrease in unit costs, offset by a 23% decline in realized prices.

Non-GAAP revenues for 2012 totaled $1.4 billion (11% increase compared to
2011), cash flow from operations before changes in working capital, a non-GAAP
measure, reached $756 million ($4.71 per diluted share versus consensus of
$4.33 per share). Adjusted net income, a non-GAAP measure, was $148 million
($0.92 per diluted share for 2012 versus average First Call consensus
estimates of $0.74 per share). Wellhead prices, after adjustment for all
cash-settled hedges and derivatives, averaged $5.05 per mcfe. The Company’s
cost structure continued to improve as total unit costs decreased by $0.40 per
mcfe or 9% as compared to the prior year. Direct operating expenses for the
year averaged $0.41 per mcfe, a 32% decrease compared to the prior year.
Depreciation, depletion and amortization expense decreased 7% to $1.62 per
mcfe.

Fourth Quarter

GAAP revenues for the fourth quarter of 2012 totaled $458 million (51%
increase as compared to fourth quarter 2011), GAAP net cash provided from
operating activities including changes in working capital reached $186 million
($1.16 per diluted share) and GAAP earnings were $53 million ($0.32 per
diluted share) versus a net loss of $3 million ($0.02 loss per diluted share)
in 2011. Fourth quarter results were driven by a 35% increase in production
and lower unit costs.

Non-GAAP revenues for fourth quarter 2012 totaled $418 million (19% increase
compared to fourth quarter 2011), cash flow from operations before changes in
working capital, a non-GAAP measure, reached $248 million ($1.54 per diluted
share versus average First Call consensus estimates of $1.36 per share).
Adjusted net income, a non-GAAP measure, was $73 million ($0.46 per diluted
share for the fourth quarter 2012 versus average First Call consensus
estimates of $0.29 per share). Wellhead prices, after adjustment for all
cash-settled hedges and derivatives, averaged $5.35 per mcfe. The Company’s
total unit costs decreased by $0.36 per mcfe or 9% compared to the prior-year
quarter. Direct operating expenses for the quarter were $0.38 per mcfe, a 16%
decrease compared to the prior-year quarter. Depreciation, depletion and
amortization expense decreased 14% to $1.46 per mcfe.

See “Non-GAAP Financial Measures” for a definition of each of these non-GAAP
financial measures and tables that reconcile each of these non-GAAP measures
to their most directly comparable GAAP financial measure.

Balance Sheet

During 2012, Range strengthened its balance sheet with the sale of its Ardmore
Woodford and other miscellaneous properties for approximately $170 million.
The sale proceeds were used to pay down the outstanding balance on its bank
credit facility. At year-end 2012, following the redemption of $250 million in
high-coupon 7.5% bonds, the Company had over $900 million of liquidity on its
credit facility. Increasing quarterly cash flow and the proceeds from
additional asset sales are expected to strengthen the balance sheet in 2013.

Recent Asset Sale Agreement

Range recently entered into an agreement to sell certain of its Permian Basin
properties in southeast New Mexico and West Texas for a purchase price of $275
million. The sale is expected to close in April and is subject to customary
closing conditions and purchase price adjustments. The properties being sold
consist of approximately 7,000 net acres that are currently producing
approximately 18 Mmcfe per day with approximately 70% being natural gas and
30% oil and NGLs. With this sale, the Company will have sold $2.3 billion in
assets since 2004 while focusing its resources and personnel on the highest
rate of return projects in the portfolio.

Hedging Status

Range hedges portions of its expected future production volumes to increase
the predictability of its cash flow and to help maintain a strong, flexible
financial position. Range currently has over 70% of its expected 2013 natural
gas production hedged at a weighted average floor price of $4.18 per mcf.
Similarly, Range has hedged more than 80% of its projected crude oil
production at a floor price of $94.55 and more than 50% of its composite NGL
production near current market prices. Please see Range’s detailed hedging
schedule posted at the end of the financial tables below and on its website at
http://www.rangeresources.com.

Operational Discussion

Range has updated its investor presentation with acreage maps, updated
economic sensitivity analysis and other financial and operational information.
Please see www.rangeresources.com under the Investor Relations tab,
“Presentations and Webcasts” area, for the presentation entitled, “Company
Presentation - February 26, 2013.”

Fourth quarter drilling expenditures of $234 million funded the drilling of 64
(54 net) wells. A 100% success rate was achieved. Drilling expenditures for
2012 totaled $1.36 billion, and Range drilled 298 (257 net) wells and 4 (4
net) recompletions during the year. Total capital spending for 2012 was $1.62
billion, including $189 million for leasehold. All-in finding and development
cost for 2012 averaged $0.86 per mcfe, with drill bit reserve replacement of
773%. Drill bit only finding cost averaged $0.67 per mcfe.

Marcellus Shale -

Range continued to make significant progress in the Marcellus Shale during
2012 as we continued to grow production and reserves and delineate our sizable
acreage position while expanding our current and future marketing and
transportation capabilities for natural gas and NGLs. Range was able to reach
its year-end production target of 600 Mmcfe per day net with approximately 75%
of that production coming from the liquids-rich area of the play. Another
milestone for Range in 2012 was the signing of two additional ethane
transportation agreements, ATEX and Mariner East; the culmination of several
years of planning. Mariner East will also transport propane to the northeast
United States for both domestic consumption and export to international
markets. Ethane exports to Canada under the first ethane sales agreement are
expected to commence on time in mid-2013. These ethane sales are expected to
allow Range to meet natural gas pipeline quality requirements for the
foreseeable future and are expected to eliminate shut-in production risk in
the liquids-rich area. Prior to the Mariner East pipeline being completed in
2014, Range is shipping propane by rail for export through the Marcus Hook
port facility near Philadelphia to the international market. This innovative
arrangement increased our NGL realizations in the fourth quarter of 2012.
Additional exports of propane are planned for 2013.

Southern Marcellus Shale Division -

In early February, Range revised its estimated ultimate recovery (“EUR”) for
wells drilled in both the wet and super-rich areas of the Southern Marcellus
Shale division. In the super-rich area, Range estimates wells will cost $5.1
million in development mode to drill and complete with a lateral length of
3,800 feet and 18 frac stages. This is expected to develop an EUR of 1.44
million barrels of oil equivalent that is 57% liquids (109 thousand barrels
condensate, 715 thousand barrels NGLs and 3.7 Bcf gas). These projected
well-level economics generate a 93% rate of return based on NYMEX “strip
pricing” as of December 31, 2012. In the wet area, Range estimates wells will
cost $4.9 million in development mode to drill and complete with a lateral
length of 3,200 feet and 13 frac stages. This is expected to develop an EUR of
8.7 Bcf equivalent that is 49% liquids (27 thousand barrels condensate, 685
thousand barrels NGLs and 4.4 Bcf gas). These projected well-level economics
generate a 78% rate of return based on NYMEX “strip pricing” as of December
31, 2012.

During the fourth quarter, the division brought online 30 horizontal wells in
southwest Pennsylvania, 26 of which were located in the liquids-rich area of
the play. The initial production rates of the new wells averaged 6.5 (5.1 net)
Mmcfe per day consisting of 3.9 (3.0 net) Mmcf per day of natural gas and 432
(355 net) barrels of NGLs and condensate per day. Twenty-two of the wells
brought online in the fourth quarter were in the super-rich area of the play,
eight of which utilized reduced cluster spacing completions. In January, the
division completed a three-well pad in the super-rich area at the combined
24-hour rate of 6,123 (5,220 net) boe per day that was 68% liquids (1,209
barrels condensate, 2,956 barrels NGLs and 11.7 Mmcf gas). In February, the
division completed two wells on another super-rich area pad at the combined
24-hour rate of 6,866 (5,685 net) boe per day that was 59% liquids (793
barrels condensate, 3,260 barrels NGLs and 16.9 Mmcf gas).

In the southwest Marcellus, the Company drilled and cased 25 wells in the
fourth quarter and the Company turned to sales 30 wells. As a result, the
Company’s backlog of uncompleted wells and wells waiting on pipeline
connection declined to 58. The division is currently utilizing six rigs and
plans to maintain similar activity levels throughout 2013.

Northern Marcellus Shale Division -

In the northeast Marcellus, Range drilled and cased eight wells in the fourth
quarter. A significant well was drilled in Lycoming County that produced at a
24-hour rate of 14.2 (12.2 net) Mmcf per day from a lateral of 2,475 feet and
nine frac stages. In total, 11 wells were turned to sales in the fourth
quarter. As a result, the Company’s backlog of uncompleted wells and wells
waiting on pipeline connection declined to 28 wells at year-end. We are
currently running two rigs in northeast Pennsylvania and anticipate running
one or two rigs for 2013 to maintain continuous drilling commitments under the
leases.

In the Bradford County participating area with Talisman, there were a total of
17 (4.5 net) wells producing, 13 (3.5 net) wells waiting on completion and 24
(6.5 net) wells waiting on pipeline.

In northwest Pennsylvania, Range drilled its first Utica well (50% WI) on its
181,000 net acres. The well encountered 285 feet of Utica/Point Pleasant pay
at a depth of approximately 7,000 feet. The well confirmed that we are in the
wet gas window and have good pressure. Diagnostics indicate that the well was
not effectively stimulated and to date has tested at just over 1.4 Mmcfe per
day. However, we are encouraged by the well data and we are monitoring offset
activity as we choose the timing of our next test.

Midcontinent Division -

Midcontinent operations in the fourth quarter focused on the Horizontal
Mississippian play in Oklahoma and Kansas along the Nemaha Ridge. Recently,
the division drilled a well with a 24-hour initial production rate of 812 (710
net) boe per day that was 82% liquids (458 barrels oil, 207 barrels NGLs and
0.9 Mmcf gas) from a lateral that was limited to 2,342 feet due to unit size.
With five rigs currently running, completion activity is expected to build
late in the first quarter of 2013.

During the fourth quarter, 9 (8.2 net) wells were turned to sales with average
lateral lengths of 3,800 feet and 20 frac stages. Average 7-day rates for the
completions were 482 (363 net) boe per day with 76% liquids. Additionally, we
now have 30-day rates on two of our previously announced 1,000+ boe per day
wells that were drilled in the fourth quarter. The Dakota #9-5S achieved a
30-day average rate 802 (654 net) boe per day (348 barrels oil, 265 barrels
NGLs and 1.1 Mmcf gas). The Troche #1-4N had a 30-day average of 615 (372 net)
boe per day (361 barrels oil, 148 barrels NGLs and 0.6 Mmcf gas). The current
leasehold position of approximately 160,000 net acres is expected to be held
by production with the drilling schedule we have planned through 2015. A total
of 51 Horizontal Mississippian and 17 saltwater disposal wells are expected to
be drilled in 2013.

In addition, a one rig program is anticipated in the Texas Panhandle for most
of 2013 where Range has had some early success drilling Horizontal St. Louis
wells. Another St. Louis well was completed in the fourth quarter for 10.9
(4.3 net) Mmcfe per day (7.8 Mmcf gas, 203 barrels oil and 314 barrels NGLs).
Six to eight additional test wells are planned for drilling in 2013.

Permian Division -

Range’s Permian team is targeting the Wolfberry and Cline Shale oil plays in
West Texas. In the Wolfberry, Range completed three additional wells in the
fourth quarter. The average 24-hour initial production rate for these wells
was 521 (406 net) boe per day with 78% liquids (301 barrels oil, 104 barrels
NGLs and 0.7 Mmcf gas). In addition to higher initial rates in the Wolfberry,
drill and completion costs were reduced to $2.4 million for the most recent
three wells. The six Wolfberry wells drilled to date are producing above our
initial forecasts. In the Cline Shale, Range completed its third well in the
fourth quarter. The initial 24-hour rate on this well was 620 (511 net) boe
per day with 77% liquids (231 barrels oil, 249 barrels NGLs and 0.8 Mmcf gas).
Range will continue to test these plays throughout 2013, while monitoring
industry activity in an area where Range has approximately 100,000 net acres
that are over 90% held by production.

Southern Appalachia Division -

The Southern Appalachia Division continued development of multi-pay horizons
on its 350,000 (235,000 net) acre position in Virginia during the fourth
quarter. The division had one drillingrig and one completion rig running in
the quarter and drilled 2 (2 net) tight gas sand wells and turned online 4 (4
net) wells. Despite spending only $29 million in capital in 2012, (down
approximately 50% versus prior year), the division’s 2012 production rate was
up 2% compared to 2011.

Guidance – First Quarter 2013

Production per day Guidance:

Production growth for 2013 is targeted at 20%-25% year-over-year. Production
for the first quarter of 2013 is expected to range between 845 to 850 Mmcfe
per day. Liquids are expected to be approximately 20% of first quarter
production. Daily liquids production is expected to be slightly lower in the
first quarter of 2013 compared to fourth quarter of 2012. This is the result
of completion timing and the mix of wells being turned on. In the winter the
Company typically completes fewer wells due to weather, as is typical in
Appalachia. As a result of fewer completions and fewer wells being turned on,
first quarter production will be relatively flat, while liquids will decline
slightly. The relatively small set of wells being turned to sales in first
quarter has some high-return dry gas wells which keeps that portion of the
production growing in first quarter 2013. Range expects completions and wells
being turned to sales to accelerate throughout the rest of the year and that
activity is expected to be weighted toward the liquids-rich areas. As a
result, Range is expecting liquids production growth during 2013 to be greater
than the 20%-25% year-over-year overall production growth target.

Expense per mcfe Guidance:

Direct operating expense:                              $0.38 - $0.40 per mcfe
Transportation, gathering and compression expense       $0.75 - $0.77 per mcfe
(a):
Production tax expense (b):                             $0.14 - $0.15 per mcfe
Exploration expense:                                    $18 - $20 million
Unproved property impairment expense:                   $15 - $17 million
G&A expense:                                            $0.40 - $0.42 per mcfe
Interest expense:                                       $0.55 - $0.57 per mcfe
DD&A expense:                                           $1.46 - $1.48 per mcfe

(a) Prior to year-end 2011 this expense was netted against revenue. Please
refer to Table 6 of the 4Q 2012 Supplement Tables for historical detail of
this expense by product.

(b) Production tax expense in first quarter should equal approximately $0.07
per mcfe plus an estimated $6.2 million for the Pennsylvania impact fee. Total
production tax expense including the impact fee is expected to be $0.14 -
$0.15 per mcfe.

Differential Pricing History (c)

              3Q 2011   4Q 2011   1Q 2012   2Q 2012   3Q 2012   4Q 2012
Natural Gas    $ 0.26     $ 0.07     ($0.02 )   ($0.13 )   ($0.03 )   $ 0.18
NGL (% of        54   %     54   %   48     %   39     %   33     %     43   %
WTI NYMEX)
Oil (% of        91   %     92   %   88     %   91     %   90     %     89   %
WTI NYMEX)

(c) Differentials based on pre-hedge pricing, excluding transportation,
gathering and compression expense.

Conference Call Information

A conference call to review the financial results is scheduled on Wednesday,
February 27 at 9:00 a.m. ET. To participate in the call, please dial
877-407-0778 and ask for the Range Resources 2012 financial results conference
call. A replay of the call will be available through March 29. To access the
phone replay dial 877-660-6853. The conference ID is 409202.

A simultaneous webcast of the call may be accessed over the Internet at
http://www.rangeresources.com/ or http://www.vcall.com/. The webcast will be
archived for replay on the Company's website until March 29.

Non-GAAP Financial Measures:

Adjusted net income comparable to analysts’ estimates as set forth in this
release represents income 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 useful 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 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.

Cash flow from operations before changes in working capital 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.

Range has disclosed two primary metrics in this release to measure our ability
to establish a long-term trend of adding reserves at a reasonable cost – a
reserve replacement ratio and finding and development cost per unit. The
reserve replacement ratio is an indicator of our ability to replace annual
production volumes and grow our reserves. It is important to economically find
and develop new reserves that will offset produced volumes and provide for
future production given the inherent decline of hydrocarbon reserves as they
are produced. We believe the ability to develop a competitive advantage over
other natural gas and oil companies is dependent on adding reserves in our
core areas at lower costs than our competition. The reserve replacement ratio
is calculated by dividing production for the year into the total of proved
extensions, discoveries and additions and proved reserves added by performance
revisions.

Finding and development cost per unit is a non-GAAP metric used in the
exploration and production industry by companies, investors and analysts. The
calculations presented by the Company are based on costs incurred excluding
asset retirement obligations and divided by proved reserve additions
(extensions, discoveries and additions shown in the summary of changes in
proved reserves table) adjusted for the changes in proved reserves for
performance revisions (drill bit) and for performance and price revisions
(all-in). This calculation does not include the future development costs
required for the development of proved undeveloped reserves. The SEC method of
computing finding costs contains additional cost components and results in a
higher number. A reconciliation of the two methods is shown on our website at
www.rangeresources.com.

The reserve replacement ratio and finding and development cost per unit are
statistical indicators that have limitations, including their predictive and
comparative value. As an annual measure, the reserve replacement ratio can be
limited because it may vary widely based on the extent and timing of new
discoveries and the varying effects of changes in prices and well performance.
In addition, since the reserve replacement ratio and finding and development
cost per unit do not consider the cost or timing of future production of new
reserves, such measures may not be an adequate measure of value creation.
These reserves metrics may not be comparable to similarly titled measurements
used by other companies.

Year-end pre-tax discounted present value is considered a non-GAAP financial
measure as defined by the SEC. We believe that the presentation of pre-tax
discounted present value is relevant and useful to our investors because it
presents the discounted future net cash flows attributable to our proved
reserves prior to taking into account corporate future income taxes and our
current tax structure. We further believe investors and creditors use pre-tax
discounted present value as a basis for comparison of the relative size and
value of our reserves as compared with other companies. Range’s pre-tax
discounted present value as of December 31, 2012 may be reconciled to its
standardized measure of discounted future net cash flows as of December 31,
2012 by reducing Range’s pre-tax discounted present value by the discounted
future income taxes associated with such reserves.

Reconciliation of PV-10

($ in millions) (unaudited)
                                                           December 31, 2012
Standardized measure of discounted future net of cash       $      3,224
flows
Discounted future cash flows for income taxes                      736
Discounted future net cash flows before income taxes         $      3,960
(PV-10)
                                                                    

Range has disclosed a debt-adjusted per share metric in this release to
measure per-share growth of production and reserves. This debt-adjusted metric
keeps the debt-to-capitalization ratio unchanged during the calculation
period. To achieve a constant debt-to-capitalization ratio, the share count is
adjusted to increase/decrease equity from the actual end-of-year to the
beginning of period level debt-to-cap. This adjustment is made by dividing the
necessary increase/decrease in equity by the average common share price during
the year for production (year-end price for reserves) to arrive at shares
issued/repurchased. The production or reserves are then divided by this
adjusted share count to reach the debt-adjusted per share results.

Hedging and Derivatives

In this news release, Range has reclassified within total revenues its
financial reporting of the cash settlement of its commodity derivatives. Under
this presentation those hedges considered “effective” under ASC 815 are
included in “Natural gas, NGLs and oil sales” when settled. For those hedges
designated to regions where the historical correlation between NYMEX and
regional prices is “non-highly effective” or is “volumetric ineffective” due
to sale of the underlying reserves, they are deemed to be “derivatives” and
the cash settlements are included in a separate line item shown as “Derivative
fair value income (loss)” in the consolidated statements of operations
included in the Company’s Form 10-K along with the change in mark-to-market
valuations of such unrealized derivatives. 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 southwest
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
http://www.rangeresources.com/ and http://www.myrangeresources.com/.

Except for historical information, statements made in this release such as
future growth in production, reserves, cash flow, earnings and per-share
value, low-reinvestment risk, future rates of return, continued drilling
improvements, disproportionate growth in liquids production and reserves, cost
structure improvements, future price realizations, expected sales proceeds,
planned exports, estimated cost, and expected drilling plans 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 and environmental risks. 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,""upside" and “EURs per well” 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 being
actually 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, unrisked resource potential
has not been fully risked by Range's management. “EUR,” or estimated ultimate
recovery, refers to our management’s internal estimates of per well
hydrocarbon quantities that may be potentially recovered from a hypothetical
future well completed as a producer in the area. These quantities do 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. Our management estimated these EURs based on
our previous operating experience in the given area and publicly available
information relating to the operations of producers who are conducting
operating in these areas. Actual quantities that may be ultimately recovered
from Range's interests will 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. 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 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-K
(Unaudited, in
thousands, except   Three Months Ended December 31,      Twelve Months Ended December 31,
per share data)
                    2012        2011       %        2012          2011         %   
Revenues and
other income:
  Natural gas,
  NGLs and oil      $ 398,688     $ 331,720              $ 1,351,694     $ 1,173,266
  sales (a)
  Derivative cash
  settlements         16,706        13,800                 38,700          22,142
  gain (loss) (a)
  (b)
  Change in
  mark-to-market
  on unrealized       (24,117 )     (51,331 )
  derivatives
  gain (loss) (b)                                          5,958           15,762
  Ineffective
  hedging (loss)      1,840         (348    )              (3,221    )     2,183
  gain (b)
  Gain (loss) on
  sale of             61,836        3,539                  49,132          2,259
  properties
  Brokered
  natural gas and     2,948         3,770                  15,078          12,693
  marketing (c)
  Equity method       (177    )     356                    (372      )     (1,043    )
  investment (c)
  Other (c)          314         1,712                735           3,380     
  Total revenues
  and other          458,038     303,218    51   %    1,457,704     1,230,642    18  %
  income
Costs and
expenses:
  Direct              29,446        25,347                 113,490         110,985
  operating
  Direct
  operating –
  non-cash stock      768           571                    2,415           1,987
  compensation
  (d)
  Transportation,
  gathering and       55,281        34,576                 192,445         120,755
  compression
  Production and
  ad valorem          9,380         5,920                  41,912          26,666
  taxes
  Pennsylvania
  impact fee -        501           -                      25,208          -
  prior year
  Brokered
  natural gas and     4,542         2,803                  18,669          10,531
  marketing
  Brokered
  natural gas and     452           348                    1,765           1,455
  marketing –
  non-cash stock-
  based
  compensation
  (d)
  Exploration         17,021        24,042                 65,758          77,259
  Exploration –
  non-cash stock      1,001         940                    4,049           4,108
  compensation
  (d)
  Abandonment and
  impairment of       21,230        27,639                 125,278         79,703
  unproved
  properties
  General and         31,402        32,647                 125,355         113,461
  administrative
  General and
  administrative
  – non-cash          13,786        8,756
  stock
  compensation                                             44,541          36,244
  (d)
  General and
  administrative      644           302                    3,167           540
  – lawsuit
  settlements
  General and
  administrative      750           500                    750             946
  – bad debt
  expense
  Deferred
  compensation        (14,352 )     9,640                  7,203           43,209
  plan (e)
  Interest            44,708        34,709                 168,798         125,052
  expense
  Loss on early
  extinguishment      11,063        -                      11,063          18,576
  of debt
  Depletion,
  depreciation        113,216       97,092                 445,228         341,221
  and
  amortization
  Impairment of
  proved             34,273      -                    35,554        38,681    
  properties and
  other assets
  Total costs and    375,112     305,832    23   %    1,432,648     1,152,379    24  %
  expenses
                                                                                         
Income (loss)
from continuing       82,926        (2,614  )   3272 %     25,056          78,263        -68 %
operations before
income taxes
                                                                                         
Income tax
expense
(benefit):
  Current             (1,778  )     636                    (1,778    )     637
  Deferred           31,742      (425    )             13,832        34,920    
                     29,964      211                  12,054        35,557    
                                                                                         
Income (loss)
from continuing       52,962        (2,825  )   1975 %     13,002          42,706        -70 %
operations
                                                                                         
Discontinued
operations, net      -           (164    )             -             15,320    
of tax
                                                                                         
Net income (loss)   $ 52,962     $ (2,989  )   1872 %   $ 13,002       $ 58,026       -78 %
                                                                                         
Income (Loss) Per
Common Share:
                                                                                         
Basic-Income
(loss) from         $ 0.33        $ (0.02   )            $ 0.08          $ 0.26
continuing
operations
  Discontinued       -           -                    -             0.10      
  operations
  Net income        $ 0.33       $ (0.02   )   1750 %   $ 0.08         $ 0.36         -78 %
  (loss)
                                                                                         
Diluted-Income
(loss) from         $ 0.32        $ (0.02   )            $ 0.08          $ 0.26
continuing
operations
  Discontinued       -           -                    -             0.10      
  operations
  Net income        $ 0.32       $ (0.02   )   1700 %   $ 0.08         $ 0.36         -78 %
  (loss)
                                                                                         
Weighted average
common shares
outstanding, as
reported:
  Basic               159,832       158,413     1    %     159,431         158,030       1   %
  Diluted             160,559       158,413     1    %     160,307         159,441       1   %
                                                                                             

(a) See separate natural gas, NGLs and oil sales information table.

(b) Included in Derivative fair value (loss) income in the 10-K.

(c) Included in Brokered natural gas, marketing and other revenues in the
10-K.

(d) Costs associated with stock compensation and restricted stock
amortization, which have been reflected in the categories associated with the
direct personnel costs, which are combined with the cash costs in the 10-K.

(e) Reflects the change in market value of the vested Company stock held in
the deferred compensation plan.

                                                                                      
RANGE RESOURCES CORPORATION
                                                                                             
STATEMENTS OF
OPERATIONS
Restated for
Barnett
discontinued
operations,
  a non-GAAP        Three Months Ended December 31, 2012       Three Months Ended December 31, 2011
   presentation
   (Unaudited, in                  Barnett        Including                   Barnett        Including
   thousands,        As            Discontinued   Barnett       As            Discontinued   Barnett
   except per        reported     Operations    Ops           reported     Operations    Ops
   share data)
Revenues and other
income:
   Natural gas,
   NGLs and oil      $ 398,688     -              $ 398,688     $ 331,720     $   188        $ 331,908
   sales
   Derivative cash
   settlements         16,706      -                16,706        13,800          -            13,800
   gain (loss)
   Change in
   mark-to-market
   on unrealized       (24,117 )   -                (24,117 )     (51,331 )       -            (51,331 )
   derivatives

   gain (loss)
   Ineffective
   hedging gain        1,840       -                1,840         (348    )       -            (348    )
   (loss)
   Gain (loss) on
   sale of             61,836      -                61,836        3,539           -            3,539
   properties
   Brokered
   natural gas and     2,948       -                2,948         3,770           -            3,770
   marketing
   Equity method       (177    )   -                (177    )     356             (81   )      275
   investment
   Interest and       314       -              314         1,712        -         1,712   
   other
                      458,038   -              458,038     303,218      107       303,325 
Costs and
expenses:
   Direct              29,446      -                29,446        25,347          245          25,592
   operating
   Direct
   operating –
   non-cash            768         -                768           571             -            571
   stock-based
   compensation
   Transportation,
   gathering and       55,281      -                55,281        34,576          17           34,593
   compression
   Production and
   ad valorem          9,380       -                9,380         5,920           103          6,023
   taxes
   Pennsylvania
   impact fee –        501         -                501           -               -            -
   prior year
   Brokered
   natural gas and     4,542       -                4,542         2,803           -            2,803
   marketing
   Brokered
   natural gas and
   marketing           452         -                452           348             -            348
   non-cash
   stock-based
   comp
   Exploration         17,021      -                17,021        24,042          -            24,042
   Exploration –
   non-cash            1,001       -                1,001         940             -            940
   stock-based
   compensation
   Abandonment and
   impairment of       21,230      -                21,230        27,639          -            27,639
   unproved
   properties
   General and         31,402      -                31,402        32,647          -            32,647
   administrative
   General and
   administrative
   – non-cash          13,786      -                13,786        8,756           -            8,756
   stock-based

   compensation
   General and
   administrative      644         -                644           302             -            302
   – lawsuit
   settlements
   General and
   administrative      750         -                750           500             -            500
   – bad debt
   expense
   Deferred
   compensation        (14,352 )   -                (14,352 )     9,640           -            9,640
   plan
   Interest            44,708      -                44,708        34,709          -            34,709
   expense
   Loss on early
   extinguishment      11,063      -                11,063        -               -            -
   of debt
   Depletion,
   depreciation        113,216     -                113,216       97,092          -            97,092
   and
   amortization
   Impairment of
   proved             34,273    -              34,273      -            -         -       
   properties and
   other assets
                      375,112   -              375,112     305,832      365       306,197 
                                                                                             
Income (loss) from
continuing             82,926      -                82,926        (2,614  )       (258  )      (2,872  )
operations before
income taxes
                                                                                             
Income tax expense
(benefit):
   Current             (1,778  )   -                (1,778  )     636             -            636
   Deferred           31,742    -              31,742      (425    )     (94   )    (519    )
                      29,964    -              29,964      211          (94   )    117     
                                                                                             
Income (loss) from
continuing             52,962      -                52,962        (2,825  )       (164  )      (2,989  )
operations
Discontinued
operations-Barnett    -         -              -           (164    )     164       -       
Shale, net of tax
Net income (loss)    $ 52,962    -             $ 52,962     $ (2,989  )     -        $ (2,989  )
                                                                                             
OPERATING
HIGHLIGHTS
                                                                                             
Average daily
production:
   Natural gas         655,224     -                655,224       490,731         289          491,020
   (mcf)
   NGLs (bbl)          21,652      -                21,652        16,886          45           16,931
   Oil (bbl)           9,863       -                9,863         5,407           2            5,409
   Gas equivalents     844,314     -                844,314       624,491         568          625,059
   (mcfe)
                                                                                             
Average prices
realized before
transportation,
gathering and
compression:
   Natural gas       $ 4.21        -              $ 4.21        $ 4.81            -          $ 4.81
   (mcf)
   NGLs (bbl)        $ 43.56       -              $ 43.56       $ 55.69           -          $ 55.68
   Oil (bbl)         $ 82.30       -              $ 82.30       $ 83.71           -          $ 83.71
   Gas equivalents   $ 5.35        -              $ 5.35        $ 6.01            -          $ 6.01
   (mcfe)
                                                                                             
Direct operating
cash costs per
mcfe:
   Field expenses    $ 0.36        -              $ 0.36        $ 0.42            -          $ 0.43
   Workovers          0.02      -              0.02        0.02         -         0.02    
   Total operating   $ 0.38      -             $ 0.38       $ 0.44         -        $ 0.45    
   costs
                                                                                             
Transportation,
gathering and        $ 0.71      -             $ 0.71       $ 0.60      $   0.33     $ 0.60    
compression cost
per mcf:

                                                                                            
RANGE RESOURCES CORPORATION
                                                                                                   
STATEMENTS OF
OPERATIONS
Restated for
Barnett
discontinued
operations,
  a non-GAAP        Twelve Months Ended December 31, 2012          Twelve Months Ended December 31, 2011
   presentation
   (Unaudited, in                    Barnett        Including                       Barnett        Including
   thousands,        As              Discontinued   Barnett         As              Discontinued   Barnett
   except per        reported       Operations    Ops             reported       Operations    Ops
   share data)
Revenues and other
income:
   Natural gas,
   NGLs and oil      $ 1,351,694     -              $ 1,351,694     $ 1,173,266     $  59,185      $ 1,232,451
   sales
   Derivative cash
   settlements         38,700        -                38,700          22,142           -             22,142
   gain (loss)
   Change in
   mark-to-market
   on unrealized       5,958         -                5,958           15,762           -             15,762
   derivatives
   gain (loss)
   Ineffective
   hedging gain        (3,221    )   -                (3,221    )     2,183            -             2,183
   (loss)
   Gain (loss) on
   sale of             49,132        -                49,132          2,259            -             2,259
   properties
   Brokered
   natural gas and     15,078        -                15,078          12,693           6             12,699
   marketing
   Equity method       (372      )   -                (372      )     (1,043    )      4,771         3,728
   investment
   Interest and       735         -              735           3,380         4          3,384
   other
                      1,457,704   -              1,457,704     1,230,642     63,966     1,294,608
Costs and
expenses:
   Direct              113,490       -                113,490         110,985          10,035        121,020
   operating
   Direct
   operating –
   non-cash            2,415         -                2,415           1,987            45            2,032
   stock-based
   compensation
   Transportation,
   gathering and       192,445       -                192,445         120,755          5,257         126,012
   compression
   Production and
   ad valorem          41,912        -                41,912          27,666           1,309         28,975
   taxes
   Pennsylvania
   impact fee –        25,208        -                25,208          -                -             -
   prior year
   Brokered
   natural gas and     18,669        -                18,669          10,531           -             10,531
   marketing
   Brokered
   natural gas and
   marketing           1,765         -                1,765           1,455            -             1,455
   non-cash
   stock-based
   comp
   Exploration         65,758        -                65,758          77,259           37            77,296
   Exploration –
   non-cash            4,049         -                4,049           4,108            -             4,108
   stock-based
   compensation
   Abandonment and
   impairment of       125,278       -                125,278         79,703           -             79,703
   unproved
   properties
   General and         125,355       -                125,355         113,461          -             113,461
   administrative
   General and
   administrative
   – non-cash          44,541        -                44,541          36,244           -             36,244
   stock-based

   compensation
   General and
   administrative      3,167         -                3,167           540              -             540
   – lawsuit
   settlements
   General and
   administrative      750           -                750             946              -             946
   – bad debt
   expense
   Deferred
   compensation        7,203         -                7,203           43,209           -             43,209
   plan
   Interest            168,798       -                168,798         125,052          14,791        139,843
   expense
   Loss on early
   extinguishment      11,063        -                11,063          18,576           -             18,576
   of debt
   Depletion,
   depreciation        445,228       -                445,228         341,221          8,894         350,115
   and
   amortization
   Impairment of
   proved             35,554      -              35,554        38,681        -          38,681
   properties and
   other assets
                      1,432,648   -              1,432,648     1,152,379     40,368     1,192,747
                                                                                                   
Income (loss) from
continuing             25,056        -                25,056          78,263           23,598        101,861
operations before
income taxes
                                                                                                   
Income tax expense
(benefit):
   Current             (1,778    )   -                (1,778    )     637              -             637
   Deferred           13,832      -              13,832        34,920        8,278      43,198
                      12,054      -              12,054        35,557        8,278      43,835
                                                                                                   
Income (loss) from
continuing             13,002        -                13,002          42,706           15,320        58,026
operations
Discontinued
operations-Barnett    -           -              -             15,320        (15,320 )   -
Shale, net of tax
Net income (loss)    $ 13,002      -             $ 13,002       $ 58,026        -         $ 58,026
                                                                                                   
OPERATING
HIGHLIGHTS
                                                                                                   
Average daily
production:
   Natural gas         591,679       -                591,679         397,825          32,316        430,141
   (mcf)
   NGLs (bbl)          19,036        -                19,036          14,664           605           15,269
   Oil (bbl)           7,790         -                7,790           5,369            23            5,392
   Gas equivalents     752,637       -                752,637         518,019          36,079        554,098
   (mcfe)
                                                                                                   
Average prices
realized before
transportation,
gathering and
compression:
   Natural gas       $ 3.95          -              $ 3.95          $ 5.22             -           $ 5.13
   (mcf)
   NGLs (bbl)        $ 42.60         -              $ 42.60         $ 52.03            -           $ 51.79
   Oil (bbl)         $ 83.64         -              $ 83.64         $ 81.34            -           $ 81.38
   Gas equivalents   $ 5.05          -              $ 5.05          $ 6.32             -           $ 6.20
   (mcfe)
                                                                                                   
Direct operating
cash costs per
mcfe:
   Field expenses    $ 0.39          -              $ 0.39          $ 0.57          $  0.74        $ 0.58
   Workovers          0.02        -              0.02          0.02          0.02       0.02
   Total operating   $ 0.41        -             $ 0.41         $ 0.59        $  0.76      $ 0.60
   costs
                                                                                                   
Transportation,
gathering and        $ 0.70        -             $ 0.70         $ 0.85        $  0.53      $ 0.83
compression cost
per mcf:

                                               
RANGE RESOURCES CORPORATION
                                                 
BALANCE SHEETS
(Audited, in thousands)                          December 31,   December 31,
                                                  2012          2011      
Assets
Current assets                                   $ 190,062       $ 141,342
Current unrealized derivative gain                 137,552         173,921
Natural gas and oil properties                     6,096,184       5,157,566
Transportation and field assets                    41,567          52,678
Other                                             263,370       319,963   
                                                 $ 6,728,735    $ 5,845,470 
                                                                 
Liabilities and Stockholders’ Equity
Current liabilities                              $ 448,202       $ 506,274
Current asset retirement obligation                2,470           5,005
Current unrealized derivative loss                 4,471           -
Current liabilities of discontinued operations     -               653
                                                                 
Bank debt                                          739,000         187,000
Subordinated notes                                2,139,185     1,787,967 
Total long-term debt                              2,878,185     1,974,967 
                                                                 
Deferred tax liability                             698,302         710,490
Unrealized derivative loss                         3,463           173
Deferred compensation liability                    187,604         169,188
Long-term asset retirement obligation and          148,646         86,300
other
                                                                 
Common stock and retained earnings                 2,278,243       2,242,136
Treasury stock                                     (4,760    )     (6,343    )
Accumulated other comprehensive income            83,909        156,627   
Total stockholders’ equity                        2,357,392     2,392,420 
                                                 $ 6,728,735    $ 5,845,470 

                                                               
RANGE RESOURCES CORPORATION
                                                                   
CASH FLOWS FROM
OPERATING ACTIVITIES
(Unaudited, in           Three Months Ended          Twelve Months Ended
thousands)
                         December 31,                December 31,
                          2012       2011        2012        2011    
                                                                   
Net income (loss)        $ 52,962      $ (2,989  )   $ 13,002      $ 58,026
Adjustments to
reconcile net income
to net cash provided
from operating
activities:
(Income) loss
discontinued               -             164           -             (15,320 )
operations
(Gain) loss from
equity investment, net     3,418         (1,906  )     5,670         16,871
of distributions
Deferred income tax        31,742        (425    )     13,832        34,920
expense (benefit)
Depletion,
depreciation,
amortization and           147,489       97,092        480,782       379,902
proved property
impairment
Exploration dry hole       9             1,372         841           3,888
costs
Abandonment and
impairment of unproved     21,230        27,639        125,278       79,703
properties
Mark-to-market loss
(gain) on oil and gas      24,118        51,331        (5,958  )     (15,762 )
derivatives not
designated as hedges
Unrealized derivatives     (1,840  )     348           3,221         (2,183  )
(gain) loss
Allowance for bad          750           500           750           946
debts
Amortization of
deferred financing
costs, loss on             17,195        1,705         23,165        25,458
extinguishment of
debt, and other
Deferred and
stock-based                1,563         20,220        60,136        86,979
compensation
Gain (loss) on sale of     (61,836 )     (3,539  )     (49,132 )     (2,259  )
assets and other
                                                                   
Changes in working
capital:
Accounts receivable        (39,507 )     (17,756 )     (48,986 )     (52,112 )
Inventory and other        (1,982  )     (10     )     (7,376  )     865
Accounts payable           2,580         8,000         13,654        738
Accrued liabilities       (11,915 )    (413    )    18,220      9,540   
and other
Net changes in working    (50,824 )    (10,179 )    (24,488 )    (40,969 )
capital
Net cash provided from     185,976       181,333       647,099       610,200
continuing operations
Net cash provided from
discontinued              -           1,959       -           21,437  
operations
Net cash provided from   $ 185,976    $ 183,292    $ 647,099    $ 631,637 
operating activities

                                                  
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           Three Months Ended          Twelve Months Ended
thousands)
                         December 31,                December 31,
                          2012       2011        2012       2011    
                                                                   
Net cash provided from
operating activities,    $ 185,976     $ 183,292     $ 647,099     $ 631,637
as reported
Net changes in working
capital from               50,824        10,179        24,488        40,969
continuing operations
Exploration expense        12,873        22,670        60,778        73,371
Lawsuit settlements        644           302           3,167         540
Equity method
investment
distribution /             (3,241  )     1,550         (5,298  )     (15,828 )
intercompany
elimination
Prior year
Pennsylvania impact        501           -             25,208        -
fee
Non-cash compensation      292           85            295           270
adjustment
Net changes in working
capital from              -           (2,136  )    -           6,366   
discontinued
operations and other
Cash flow from
operations before
changes in working       $ 247,869    $ 215,942    $ 755,737    $ 737,325 
capital, a non-GAAP
measure
                                                                   
ADJUSTED WEIGHTED
AVERAGE SHARES
OUTSTANDING
(Unaudited, in           Three Months Ended          Twelve Months Ended
thousands)
                         December 31,                December 31,
                          2012        2011        2012        2011    
Basic:
Weighted average           162,627       161,253       162,306       160,906
shares outstanding
Stock held by deferred    (2,795  )    (2,840  )    (2,875  )    (2,876  )
compensation plan
Adjusted basic            159,832     158,413     159,431     158,030 
                                                                   
Dilutive:
Weighted average           162,627       161,253       162,306       160,906
shares outstanding
Anti-dilutive or
dilutive stock options    (2,068  )    (2,840  )    (1,999  )    (1,465  )
under treasury method
Adjusted dilutive         160,559     158,413     160,307     159,441 

                                                         
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
                  As Reported, GAAP                         Non-GAAP

                  Excludes Barnett Operations               Includes Barnett Operations
(Unaudited, in
thousands,        Three Months Ended December 31,           Three Months Ended December 31,
except per unit
data)
                   2012          2011         %       2012          2011         %   
Natural gas,
NGLs and oil
sales
components:
Natural gas       $ 213,348        $ 165,300                $ 213,348        $ 165,256
sales
NGLs sales          75,468           79,995                   75,468           80,215
Oil sales           71,245           43,489                   71,245           43,501
                                                                                              
Cash-settled
hedges
(effective):
Natural gas         39,584           42,936                   39,584           42,936
Crude oil          (957       )    -                      (957       )    -          
Total natural
gas, NGLs and     $ 398,688       $ 331,720       20  %   $ 398,688       $ 331,908       20  %
oil sales, as
reported
                                                                                              
Derivative fair
value income
(loss)
components:
Cash-settled
derivatives
(ineffective):
Natural gas       $ 1,026          $ 9,122                  $ 1,026          $ 9,122
NGLs                11,295           6,524                    11,295           6,524
Crude Oil           4,385            (1,847     )             4,385            (1,847     )
Change in
mark-to-market      (24,117    )     (51,331    )             (24,117    )     (51,331    )
on unrealized
derivatives
Unrealized         1,840          (348       )            1,840          (348       )
ineffectiveness
Total
derivative fair
value income      $ (5,571     )   $ (37,880    )           $ (5,571     )   $ (37,880    )
(loss), as
reported
                                                                                              
Natural gas,
NGLs and oil
sales,
including all
cash-settled
derivatives
(c):
Natural gas       $ 253,958        $ 217,358                $ 253,958        $ 217,314
sales
NGL sales           86,763           86,519                   86,763           86,739
Oil sales          74,673         41,642                 74,673         41,654     
Total             $ 415,394       $ 345,519       20  %   $ 415,394       $ 345,707       20  %
                                                                                              
Third party
transportation,
gathering and
compression fee
components:
Natural gas       $ 52,113         $ 32,441                 $ 52,113         $ 32,458
NGLs               3,168          2,135                  3,168          2,135      
Total
transportation,
gathering and     $ 55,281        $ 34,576                $ 55,281        $ 34,593     
compression, as
reported
                                                                                              
Production
during the
period (a):
Natural gas         60,280,617       45,147,273     34  %     60,280,617       45,173,850     33  %
(mcf)
NGLs (bbl)          1,992,028        1,553,546      28  %     1,992,028        1,557,673      28  %
Oil (bbl)           907,351          497,440        82  %     907,351          497,585        82  %
Gas equivalent      77,676,891       57,453,189     35  %     77,676,891       57,505,398     35  %
(mcfe) (b)
                                                                                              
Production –
average per day
(a):
Natural gas         655,224          490,731        34  %     655,224          491,020        33  %
(mcf)
NGLs (bbl)          21,652           16,886         28  %     21,652           16,931         28  %
Oil (bbl)           9,863            5,407          82  %     9,863            5,409          82  %
Gas equivalent      844,314          624,491        35  %     844,314          625,059        35  %
(mcfe) (b)
                                                                                              
Average prices,
including
cash-settled
hedges and
derivatives
before third
party
transportation
costs (c):
Natural gas       $ 4.21           $ 4.81           -12 %   $ 4.21           $ 4.81           -12 %
(mcf)
NGLs (bbl)        $ 43.56          $ 55.69          -22 %   $ 43.56          $ 55.68          -22 %
Oil (bbl)         $ 82.30          $ 83.71          -2  %   $ 82.30          $ 83.71          -2  %
Gas equivalent    $ 5.35           $ 6.01           -11 %   $ 5.35           $ 6.01           -11 %
(mcfe) (b)
                                                                                              
Average prices,
including
cash-settled
hedges and
derivatives
(d):
Natural gas       $ 3.35           $ 4.10           -18 %   $ 3.35           $ 4.09           -18 %
(mcf)
NGLs (bbl)        $ 41.96          $ 54.32          -23 %   $ 41.96          $ 54.31          -23 %
Oil (bbl)         $ 82.30          $ 83.71          -2  %   $ 82.30          $ 83.71          -2  %
Gas equivalent    $ 4.64           $ 5.41           -14 %   $ 4.64           $ 5.41           -14 %
(mcfe) (b)
                                                                                              

(a) Represents volumes sold regardless of when produced.

(b) Oil and NGLs are converted to mcfe at a rate of one barrel equals six mcf
based upon the approximate relative energy content of oil and 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 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
                                                             Non-GAAP
(Unaudited, in    As Reported, GAAP
thousands,                                                    Includes Barnett Operations
except per unit   Excludes Barnett Operations
data)                                                         Twelve Months Ended December 31,
                  Twelve Months Ended December 31,
                   2012           2011          %      2012           2011          %   
Natural gas,
NGLs and oil
sales
components:
Natural gas       $ 612,354         $ 611,864                 $612,354        $ 651,533
sales
NGLs sales          265,072           268,846                 265,072           278,995
Oil sales           237,963           168,961                 237,963           169,722
                                                                                                
Cash-settled
hedges
(effective):
Natural gas         238,259           123,595                 238,259           132,201
Crude oil          (1,954      )    -                      (1,954      )    -           
Total natural
gas, NGLs and     $ 1,351,694      $ 1,173,266      15  %   $1,351,694     $ 1,232,451      10  %
oil sales, as
reported
                                                                                                
Derivative fair
value income
(loss)
components:
Cash-settled
derivatives
(ineffective):
Natural gas       $ 4,477           $ 22,104                  $4,477          $ 22,104
NGLs                31,737            9,612                   31,737            9,612
Crude Oil           2,486             (9,574      )           2,486             (9,574      )
Change in
mark-to-market      5,958             15,762                  5,958             15,762
on unrealized
derivatives
Unrealized         (3,221      )    2,183                  (3,221      )    2,183       
ineffectiveness
Total
derivative fair
value income      $ 41,437         $ 40,087                 $41,437        $ 40,087      
(loss), as
reported
                                                                                                
Natural gas,
NGLs and oil
sales,
including all
cash-settled
derivatives
(c):
Natural gas       $ 855,090         $ 757,563                 $855,090        $ 805,838
sales
NGLs sales          296,809           278,458                 296,809           288,607
Oil sales          238,495         159,387                238,495         160,148     
Total             $ 1,390,394      $ 1,195,408      16  %   $1,390,394     $ 1,254,593      11  %
                                                                                                
Third party
transportation,
gathering and
compression fee
components:
Natural gas       $ 181,524         $ 114,289                 $181,524        $ 119,546
NGLs               10,921          6,466                  10,921          6,466       
Total
transportation,
gathering and     $ 192,445        $ 120,755                $192,445       $ 126,012     
compression, as
reported
                                                                                                
Production
during the
period (a):
Natural gas         216,554,689       145,206,124     49  %   216,554,689       157,001,395     38  %
(mcf)
NGLs (bbl)          6,967,114         5,352,181       30  %   6,967,114         5,572,829       25  %
Oil (bbl)           2,851,312         1,959,608       46  %   2,851,312         1,967,881       45  %
Gas equivalent      275,465,245       189,076,858     46  %   275,465,245       202,245,656     36 %
(mcfe) (b)
                                                                                                
Production –
average per day
(a):
Natural gas         591,679           397,825         49  %   591,679           430,141         38  %
(mcf)
NGLs (bbl)          19,036            14,664          30  %   19,036            15,268          25  %
Oil (bbl)           7,790             5,369           45  %   7,790             5,391           44  %
Gas equivalent      752,637           518,019         45  %   752,637           554,098         36  %
(mcfe) (b)
                                                                                                
Average prices,
including
cash-settled
hedges and
derivatives
before third
party
transportation
costs (c):
Natural gas       $ 3.95            $ 5.22            -24 %   $3.95           $ 5.13            -23 %
(mcf)
NGLs (bbl)        $ 42.60           $ 52.03           -18 %   $42.60          $ 51.79           -18 %
Oil (bbl)         $ 83.64           $ 81.34           3   %   $83.64          $ 81.38           3   %
Gas equivalent    $ 5.05            $ 6.32            -20 %   $5.05           $ 6.20            -19 %
(mcfe) (b)
                                                                                                
Average prices,
including
cash-settled
hedges and
derivatives
(d):
Natural gas       $ 3.11            $ 4.43            -30 %   $3.11           $ 4.37            -29 %
(mcf)
NGLs (bbl)        $ 41.03           $ 50.82           -19 %   $41.03          $ 50.63           -19 %
Oil (bbl)         $ 83.64           $ 81.34           3   %   $83.64          $ 81.38           3   %
Gas equivalent    $ 4.35            $ 5.68            -23 %   $4.35           $ 5.58            -22 %
(mcfe) (b)
                                                                                                

(a) Represents volumes sold regardless of when produced.

(b) Oil and NGLs are converted to mcfe at a rate of one barrel equals six mcf
based upon the approximate relative energy content of oil and 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,       Three Months Ended December 31,    Twelve Months Ended December 31,
except per
share data)
                 2012       2011      %        2012        2011       %   
                                                                                
(Loss) income
from
continuing
operations       $82,926     $ (2,614  )   3272 %   $ 25,056      $ 78,263      -68 %
before income
taxes, as
reported
Adjustment for
certain items:
Gain (loss) on
sale of          (61,836 )     (3,539  )              (49,132 )     (2,259  )
properties
Barnett
discontinued
operations       -             (177    )              -             18,827
less gain on
sale
Change in
mark-to-market
on unrealized    24,117        51,331                 (5,958  )     (15,762 )
derivatives
(gain) loss
Unrealized
derivative       (1,840  )     348                    3,221         (2,183  )
(gain) loss
Abandonment
and impairment   21,230        27,639                 125,278       79,703
of unproved
properties
Loss on early
extinguishment   11,063        -                      11,063        18,576
of debt
Prior year
Pennsylvania     501           -                      25,208        -
impact fee
Proved
property and     34,273        -                      35,554        38,681
other asset
impairment
Lawsuit          644           302                    3,167         540
settlements
Brokered
natural gas
and marketing
– non cash       452           348                    1,765         1,455
stock-based

compensation
Direct
operating –
non-cash         768           571                    2,415         1,987
stock-based
compensation
Exploration
expenses –
non-cash         1,001         940                    4,049         4,108
stock-based
compensation
General &
administrative
– non-cash       13,786        8,756                  44,541        36,244
stock-based
compensation
Deferred
compensation
plan –           (14,352 )    9,640                7,203       43,209  
non-cash
adjustment
                                                                                
Income from
operations
before income    112,733       93,545      21   %     233,430       301,389     -23 %
taxes, as
adjusted
                                                                                
Income tax
expense, as
adjusted
Current          (1,778  )     636                    (1,778  )     637
Deferred         41,152      39,647               87,351      124,372 
Net income
excluding
certain items,   $73,359    $ 53,262     38   %   $ 147,857    $ 176,380    -16 %
a non-GAAP
measure
                                                                                
Non-GAAP
income per
common share
Basic.           $0.46      $ 0.34       35   %   $ 0.93       $ 1.12       -17 %
Diluted          $0.46      $ 0.33       39   %   $ 0.92       $ 1.11       -17 %
                                                                                
Non-GAAP
diluted shares   160,559     160,051              160,307     159,441 
outstanding,
if dilutive

                                            
HEDGING POSITION AS OF FEBRUARY 26, 2013
(Unaudited)
                                                  
                                   Daily Volume   Hedge Price
      Gas (Mmbtu)
      1Q 2013 Swaps                205,000        $3.24
      1Q 2013 Collars              280,000        $4.59 - $5.05
      2Q 2013 Swaps                215,000        $3.28
      2Q 2013 Collars              280,000        $4.59 - $5.05
      3Q 2013 Swaps                220,000        $3.42
      3Q 2013 Collars              280,000        $4.59 - $5.05
      4Q 2013 Swaps                213,370        $3.62
      4Q 2013 Collars              280,000        $4.59 - $5.05
      2014 Collars                 402,500        $3.81 - $4.47
      2015 Collars                 55,000         $4.03 - $4.50
                                                  
      Oil (Bbls)
      1Q 2013 Swaps                4,653          $96.52
      1Q 2013 Collars              3,000          $90.60 - $100.00
      2Q 2013 Swaps                4,825          $96.64
      2Q 2013 Collars              3,000          $90.60 - $100.00
      3Q 2013 Swaps                5,825          $96.74
      3Q 2013 Collars              3,000          $90.60 - $100.00
      4Q 2013 Swaps                6,825          $96.79
      4Q 2013 Collars              3,000          $90.60 - $100.00
      2014 Swaps                   6,000          $94.54
      2014 Collars                 2,000          $85.55 - $100.00
      2015 Swaps                   2,000          $90.20
                                                  
      C5 Natural Gasoline (Bbls)
      1Q 2013 Swaps                6,500          $2.13
      2Q 2013 Swaps                6,500          $2.13
      3Q 2013 Swaps                6,500          $2.13
      4Q 2013 Swaps                6,500          $2.13
                                                  
      C3 Propane (Bbls)
      1Q 2013 Swaps                5,344          $0.94
      2Q 2013 Swaps                6,000          $0.93
      3Q 2013 Swaps                6,000          $0.93
      4Q 2013 Swaps                6,000          $0.93

     NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

Contact:

Range Resources Corporation
Investor Contacts:
Rodney Waller, 817-869-4258
Senior Vice President
or
David Amend, 817-869-4266
Investor Relations Manager
or
Laith Sando, 817-869-4267
Senior Financial Analyst
or
Michael Freeman, 817-869-4264
Financial Analyst
or
Media Contact:
Matt Pitzarella, 724-873-3224
Director of Corporate Communications
www.rangeresources.com

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