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 drilling rig 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 (a):
|
|
$0.75 - $0.77 per mcfe
|
|
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 WTI NYMEX)
|
|
|
54
|
%
|
|
|
54
|
%
|
|
48
|
%
|
|
39
|
%
|
|
33
|
%
|
|
|
43
|
%
|
|
Oil (% of WTI NYMEX)
|
|
|
91
|
%
|
|
|
92
|
%
|
|
88
|
%
|
|
91
|
%
|
|
90
|
%
|
|
|
89
|
%
|
(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 flows
|
|
$
|
3,224
|
|
Discounted future cash flows for income taxes
|
|
|
736
|
|
Discounted future net cash flows before income taxes (PV-10)
|
|
$
|
3,960
|
|
|
|
|
|
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 per share data)
|
|
Three Months Ended December 31,
|
|
Twelve Months Ended December 31,
|
|
|
|
|
|
2012
|
|
|
|
2011
|
|
|
%
|
|
|
|
2012
|
|
|
|
2011
|
|
|
%
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGLs and oil sales (a)
|
|
$
|
398,688
|
|
|
$
|
331,720
|
|
|
|
|
$
|
1,351,694
|
|
|
$
|
1,173,266
|
|
|
|
|
|
Derivative cash settlements gain (loss) (a) (b)
|
|
|
16,706
|
|
|
|
13,800
|
|
|
|
|
|
38,700
|
|
|
|
22,142
|
|
|
|
|
|
Change in mark-to-market on unrealized derivatives
|
|
|
(24,117
|
)
|
|
|
(51,331
|
)
|
|
|
|
|
|
|
|
|
|
gain (loss) (b)
|
|
|
|
|
5,958
|
|
|
|
15,762
|
|
|
|
|
|
Ineffective hedging (loss) gain (b)
|
|
|
1,840
|
|
|
|
(348
|
)
|
|
|
|
|
(3,221
|
)
|
|
|
2,183
|
|
|
|
|
|
Gain (loss) on sale of properties
|
|
|
61,836
|
|
|
|
3,539
|
|
|
|
|
|
49,132
|
|
|
|
2,259
|
|
|
|
|
|
Brokered natural gas and marketing (c)
|
|
|
2,948
|
|
|
|
3,770
|
|
|
|
|
|
15,078
|
|
|
|
12,693
|
|
|
|
|
|
Equity method investment (c)
|
|
|
(177
|
)
|
|
|
356
|
|
|
|
|
|
(372
|
)
|
|
|
(1,043
|
)
|
|
|
|
|
Other (c)
|
|
|
314
|
|
|
|
1,712
|
|
|
|
|
|
735
|
|
|
|
3,380
|
|
|
|
|
|
Total revenues and other income
|
|
|
458,038
|
|
|
|
303,218
|
|
|
51
|
%
|
|
|
1,457,704
|
|
|
|
1,230,642
|
|
|
18
|
%
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating
|
|
|
29,446
|
|
|
|
25,347
|
|
|
|
|
|
113,490
|
|
|
|
110,985
|
|
|
|
|
|
Direct operating – non-cash stock compensation (d)
|
|
|
768
|
|
|
|
571
|
|
|
|
|
|
2,415
|
|
|
|
1,987
|
|
|
|
|
|
Transportation, gathering and compression
|
|
|
55,281
|
|
|
|
34,576
|
|
|
|
|
|
192,445
|
|
|
|
120,755
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
9,380
|
|
|
|
5,920
|
|
|
|
|
|
41,912
|
|
|
|
26,666
|
|
|
|
|
|
Pennsylvania impact fee - prior year
|
|
|
501
|
|
|
|
-
|
|
|
|
|
|
25,208
|
|
|
|
-
|
|
|
|
|
|
Brokered natural gas and marketing
|
|
|
4,542
|
|
|
|
2,803
|
|
|
|
|
|
18,669
|
|
|
|
10,531
|
|
|
|
|
|
Brokered natural gas and marketing – non-cash stock-
|
|
|
452
|
|
|
|
348
|
|
|
|
|
|
1,765
|
|
|
|
1,455
|
|
|
|
|
|
based compensation (d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
|
|
|
17,021
|
|
|
|
24,042
|
|
|
|
|
|
65,758
|
|
|
|
77,259
|
|
|
|
|
|
Exploration – non-cash stock compensation (d)
|
|
|
1,001
|
|
|
|
940
|
|
|
|
|
|
4,049
|
|
|
|
4,108
|
|
|
|
|
|
Abandonment and impairment of unproved properties
|
|
|
21,230
|
|
|
|
27,639
|
|
|
|
|
|
125,278
|
|
|
|
79,703
|
|
|
|
|
|
General and administrative
|
|
|
31,402
|
|
|
|
32,647
|
|
|
|
|
|
125,355
|
|
|
|
113,461
|
|
|
|
|
|
General and administrative – non-cash stock
|
|
|
13,786
|
|
|
|
8,756
|
|
|
|
|
|
|
|
|
|
|
compensation (d)
|
|
|
|
|
44,541
|
|
|
|
36,244
|
|
|
|
|
|
General and administrative – lawsuit settlements
|
|
|
644
|
|
|
|
302
|
|
|
|
|
|
3,167
|
|
|
|
540
|
|
|
|
|
|
General and administrative – bad debt expense
|
|
|
750
|
|
|
|
500
|
|
|
|
|
|
750
|
|
|
|
946
|
|
|
|
|
|
Deferred compensation plan (e)
|
|
|
(14,352
|
)
|
|
|
9,640
|
|
|
|
|
|
7,203
|
|
|
|
43,209
|
|
|
|
|
|
Interest expense
|
|
|
44,708
|
|
|
|
34,709
|
|
|
|
|
|
168,798
|
|
|
|
125,052
|
|
|
|
|
|
Loss on early extinguishment of debt
|
|
|
11,063
|
|
|
|
-
|
|
|
|
|
|
11,063
|
|
|
|
18,576
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
113,216
|
|
|
|
97,092
|
|
|
|
|
|
445,228
|
|
|
|
341,221
|
|
|
|
|
|
Impairment of proved properties and other assets
|
|
|
34,273
|
|
|
|
-
|
|
|
|
|
|
35,554
|
|
|
|
38,681
|
|
|
|
|
|
Total costs and expenses
|
|
|
375,112
|
|
|
|
305,832
|
|
|
23
|
%
|
|
|
1,432,648
|
|
|
|
1,152,379
|
|
|
24
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
82,926
|
|
|
|
(2,614
|
)
|
|
3272
|
%
|
|
|
25,056
|
|
|
|
78,263
|
|
|
-68
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 operations
|
|
|
52,962
|
|
|
|
(2,825
|
)
|
|
1975
|
%
|
|
|
13,002
|
|
|
|
42,706
|
|
|
-70
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations, net of tax
|
|
|
-
|
|
|
|
(164
|
)
|
|
|
|
|
-
|
|
|
|
15,320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
52,962
|
|
|
$
|
(2,989
|
)
|
|
1872
|
%
|
|
$
|
13,002
|
|
|
$
|
58,026
|
|
|
-78
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Per Common Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic-Income (loss) from continuing operations
|
|
$
|
0.33
|
|
|
$
|
(0.02
|
)
|
|
|
|
$
|
0.08
|
|
|
$
|
0.26
|
|
|
|
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
-
|
|
|
|
0.10
|
|
|
|
|
|
Net income (loss)
|
|
$
|
0.33
|
|
|
$
|
(0.02
|
)
|
|
1750
|
%
|
|
$
|
0.08
|
|
|
$
|
0.36
|
|
|
-78
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted-Income (loss) from continuing operations
|
|
$
|
0.32
|
|
|
$
|
(0.02
|
)
|
|
|
|
$
|
0.08
|
|
|
$
|
0.26
|
|
|
|
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
-
|
|
|
|
0.10
|
|
|
|
|
|
Net income (loss)
|
|
$
|
0.32
|
|
|
$
|
(0.02
|
)
|
|
1700
|
%
|
|
$
|
0.08
|
|
|
$
|
0.36
|
|
|
-78
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 presentation
|
|
Three Months Ended December 31, 2012
|
|
Three Months Ended December 31, 2011
|
|
|
(Unaudited, in thousands, except per share data)
|
|
As
reported
|
|
Barnett
Discontinued
Operations
|
|
Including
Barnett
Ops
|
|
As
reported
|
|
Barnett
Discontinued
Operations
|
|
Including
Barnett
Ops
|
|
|
|
|
|
|
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGLs and oil sales
|
|
$
|
398,688
|
|
|
-
|
|
$
|
398,688
|
|
|
$
|
331,720
|
|
|
$
|
188
|
|
|
$
|
331,908
|
|
|
|
Derivative cash settlements gain (loss)
|
|
|
16,706
|
|
|
-
|
|
|
16,706
|
|
|
|
13,800
|
|
|
|
-
|
|
|
|
13,800
|
|
|
|
Change in mark-to-market on unrealized derivatives
gain (loss)
|
|
|
(24,117
|
)
|
|
-
|
|
|
(24,117
|
)
|
|
|
(51,331
|
)
|
|
|
-
|
|
|
|
(51,331
|
)
|
|
|
Ineffective hedging gain (loss)
|
|
|
1,840
|
|
|
-
|
|
|
1,840
|
|
|
|
(348
|
)
|
|
|
-
|
|
|
|
(348
|
)
|
|
|
Gain (loss) on sale of properties
|
|
|
61,836
|
|
|
-
|
|
|
61,836
|
|
|
|
3,539
|
|
|
|
-
|
|
|
|
3,539
|
|
|
|
Brokered natural gas and marketing
|
|
|
2,948
|
|
|
-
|
|
|
2,948
|
|
|
|
3,770
|
|
|
|
-
|
|
|
|
3,770
|
|
|
|
Equity method investment
|
|
|
(177
|
)
|
|
-
|
|
|
(177
|
)
|
|
|
356
|
|
|
|
(81
|
)
|
|
|
275
|
|
|
|
Interest and other
|
|
|
314
|
|
|
-
|
|
|
314
|
|
|
|
1,712
|
|
|
|
-
|
|
|
|
1,712
|
|
|
|
|
|
|
458,038
|
|
|
-
|
|
|
458,038
|
|
|
|
303,218
|
|
|
|
107
|
|
|
|
303,325
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating
|
|
|
29,446
|
|
|
-
|
|
|
29,446
|
|
|
|
25,347
|
|
|
|
245
|
|
|
|
25,592
|
|
|
|
Direct operating – non-cash stock-based compensation
|
|
|
768
|
|
|
-
|
|
|
768
|
|
|
|
571
|
|
|
|
-
|
|
|
|
571
|
|
|
|
Transportation, gathering and compression
|
|
|
55,281
|
|
|
-
|
|
|
55,281
|
|
|
|
34,576
|
|
|
|
17
|
|
|
|
34,593
|
|
|
|
Production and ad valorem taxes
|
|
|
9,380
|
|
|
-
|
|
|
9,380
|
|
|
|
5,920
|
|
|
|
103
|
|
|
|
6,023
|
|
|
|
Pennsylvania impact fee – prior year
|
|
|
501
|
|
|
-
|
|
|
501
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
Brokered natural gas and marketing
|
|
|
4,542
|
|
|
-
|
|
|
4,542
|
|
|
|
2,803
|
|
|
|
-
|
|
|
|
2,803
|
|
|
|
Brokered natural gas and marketing non-cash stock-based comp
|
|
|
452
|
|
|
-
|
|
|
452
|
|
|
|
348
|
|
|
|
-
|
|
|
|
348
|
|
|
|
Exploration
|
|
|
17,021
|
|
|
-
|
|
|
17,021
|
|
|
|
24,042
|
|
|
|
-
|
|
|
|
24,042
|
|
|
|
Exploration – non-cash stock-based compensation
|
|
|
1,001
|
|
|
-
|
|
|
1,001
|
|
|
|
940
|
|
|
|
-
|
|
|
|
940
|
|
|
|
Abandonment and impairment of unproved properties
|
|
|
21,230
|
|
|
-
|
|
|
21,230
|
|
|
|
27,639
|
|
|
|
-
|
|
|
|
27,639
|
|
|
|
General and administrative
|
|
|
31,402
|
|
|
-
|
|
|
31,402
|
|
|
|
32,647
|
|
|
|
-
|
|
|
|
32,647
|
|
|
|
General and administrative – non-cash stock-based
compensation
|
|
|
13,786
|
|
|
-
|
|
|
13,786
|
|
|
|
8,756
|
|
|
|
-
|
|
|
|
8,756
|
|
|
|
General and administrative – lawsuit settlements
|
|
|
644
|
|
|
-
|
|
|
644
|
|
|
|
302
|
|
|
|
-
|
|
|
|
302
|
|
|
|
General and administrative – bad debt expense
|
|
|
750
|
|
|
-
|
|
|
750
|
|
|
|
500
|
|
|
|
-
|
|
|
|
500
|
|
|
|
Deferred compensation plan
|
|
|
(14,352
|
)
|
|
-
|
|
|
(14,352
|
)
|
|
|
9,640
|
|
|
|
-
|
|
|
|
9,640
|
|
|
|
Interest expense
|
|
|
44,708
|
|
|
-
|
|
|
44,708
|
|
|
|
34,709
|
|
|
|
-
|
|
|
|
34,709
|
|
|
|
Loss on early extinguishment of debt
|
|
|
11,063
|
|
|
-
|
|
|
11,063
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
Depletion, depreciation and amortization
|
|
|
113,216
|
|
|
-
|
|
|
113,216
|
|
|
|
97,092
|
|
|
|
-
|
|
|
|
97,092
|
|
|
|
Impairment of proved properties and other assets
|
|
|
34,273
|
|
|
-
|
|
|
34,273
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
375,112
|
|
|
-
|
|
|
375,112
|
|
|
|
305,832
|
|
|
|
365
|
|
|
|
306,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
82,926
|
|
|
-
|
|
|
82,926
|
|
|
|
(2,614
|
)
|
|
|
(258
|
)
|
|
|
(2,872
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 operations
|
|
|
52,962
|
|
|
-
|
|
|
52,962
|
|
|
|
(2,825
|
)
|
|
|
(164
|
)
|
|
|
(2,989
|
)
|
|
Discontinued operations-Barnett Shale, net of tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
(164
|
)
|
|
|
164
|
|
|
|
-
|
|
|
Net income (loss)
|
|
$
|
52,962
|
|
|
-
|
|
$
|
52,962
|
|
|
$
|
(2,989
|
)
|
|
|
-
|
|
|
$
|
(2,989
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING HIGHLIGHTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
|
655,224
|
|
|
-
|
|
|
655,224
|
|
|
|
490,731
|
|
|
|
289
|
|
|
|
491,020
|
|
|
|
NGLs (bbl)
|
|
|
21,652
|
|
|
-
|
|
|
21,652
|
|
|
|
16,886
|
|
|
|
45
|
|
|
|
16,931
|
|
|
|
Oil (bbl)
|
|
|
9,863
|
|
|
-
|
|
|
9,863
|
|
|
|
5,407
|
|
|
|
2
|
|
|
|
5,409
|
|
|
|
Gas equivalents (mcfe)
|
|
|
844,314
|
|
|
-
|
|
|
844,314
|
|
|
|
624,491
|
|
|
|
568
|
|
|
|
625,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices realized before transportation, gathering and
compression:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
$
|
4.21
|
|
|
-
|
|
$
|
4.21
|
|
|
$
|
4.81
|
|
|
|
-
|
|
|
$
|
4.81
|
|
|
|
NGLs (bbl)
|
|
$
|
43.56
|
|
|
-
|
|
$
|
43.56
|
|
|
$
|
55.69
|
|
|
|
-
|
|
|
$
|
55.68
|
|
|
|
Oil (bbl)
|
|
$
|
82.30
|
|
|
-
|
|
$
|
82.30
|
|
|
$
|
83.71
|
|
|
|
-
|
|
|
$
|
83.71
|
|
|
|
Gas equivalents (mcfe)
|
|
$
|
5.35
|
|
|
-
|
|
$
|
5.35
|
|
|
$
|
6.01
|
|
|
|
-
|
|
|
$
|
6.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 costs
|
|
$
|
0.38
|
|
|
-
|
|
$
|
0.38
|
|
|
$
|
0.44
|
|
|
|
-
|
|
|
$
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation, gathering and compression cost per mcf:
|
|
$
|
0.71
|
|
|
-
|
|
$
|
0.71
|
|
|
$
|
0.60
|
|
|
$
|
0.33
|
|
|
$
|
0.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RANGE RESOURCES CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restated for Barnett discontinued operations,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
a non-GAAP presentation
|
|
Twelve Months Ended December 31, 2012
|
|
Twelve Months Ended December 31, 2011
|
|
|
(Unaudited, in thousands, except per share data)
|
|
As
reported
|
|
Barnett
Discontinued
Operations
|
|
Including
Barnett
Ops
|
|
As
reported
|
|
Barnett
Discontinued
Operations
|
|
Including
Barnett
Ops
|
|
|
|
|
|
|
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGLs and oil sales
|
|
$
|
1,351,694
|
|
|
-
|
|
$
|
1,351,694
|
|
|
$
|
1,173,266
|
|
|
$
|
59,185
|
|
|
$
|
1,232,451
|
|
|
Derivative cash settlements gain (loss)
|
|
|
38,700
|
|
|
-
|
|
|
38,700
|
|
|
|
22,142
|
|
|
|
-
|
|
|
|
22,142
|
|
|
Change in mark-to-market on unrealized derivatives gain (loss)
|
|
|
5,958
|
|
|
-
|
|
|
5,958
|
|
|
|
15,762
|
|
|
|
-
|
|
|
|
15,762
|
|
|
Ineffective hedging gain (loss)
|
|
|
(3,221
|
)
|
|
-
|
|
|
(3,221
|
)
|
|
|
2,183
|
|
|
|
-
|
|
|
|
2,183
|
|
|
Gain (loss) on sale of properties
|
|
|
49,132
|
|
|
-
|
|
|
49,132
|
|
|
|
2,259
|
|
|
|
-
|
|
|
|
2,259
|
|
|
Brokered natural gas and marketing
|
|
|
15,078
|
|
|
-
|
|
|
15,078
|
|
|
|
12,693
|
|
|
|
6
|
|
|
|
12,699
|
|
|
Equity method investment
|
|
|
(372
|
)
|
|
-
|
|
|
(372
|
)
|
|
|
(1,043
|
)
|
|
|
4,771
|
|
|
|
3,728
|
|
|
Interest and other
|
|
|
735
|
|
|
-
|
|
|
735
|
|
|
|
3,380
|
|
|
|
4
|
|
|
|
3,384
|
|
|
|
|
|
1,457,704
|
|
|
-
|
|
|
1,457,704
|
|
|
|
1,230,642
|
|
|
|
63,966
|
|
|
|
1,294,608
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating
|
|
|
113,490
|
|
|
-
|
|
|
113,490
|
|
|
|
110,985
|
|
|
|
10,035
|
|
|
|
121,020
|
|
|
Direct operating – non-cash stock-based compensation
|
|
|
2,415
|
|
|
-
|
|
|
2,415
|
|
|
|
1,987
|
|
|
|
45
|
|
|
|
2,032
|
|
|
Transportation, gathering and compression
|
|
|
192,445
|
|
|
-
|
|
|
192,445
|
|
|
|
120,755
|
|
|
|
5,257
|
|
|
|
126,012
|
|
|
Production and ad valorem taxes
|
|
|
41,912
|
|
|
-
|
|
|
41,912
|
|
|
|
27,666
|
|
|
|
1,309
|
|
|
|
28,975
|
|
|
Pennsylvania impact fee – prior year
|
|
|
25,208
|
|
|
-
|
|
|
25,208
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
Brokered natural gas and marketing
|
|
|
18,669
|
|
|
-
|
|
|
18,669
|
|
|
|
10,531
|
|
|
|
-
|
|
|
|
10,531
|
|
|
Brokered natural gas and marketing non-cash stock-based comp
|
|
|
1,765
|
|
|
-
|
|
|
1,765
|
|
|
|
1,455
|
|
|
|
-
|
|
|
|
1,455
|
|
|
Exploration
|
|
|
65,758
|
|
|
-
|
|
|
65,758
|
|
|
|
77,259
|
|
|
|
37
|
|
|
|
77,296
|
|
|
Exploration – non-cash stock-based compensation
|
|
|
4,049
|
|
|
-
|
|
|
4,049
|
|
|
|
4,108
|
|
|
|
-
|
|
|
|
4,108
|
|
|
Abandonment and impairment of unproved properties
|
|
|
125,278
|
|
|
-
|
|
|
125,278
|
|
|
|
79,703
|
|
|
|
-
|
|
|
|
79,703
|
|
|
General and administrative
|
|
|
125,355
|
|
|
-
|
|
|
125,355
|
|
|
|
113,461
|
|
|
|
-
|
|
|
|
113,461
|
|
|
General and administrative – non-cash stock-based
compensation
|
|
|
44,541
|
|
|
-
|
|
|
44,541
|
|
|
|
36,244
|
|
|
|
-
|
|
|
|
36,244
|
|
|
General and administrative – lawsuit settlements
|
|
|
3,167
|
|
|
-
|
|
|
3,167
|
|
|
|
540
|
|
|
|
-
|
|
|
|
540
|
|
|
General and administrative – bad debt expense
|
|
|
750
|
|
|
-
|
|
|
750
|
|
|
|
946
|
|
|
|
-
|
|
|
|
946
|
|
|
Deferred compensation plan
|
|
|
7,203
|
|
|
-
|
|
|
7,203
|
|
|
|
43,209
|
|
|
|
-
|
|
|
|
43,209
|
|
|
Interest expense
|
|
|
168,798
|
|
|
-
|
|
|
168,798
|
|
|
|
125,052
|
|
|
|
14,791
|
|
|
|
139,843
|
|
|
Loss on early extinguishment of debt
|
|
|
11,063
|
|
|
-
|
|
|
11,063
|
|
|
|
18,576
|
|
|
|
-
|
|
|
|
18,576
|
|
|
Depletion, depreciation and amortization
|
|
|
445,228
|
|
|
-
|
|
|
445,228
|
|
|
|
341,221
|
|
|
|
8,894
|
|
|
|
350,115
|
|
|
Impairment of proved properties and other assets
|
|
|
35,554
|
|
|
-
|
|
|
35,554
|
|
|
|
38,681
|
|
|
|
-
|
|
|
|
38,681
|
|
|
|
|
|
1,432,648
|
|
|
-
|
|
|
1,432,648
|
|
|
|
1,152,379
|
|
|
|
40,368
|
|
|
|
1,192,747
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
25,056
|
|
|
-
|
|
|
25,056
|
|
|
|
78,263
|
|
|
|
23,598
|
|
|
|
101,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 operations
|
|
|
13,002
|
|
|
-
|
|
|
13,002
|
|
|
|
42,706
|
|
|
|
15,320
|
|
|
|
58,026
|
|
Discontinued operations-Barnett Shale, net of tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
15,320
|
|
|
|
(15,320
|
)
|
|
|
-
|
|
Net income (loss)
|
|
$
|
13,002
|
|
|
-
|
|
$
|
13,002
|
|
|
$
|
58,026
|
|
|
|
-
|
|
|
$
|
58,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING HIGHLIGHTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
|
591,679
|
|
|
-
|
|
|
591,679
|
|
|
|
397,825
|
|
|
|
32,316
|
|
|
|
430,141
|
|
|
NGLs (bbl)
|
|
|
19,036
|
|
|
-
|
|
|
19,036
|
|
|
|
14,664
|
|
|
|
605
|
|
|
|
15,269
|
|
|
Oil (bbl)
|
|
|
7,790
|
|
|
-
|
|
|
7,790
|
|
|
|
5,369
|
|
|
|
23
|
|
|
|
5,392
|
|
|
Gas equivalents (mcfe)
|
|
|
752,637
|
|
|
-
|
|
|
752,637
|
|
|
|
518,019
|
|
|
|
36,079
|
|
|
|
554,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices realized before transportation, gathering and
compression:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
$
|
3.95
|
|
|
-
|
|
$
|
3.95
|
|
|
$
|
5.22
|
|
|
|
-
|
|
|
$
|
5.13
|
|
|
NGLs (bbl)
|
|
$
|
42.60
|
|
|
-
|
|
$
|
42.60
|
|
|
$
|
52.03
|
|
|
|
-
|
|
|
$
|
51.79
|
|
|
Oil (bbl)
|
|
$
|
83.64
|
|
|
-
|
|
$
|
83.64
|
|
|
$
|
81.34
|
|
|
|
-
|
|
|
$
|
81.38
|
|
|
Gas equivalents (mcfe)
|
|
$
|
5.05
|
|
|
-
|
|
$
|
5.05
|
|
|
$
|
6.32
|
|
|
|
-
|
|
|
$
|
6.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 costs
|
|
$
|
0.41
|
|
|
-
|
|
$
|
0.41
|
|
|
$
|
0.59
|
|
|
$
|
0.76
|
|
|
$
|
0.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation, gathering and compression cost per mcf:
|
|
$
|
0.70
|
|
|
-
|
|
$
|
0.70
|
|
|
$
|
0.85
|
|
|
$
|
0.53
|
|
|
$
|
0.83
|
|
|
|
|
|
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 other
|
|
|
148,646
|
|
|
|
86,300
|
|
|
|
|
|
|
|
|
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 thousands)
|
|
Three Months Ended
December 31,
|
|
Twelve Months Ended
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 operations
|
|
|
-
|
|
|
|
164
|
|
|
|
-
|
|
|
|
(15,320
|
)
|
|
(Gain) loss from equity investment, net of distributions
|
|
|
3,418
|
|
|
|
(1,906
|
)
|
|
|
5,670
|
|
|
|
16,871
|
|
|
Deferred income tax expense (benefit)
|
|
|
31,742
|
|
|
|
(425
|
)
|
|
|
13,832
|
|
|
|
34,920
|
|
|
Depletion, depreciation, amortization and proved property impairment
|
|
|
147,489
|
|
|
|
97,092
|
|
|
|
480,782
|
|
|
|
379,902
|
|
|
Exploration dry hole costs
|
|
|
9
|
|
|
|
1,372
|
|
|
|
841
|
|
|
|
3,888
|
|
|
Abandonment and impairment of unproved properties
|
|
|
21,230
|
|
|
|
27,639
|
|
|
|
125,278
|
|
|
|
79,703
|
|
|
Mark-to-market loss (gain) on oil and gas derivatives not designated
as hedges
|
|
|
24,118
|
|
|
|
51,331
|
|
|
|
(5,958
|
)
|
|
|
(15,762
|
)
|
|
Unrealized derivatives (gain) loss
|
|
|
(1,840
|
)
|
|
|
348
|
|
|
|
3,221
|
|
|
|
(2,183
|
)
|
|
Allowance for bad debts
|
|
|
750
|
|
|
|
500
|
|
|
|
750
|
|
|
|
946
|
|
|
Amortization of deferred financing costs, loss on extinguishment of
debt, and other
|
|
|
17,195
|
|
|
|
1,705
|
|
|
|
23,165
|
|
|
|
25,458
|
|
|
Deferred and stock-based compensation
|
|
|
1,563
|
|
|
|
20,220
|
|
|
|
60,136
|
|
|
|
86,979
|
|
|
Gain (loss) on sale of assets and other
|
|
|
(61,836
|
)
|
|
|
(3,539
|
)
|
|
|
(49,132
|
)
|
|
|
(2,259
|
)
|
|
|
|
|
|
|
|
|
|
|
|
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 and other
|
|
|
(11,915
|
)
|
|
|
(413
|
)
|
|
|
18,220
|
|
|
|
9,540
|
|
|
Net changes in working capital
|
|
|
(50,824
|
)
|
|
|
(10,179
|
)
|
|
|
(24,488
|
)
|
|
|
(40,969
|
)
|
|
Net cash provided from continuing operations
|
|
|
185,976
|
|
|
|
181,333
|
|
|
|
647,099
|
|
|
|
610,200
|
|
|
Net cash provided from discontinued operations
|
|
|
-
|
|
|
|
1,959
|
|
|
|
-
|
|
|
|
21,437
|
|
|
Net cash provided from operating activities
|
|
$
|
185,976
|
|
|
$
|
183,292
|
|
|
$
|
647,099
|
|
|
$
|
631,637
|
|
|
|
|
|
|
|
|
RECONCILIATION OF NET CASH PROVIDED FROM OPERATING
ACTIVITIES,
AS REPORTED, TO CASH FLOW FROM
OPERATIONS BEFORE
CHANGES IN WORKING CAPITAL, a
non-GAAP measure
|
|
|
|
|
|
(Unaudited, in thousands)
|
|
Three Months Ended
December 31,
|
|
Twelve Months Ended
December 31,
|
|
|
|
|
2012
|
|
|
|
2011
|
|
|
|
2012
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided from operating activities, as reported
|
|
$
|
185,976
|
|
|
$
|
183,292
|
|
|
$
|
647,099
|
|
|
$
|
631,637
|
|
|
Net changes in working capital from continuing operations
|
|
|
50,824
|
|
|
|
10,179
|
|
|
|
24,488
|
|
|
|
40,969
|
|
|
Exploration expense
|
|
|
12,873
|
|
|
|
22,670
|
|
|
|
60,778
|
|
|
|
73,371
|
|
|
Lawsuit settlements
|
|
|
644
|
|
|
|
302
|
|
|
|
3,167
|
|
|
|
540
|
|
|
Equity method investment distribution / intercompany elimination
|
|
|
(3,241
|
)
|
|
|
1,550
|
|
|
|
(5,298
|
)
|
|
|
(15,828
|
)
|
|
Prior year Pennsylvania impact fee
|
|
|
501
|
|
|
|
-
|
|
|
|
25,208
|
|
|
|
-
|
|
|
Non-cash compensation adjustment
|
|
|
292
|
|
|
|
85
|
|
|
|
295
|
|
|
|
270
|
|
|
Net changes in working capital from discontinued operations and other
|
|
|
-
|
|
|
|
(2,136
|
)
|
|
|
-
|
|
|
|
6,366
|
|
|
Cash flow from operations before changes in working capital, a
non-GAAP measure
|
|
$
|
247,869
|
|
|
$
|
215,942
|
|
|
$
|
755,737
|
|
|
$
|
737,325
|
|
|
|
|
|
|
|
|
|
|
|
|
ADJUSTED WEIGHTED AVERAGE SHARES OUTSTANDING
|
|
|
|
|
|
|
|
|
|
(Unaudited, in thousands)
|
|
Three Months Ended
December 31,
|
|
Twelve Months Ended
December 31,
|
|
|
|
|
2012
|
|
|
|
2011
|
|
|
|
2012
|
|
|
|
2011
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
162,627
|
|
|
|
161,253
|
|
|
|
162,306
|
|
|
|
160,906
|
|
|
Stock held by deferred compensation plan
|
|
|
(2,795
|
)
|
|
|
(2,840
|
)
|
|
|
(2,875
|
)
|
|
|
(2,876
|
)
|
|
Adjusted basic
|
|
|
159,832
|
|
|
|
158,413
|
|
|
|
159,431
|
|
|
|
158,030
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive:
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
162,627
|
|
|
|
161,253
|
|
|
|
162,306
|
|
|
|
160,906
|
|
|
Anti-dilutive or dilutive stock options under treasury method
|
|
|
(2,068
|
)
|
|
|
(2,840
|
)
|
|
|
(1,999
|
)
|
|
|
(1,465
|
)
|
|
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
Excludes Barnett Operations
|
|
Non-GAAP
Includes Barnett Operations
|
|
|
|
|
(Unaudited, in thousands, except per unit data)
|
|
Three Months Ended December 31,
|
|
Three Months Ended December 31,
|
|
|
|
|
2012
|
|
|
|
2011
|
|
|
%
|
|
|
|
2012
|
|
|
|
2011
|
|
|
%
|
|
|
Natural gas, NGLs and oil sales components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
213,348
|
|
|
$
|
165,300
|
|
|
|
|
$
|
213,348
|
|
|
$
|
165,256
|
|
|
|
|
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 oil sales, as reported
|
|
$
|
398,688
|
|
|
$
|
331,720
|
|
|
20
|
%
|
|
$
|
398,688
|
|
|
$
|
331,908
|
|
|
20
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 on unrealized derivatives
|
|
|
(24,117
|
)
|
|
|
(51,331
|
)
|
|
|
|
|
(24,117
|
)
|
|
|
(51,331
|
)
|
|
|
|
Unrealized ineffectiveness
|
|
|
1,840
|
|
|
|
(348
|
)
|
|
|
|
|
1,840
|
|
|
|
(348
|
)
|
|
|
|
Total derivative fair value income (loss), as reported
|
|
$
|
(5,571
|
)
|
|
$
|
(37,880
|
)
|
|
|
|
$
|
(5,571
|
)
|
|
$
|
(37,880
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGLs and oil sales, including all cash-settled
derivatives (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
253,958
|
|
|
$
|
217,358
|
|
|
|
|
$
|
253,958
|
|
|
$
|
217,314
|
|
|
|
|
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 compression, as reported
|
|
$
|
55,281
|
|
|
$
|
34,576
|
|
|
|
|
$
|
55,281
|
|
|
$
|
34,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production during the period (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
|
60,280,617
|
|
|
|
45,147,273
|
|
|
34
|
%
|
|
|
60,280,617
|
|
|
|
45,173,850
|
|
|
33
|
%
|
|
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 (mcfe) (b)
|
|
|
77,676,891
|
|
|
|
57,453,189
|
|
|
35
|
%
|
|
|
77,676,891
|
|
|
|
57,505,398
|
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production – average per day (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
|
655,224
|
|
|
|
490,731
|
|
|
34
|
%
|
|
|
655,224
|
|
|
|
491,020
|
|
|
33
|
%
|
|
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 (mcfe) (b)
|
|
|
844,314
|
|
|
|
624,491
|
|
|
35
|
%
|
|
|
844,314
|
|
|
|
625,059
|
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including cash-settled hedges and derivatives before
third party transportation costs (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
$
|
4.21
|
|
|
$
|
4.81
|
|
|
-12
|
%
|
|
$
|
4.21
|
|
|
$
|
4.81
|
|
|
-12
|
%
|
|
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 (mcfe) (b)
|
|
$
|
5.35
|
|
|
$
|
6.01
|
|
|
-11
|
%
|
|
$
|
5.35
|
|
|
$
|
6.01
|
|
|
-11
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including cash-settled hedges and derivatives (d):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
$
|
3.35
|
|
|
$
|
4.10
|
|
|
-18
|
%
|
|
$
|
3.35
|
|
|
$
|
4.09
|
|
|
-18
|
%
|
|
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 (mcfe) (b)
|
|
$
|
4.64
|
|
|
$
|
5.41
|
|
|
-14
|
%
|
|
$
|
4.64
|
|
|
$
|
5.41
|
|
|
-14
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
Includes Barnett Operations
Twelve Months Ended December 31,
|
|
|
|
|
(Unaudited, in thousands, except per unit data)
|
|
As Reported, GAAP
Excludes Barnett Operations
Twelve Months Ended December 31,
|
|
|
|
|
|
2012
|
|
|
|
2011
|
|
|
%
|
|
|
2012
|
|
|
|
2011
|
|
|
%
|
|
|
Natural gas, NGLs and oil sales components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
612,354
|
|
|
$
|
611,864
|
|
|
|
|
$612,354
|
|
|
$
|
651,533
|
|
|
|
|
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 oil sales, as reported
|
|
$
|
1,351,694
|
|
|
$
|
1,173,266
|
|
|
15
|
%
|
|
$1,351,694
|
|
|
$
|
1,232,451
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 on unrealized derivatives
|
|
|
5,958
|
|
|
|
15,762
|
|
|
|
|
5,958
|
|
|
|
15,762
|
|
|
|
|
Unrealized ineffectiveness
|
|
|
(3,221
|
)
|
|
|
2,183
|
|
|
|
|
(3,221
|
)
|
|
|
2,183
|
|
|
|
|
Total derivative fair value income (loss), as reported
|
|
$
|
41,437
|
|
|
$
|
40,087
|
|
|
|
|
$41,437
|
|
|
$
|
40,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, NGLs and oil sales, including all cash-settled
derivatives (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
855,090
|
|
|
$
|
757,563
|
|
|
|
|
$855,090
|
|
|
$
|
805,838
|
|
|
|
|
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 compression, as reported
|
|
$
|
192,445
|
|
|
$
|
120,755
|
|
|
|
|
$192,445
|
|
|
$
|
126,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production during the period (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
|
216,554,689
|
|
|
|
145,206,124
|
|
|
49
|
%
|
|
216,554,689
|
|
|
|
157,001,395
|
|
|
38
|
%
|
|
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 (mcfe) (b)
|
|
|
275,465,245
|
|
|
|
189,076,858
|
|
|
46
|
%
|
|
275,465,245
|
|
|
|
202,245,656
|
|
|
36
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production – average per day (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
|
591,679
|
|
|
|
397,825
|
|
|
49
|
%
|
|
591,679
|
|
|
|
430,141
|
|
|
38
|
%
|
|
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 (mcfe) (b)
|
|
|
752,637
|
|
|
|
518,019
|
|
|
45
|
%
|
|
752,637
|
|
|
|
554,098
|
|
|
36
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including cash-settled hedges and derivatives before
third party transportation costs (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
$
|
3.95
|
|
|
$
|
5.22
|
|
|
-24
|
%
|
|
$3.95
|
|
|
$
|
5.13
|
|
|
-23
|
%
|
|
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 (mcfe) (b)
|
|
$
|
5.05
|
|
|
$
|
6.32
|
|
|
-20
|
%
|
|
$5.05
|
|
|
$
|
6.20
|
|
|
-19
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices, including cash-settled hedges and derivatives (d):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf)
|
|
$
|
3.11
|
|
|
$
|
4.43
|
|
|
-30
|
%
|
|
$3.11
|
|
|
$
|
4.37
|
|
|
-29
|
%
|
|
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 (mcfe) (b)
|
|
$
|
4.35
|
|
|
$
|
5.68
|
|
|
-23
|
%
|
|
$4.35
|
|
|
$
|
5.58
|
|
|
-22
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, except per share data)
|
|
Three Months Ended December 31,
|
|
Twelve Months Ended December 31,
|
|
|
|
2012
|
|
|
|
2011
|
|
|
%
|
|
|
|
2012
|
|
|
|
2011
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations before income taxes, as
reported
|
|
$82,926
|
|
|
$
|
(2,614
|
)
|
|
3272
|
%
|
|
$
|
25,056
|
|
|
$
|
78,263
|
|
|
-68
|
%
|
|
Adjustment for certain items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on sale of properties
|
|
(61,836
|
)
|
|
|
(3,539
|
)
|
|
|
|
|
(49,132
|
)
|
|
|
(2,259
|
)
|
|
|
|
Barnett discontinued operations less gain on sale
|
|
-
|
|
|
|
(177
|
)
|
|
|
|
|
-
|
|
|
|
18,827
|
|
|
|
|
Change in mark-to-market on unrealized derivatives (gain) loss
|
|
24,117
|
|
|
|
51,331
|
|
|
|
|
|
(5,958
|
)
|
|
|
(15,762
|
)
|
|
|
|
Unrealized derivative (gain) loss
|
|
(1,840
|
)
|
|
|
348
|
|
|
|
|
|
3,221
|
|
|
|
(2,183
|
)
|
|
|
|
Abandonment and impairment of unproved properties
|
|
21,230
|
|
|
|
27,639
|
|
|
|
|
|
125,278
|
|
|
|
79,703
|
|
|
|
|
Loss on early extinguishment of debt
|
|
11,063
|
|
|
|
-
|
|
|
|
|
|
11,063
|
|
|
|
18,576
|
|
|
|
|
Prior year Pennsylvania impact fee
|
|
501
|
|
|
|
-
|
|
|
|
|
|
25,208
|
|
|
|
-
|
|
|
|
|
Proved property and other asset impairment
|
|
34,273
|
|
|
|
-
|
|
|
|
|
|
35,554
|
|
|
|
38,681
|
|
|
|
|
Lawsuit settlements
|
|
644
|
|
|
|
302
|
|
|
|
|
|
3,167
|
|
|
|
540
|
|
|
|
|
Brokered natural gas and marketing – non cash stock-based
compensation
|
|
452
|
|
|
|
348
|
|
|
|
|
|
1,765
|
|
|
|
1,455
|
|
|
|
|
Direct operating – non-cash stock-based compensation
|
|
768
|
|
|
|
571
|
|
|
|
|
|
2,415
|
|
|
|
1,987
|
|
|
|
|
Exploration expenses – non-cash stock-based compensation
|
|
1,001
|
|
|
|
940
|
|
|
|
|
|
4,049
|
|
|
|
4,108
|
|
|
|
|
General & administrative – non-cash stock-based compensation
|
|
13,786
|
|
|
|
8,756
|
|
|
|
|
|
44,541
|
|
|
|
36,244
|
|
|
|
|
Deferred compensation plan – non-cash adjustment
|
|
(14,352
|
)
|
|
|
9,640
|
|
|
|
|
|
7,203
|
|
|
|
43,209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations before income taxes, as adjusted
|
|
112,733
|
|
|
|
93,545
|
|
|
21
|
%
|
|
|
233,430
|
|
|
|
301,389
|
|
|
-23
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, a non-GAAP measure
|
|
$73,359
|
|
|
$
|
53,262
|
|
|
38
|
%
|
|
$
|
147,857
|
|
|
$
|
176,380
|
|
|
-16
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 outstanding, if dilutive
|
|
160,559
|
|
|
|
160,051
|
|
|
|
|
|
160,307
|
|
|
|
159,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
Stockhouse.com: Taking
it to the street
