QEP Resources, Inc. : QEP Resources Reports 2011 EBITDA of $1.39 Billion and Production of 275.2 Bcfe
02/22/2012| 04:50pm US/Eastern
Recommend:
DENVER, Feb. 22, 2012 /PRNewswire/ -- QEP Resources (NYSE: QEP) reported adjusted EBITDA (a non-GAAP measure) of $1,386.6 million for 2011 compared to $1,140.5 million in 2010, a 22% increase. Factors driving QEP's results included 20% higher net production and 54% higher oil and NGL production from QEP Energy, increased gathering and processing margins at QEP Field Services, and higher net realized crude oil and NGL prices which more than offset net realized natural gas prices that were 11% lower than in the previous year at QEP Energy. Adjusted EBITDA in the fourth quarter of 2011 was $390.5 million compared to $298.5 million a year earlier, a 31% increase.
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ADJUSTED EBITDA BY SUBSIDIARY
Three Months Ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 Change 2011 2010 Change
---- ---- ------ ---- ---- ------
(in millions)
QEP Energy $300.5 $242.4 24% $1,057.5 $926.2 14%
QEP Field
Services 87.2 52.4 66% 320.3 203.9 57%
QEP Marketing
and other 2.8 3.7 -24% 8.8 10.4 -15%
Total
Adjusted
EBITDA (1) $390.5 $298.5 31% $1,386.6 $1,140.5 22%
====== ====== === ======== ======== ===
(1) See attached schedule for a reconciliation of Adjusted EBITDA to net income.
QEP Resources net income from continuing operations for 2011 was $267.2 million or $1.50 per diluted share, compared to $283.0 million or $1.60 per diluted share in 2010. QEP Resources had a net loss from continuing operations in the fourth quarter of 2011 of $0.3 million or no earnings per diluted share, compared to net income of $65.0 million or $0.37 per diluted share a year earlier. The net loss in the fourth quarter of 2011 was attributed to a non-cash price-related impairment charge of $195.2 million on some of its mature, dry gas, and higher cost properties in both the Northern and Southern Regions. See Financial and Operating Results for additional information.
Excluding changes in unrealized gains and losses on natural gas basis-only swaps, gains and losses on asset sales, non-cash price-related impairment charge, separation costs and losses on early extinguishment of debt, QEP Resources adjusted net income from continuing operations (a non-GAAP measure) was $316.2 million or $1.77 per diluted share in 2011 compared to $217.8 million or $1.23 per diluted share in 2010. Similarly adjusted fourth quarter 2011 net income from continuing operations was $104.6 million or $0.58 per diluted share compared to net income of $44.8 million or $0.25 per diluted share in the year earlier period.
NET INCOME BY SUBSIDIARY
Three months ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 Change 2011 2010 Change
---- ---- ------ ---- ---- ------
(in millions, except per share amounts)
QEP Energy (1) $(43.5) $38.9 -212% $104.7 $203.9 -49%
QEP Field Services (2) 40.3 22.6 78% 154.5 91.1 70%
QEP Marketing and other 2.9 3.1 -6% 8.4 6.7 25%
QEP Resources - 0.4 -100% (0.4) (18.7) -98%
Income from continuing (0.3) 65.0 -100% 267.2 283.0 -6%
operations (2)
Discontinued operations
(3) - - - - 43.2 -100%
NET INCOME (2) $(0.3) $65.0 -100% $267.2 $326.2 -18%
===== ===== ==== ====== ====== ===
Earnings per diluted share
From continuing
operations $- $0.37 $1.50 $1.60
Total earnings $- $0.37 $1.50 $1.84
Weighted-average
diluted shares 178.2 177.4 178.4 177.3
(1) During the fourth quarter of 2011, QEP Energy recorded a non-cash price-
related impairment charge of $195.2 million on some of its mature, dry gas, and
higher cost properties in both the Northern and Southern Regions. See Financial
and Operating Results for additional information.
(2) Net income represents amounts attributable to QEP Resources after deducting
non-controlling interest.
(3) QEP Resources completed its tax-free spin-off from Questar Corporation on
June 30, 2010. In conjunction with the spin-off, QEP Resources distributed the
common stock of its wholly owned subsidiary, Wexpro Company, to Questar.
Accordingly, Wexpro's historical financial results have been presented as
discontinued operations in this release.
"QEP Resources completed another successful year in 2011," said Chuck Stanley, President and CEO. "QEP Energy production was up 20% from last year, driven by strong results from the Pinedale Anticline and Haynesville Shale plays, combined with significant contributions from new wells in our Woodford "Cana" Shale and Bakken/Three Forks plays. With 68% of our 2011 drilling capital directed to oil and liquids-rich gas plays, we grew oil and NGL production 54% and year-end proved crude oil and NGL reserves 107% compared to 2010. Crude oil and NGL production accounted for 29% of QEP Energy net realized production revenues for the year and we expect that share to grow as we allocate more of our 2012 QEP Energy capital to our higher-margin oil and liquids-rich gas resource plays. Our midstream business, QEP Field Services, had an excellent year, thanks to a combination of great execution coupled with strong gas processing margins. Our new Blacks Fork II plant continues to perform well, and the midstream team is now focused on new projects to drive additional growth in 2012 and beyond," Stanley added.
Financial and Operating Results
-- QEP Energy grew natural gas, oil and NGL net production to 275.2 billion
cubic feet of natural gas equivalent (Bcfe) compared to 229.0 Bcfe in
2010. Crude oil and NGL comprised 14% of reported production volumes.
-- QEP Energy Adjusted EBITDA increased 14% compared to 2010, driven by a
20% increase in production and increased net realized liquid prices -
30% for crude oil and 22% for NGL, partially offset by an 11% decrease
in net realized natural gas prices.
-- QEP Energy net realized natural gas prices averaged $4.74 per thousand
cubic feet (Mcf), compared to $5.32 per Mcf in 2010. Field-level
natural gas prices in 2011 were $3.95 per Mcf compared to $4.18 per Mcf
in 2010. Natural gas-related derivative settlements contributed $187.8
million in 2011 ($0.79 per Mcf) compared to $232.1 million in 2010
($1.14 per Mcf).
-- QEP Energy net crude oil and NGL revenues (including the settlement of
crude oil-related derivatives) increased 85% compared to 2010 and
represented 29% of net realized production revenues.
-- Net realized crude oil prices averaged $86.63 per barrel, up 30%
compared to 2010. Oil related derivative settlements contributed $1.6
million in 2011 ($0.43 per bbl) compared to a loss of $8.7 million in
2010 ($2.91 per bbl).
-- Net realized NGL prices at QEP Energy averaged $47.76 per barrel, up 22%
compared to the 2010.
-- QEP Field Services Adjusted EBITDA increased 57% compared to 2010,
driven by a 22% increase in gathering margin and a 93% increase in
processing margin. Net income was $154.5 million, up 70% compared to
the 2010.
-- QEP Energy 2011 capital investment (on an accrual basis) was $1,338.8
million comprised of $1,290.8 million in drilling and completion and
other expenditures (including $0.3 million of dry hole exploration
expense) and $48.0 million in property acquisition costs.
-- QEP Field Services 2011 capital investments (on an accrual basis) to
expand capacity at its gathering, processing and treating facilities in
western Wyoming, eastern Utah and the Haynesville/Cotton Valley area of
northwest Louisiana totaled $101.6 million.
-- Field Services introduced gas into the Blacks Fork II plant on July
14th. QEP Energy entered into a fee-based processing agreement with QEP
Field Services under which QEP Field Services provides cryogenic gas
processing services for QEP Energy's Pinedale production volumes at
Blacks Fork II effective August 1, 2011.
-- Separation costs and losses on early extinguishment of debt reduced QEP
Resources pre-tax income from continuing operations by $0.7 million in
2011 compared to $26.8 million in 2010.
-- Through December 31, 2011, QEP designated most of its natural gas, oil
and NGL derivative contracts as cash flow hedges, whose unrealized fair
value gains and losses were recorded to accumulated other comprehensive
income on QEP's balance sheet. Effective January 1, 2012, the Company
has elected to de-designate all of its natural gas, oil and NGL
derivative contracts that had previously been designated as cash flow
hedges at December 31, 2011, and has elected to discontinue hedge
accounting prospectively.
-- During the year ended December 31, 2011, QEP revised its reporting of
transportation and handling costs to appropriately reflect revenues and
expenses in accordance with GAAP and industry practice. The
transportation and other handling costs are recast on the Consolidated
Income Statement from revenues to "Natural gas, oil and NGL
transportation and other handling costs." All prior periods have been
adjusted to reflect the current year presentation. The impact of this
revision is immaterial and has no effect on net income and Adjusted
EBITDA.
-- During the fourth quarter of 2011, QEP recorded a non-cash price related
impairment charge of $195.2 million on some of its mature, dry gas, and
higher cost properties in both the Northern and Southern Regions. The
impairment charge related to the reduced value of these areas resulting
from lower natural gas prices and the current forward curve for natural
gas prices. The assets were written down to their estimated fair
values. Of the $195.2 million impairment charge, $163.5 million related
to properties in the Northern Region with the remaining $31.7 million
related to properties in the Southern Region.
QEP 2012 Adjusted EBITDA, Capital Expenditure and Production Guidance
Due to a dramatic decrease in 2012 natural gas prices, QEP now expects 2012 Adjusted EBITDA to range from $1,350 to $1,450 million, compared to a previously forecasted range of $1,450 to $1,550 million. QEP Energy expects 2012 production should range from 305 to 310 Bcfe, unchanged from the previously forecasted range.
The company's guidance assumes commodity derivative positions in place on the date of this release and other assumptions summarized in the table below:
Guidance and Assumptions
2012
----
Current Previous
Forecast Forecast
-------- --------
QEP Resources Adjusted EBITDA
(millions) $1,350 - $1,450 $1,450 - $1,550
QEP Energy capital investment
(millions) $1,130 - $1,280 $1,330
QEP Field Services capital investment
(millions) $170 $170
QEP Marketing and other capital
investment (millions) - -
Total QEP Resources capital investment
(millions) $1,300 - $1,450 $1,500
QEP Energy production - Bcfe 305 - 310 305 - 310
NYMEX gas price per MMBtu (1) $2.00 - $3.00 $3.75 - $4.25
NYMEX crude oil price per bbl (1) $90.00 - $100.00 $90.00 - $100.00
NYMEX/Rockies basis differential per
MMBtu (1) $0.20 - $0.15 $0.20 - $0.15
NYMEX/Midcontinent basis differential
per MMBtu (1) $0.20 - $0.15 $0.20 - $0.15
(1) For remaining 2012 un-hedged volumes
Approximately 65% of QEP Energy's forecasted natural gas production, 56% of forecasted oil production and 18% of forecasted NGL production for 2012 is subject to commodity derivatives. On a natural gas equivalent basis, the company has approximately 60% of its forecasted production for 2012 subject to commodity derivatives. A table with details of the company's positions is included at the end of this release.
In response to current commodity prices, the company is decreasing its capital allocated to the Haynesville Shale and other dry gas development areas and plans to allocate 88% of its 2012 capital to higher return projects including Pinedale, the Uinta Basin Red Wash Mesaverde play, the Bakken, and oil-directed horizontal drilling in the Powder River Basin and Midcontinent. In response to growing QEP Energy and third-party demand, QEP Field Services will begin construction on Iron Horse II, a new 150 MMcfd fee-based cryogenic gas processing plant in the Uinta Basin.
QEP Energy Results
QEP Energy's 2011 production increased 20% to 275.2 Bcfe compared to 229.0 Bcfe in the 2010 period. The Southern Region (formerly the Midcontinent region) contributed 56% of total production compared to 53% in 2010.
QEP Energy - Production by Major Area
Three months ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 Change 2011 2010 Change
---- ---- ------ ---- ---- ------
(in Bcfe)
Southern
Region
--------
Haynesville/
Cotton
Valley 26.6 22.4 19% 107.5 - 79.8 35%
Midcontinent 12.7 10.9 17% 46.2 - 40.6 14%
Total
Southern
Region 39.3 33.3 18% 153.7 120.4 28%
Northern
Region
--------
Pinedale
Anticline 23.8 18.6 28% 79.4 - 68.5 16%
Uinta
Basin
(1) 4.6 5.5 -16% 20.8 - 21.4 -3%
Rockies
Legacy 6.2 4.7 32% 21.3 - 18.7 14%
Total
Northern
Region 34.6 28.8 20% 121.5 108.6 12%
---- ---- ----- -----
Total
production 73.9 62.1 19% 275.2 229.0 20%
==== ==== ===== =====
(1) Includes 1.6 Bcfe in Q1 2011 from prior periods
due to a change in ownership interest in a federal
unit.
QEP Energy - Commodity Prices (1)
Three months ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 Change 2011 2010 Change
---- ---- ------ ---- ---- ------
Natural gas price ($ per Mcf)
Average
field-
level
natural
gas
price $3.66 $3.65 0% $3.95 $4.18 -6%
Natural
gas
hedging
impact
(2) 1.59 2.07 -23% 1.29 1.74 -26%
Average
revenue 5.25 5.72 -8% 5.24 5.92 -11%
Realized
losses
on
basis-
only
swaps
(3) (0.51) (0.58) -12% (0.50) (0.60) -17%
Net
realized
natural
gas
price $4.74 $5.14 -8% $4.74 $5.32 -11%
===== ===== ===== =====
Oil
price
($ per
bbl)
Average
field-
level
oil
price $87.01 $72.50 20% $86.20 $69.39 24%
Oil
hedging
impact
(2) 0.55 (4.20) -113% 0.43 (2.91) -115%
Net
realized
oil
price $87.56 $68.30 28% $86.63 $66.48 30%
NGL
price
($ per
bbl)
Average
field-
level
NGL
price $56.34 $39.30 43% $47.76 $39.04 22%
(1) Recast to reflect exclusion of natural gas,
oil and NGL transportation and other handling
costs.
(2) Reported in revenues in the consolidated
income statement.
(3) Reported below operating income in the
consolidated income statement.
QEP Energy - Operating Expenses
Three months ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 Change 2011 2010 Change
---- ---- ------ ---- ---- ------
(per Mcfe)
Depreciation,
depletion and
amortization $2.48 $2.58 -4% $2.57 $2.59 -1%
Lease
operating
expense 0.57 0.58 -2% 0.54 0.56 -4%
Natural gas,
oil and NGL
transportation 0.75 0.57 32% 0.68 0.55 24%
and other
handling
costs
General and
administrative
expense 0.39 0.36 8% 0.36 0.34 6%
Allocated
interest
expense 0.29 0.31 -6% 0.30 0.34 -12%
Production
taxes 0.34 0.32 6% 0.36 0.34 6%
Total
Operating
Expenses $4.82 $4.72 2% $4.81 $4.72 2%
===== ===== ===== =====
-- Depreciation, depletion and amortization expense per Mcfe (the DD&A
rate) decreased in the fourth quarter and full year 2011 compared to
2010 primarily as the result of booking additional NGL reserves in
Pinedale associated with the Blacks Fork II processing plant and the
addition of lower cost reserves in the Haynesville/Cotton Valley area.
-- Lease operating expense per Mcfe decreased in full year 2011 compared to
2010 as a result of increased production volumes in lower operating cost
areas. Growing production from high-rate, low-operating cost wells in
the Haynesville/Cotton Valley area and Pinedale coupled with declining
production from higher cost areas lowered average per Mcfe lease
operating expense. For the quarter, lease operating expenses per Mcfe
were slightly lower for the same reasons as the full year decrease.
-- Natural gas, oil and NGL transportation and other handling costs per
Mcfe were 24% higher in 2011 than in 2010, due primarily to processing
fees associated with increased NGL production and related transportation
costs under a revised processing agreement at Pinedale. Natural gas,
oil and NGL transportation and other handling costs per Mcfe were $0.18
per Mcfe higher in the fourth quarter of 2011 than in the 2010 fourth
quarter.
-- General and administrative (G&A) expense per Mcfe increased in the three
and twelve months ended December 31, 2011, as the result of higher
employee benefit and stock compensation plan related expenses, increased
legal and outside professional services and higher insurance costs which
were partially offset by increased production in the three and twelve
months ended December 31, 2011.
-- Production taxes per Mcfe increased in the current year periods compared
to 2010 as the result of increased field-level crude oil and NGL prices.
-- QEP Energy total cash cost of production lease operating expense plus
general and administrative expense, allocated interest, and production
taxes - was $1.56 per Mcfe in 2011, compared to $1.58 per Mcfe in 2010,
a 1% decrease.
Year end 2011 proved reserves increase
QEP Energy's estimated proved reserves totaled 3.6 Tcfe at December 31, 2011, up 19% from year-end 2010. Excluding price-related revisions, QEP Energy replaced 313% of 2011 production. Including price-related revisions, the reserve replacement ratio was 312% (a positive 2.1 Bcfe of price related revisions). Total combined proved crude oil and NGL reserves increased 107% from year-end 2010, driven by strong results from QEP's development program in the Bakken/Three Forks play and reserves added as a result of the completion of the Blacks Fork II plant. Approximately 24% of total proved reserves at year-end 2011 were crude oil and NGL compared to 14% at year-end 2010. Total proved developed reserves comprised 2.0 Tcfe, or 54% of the total. A reconciliation of reported quantities of proved reserves is summarized in the table below:
Natural
Natural Gas
Gas Oil NGL Equivalents
------- --- --- -----------
(Bcf) (Mbbl) (Mbbl) (Bcfe)
Total proved reserves at
December 31, 2010 2,612.9 52,276.7 17,369.5 3,030.7
Revisions of previous estimates (270.1) 1,794.0 39,290.5 (23.5)
Extensions and discoveries 641.9 17,360.4 22,600.7 881.6
Purchase of reserves in place 1.9 17.0 12.0 2.1
Sale of reserves in place (0.8) (192.0) - (1.9)
Production (236.4) (3,741.3) (2,715.6) (275.2)
------ -------- -------- ------
Total proved reserves at
December 31, 2011 2,749.4 67,514.8 76,557.1 3,613.8
======= ======== ======== =======
Details on year-end 2011 proved reserves by division or operating area, proved reserve category and percentage of total proved reserves comprised of crude oil and NGL (liquids) are as follows:
% of %
Total total PUD % liquids
(in
Bcfe) ----- ----- --------
-----
Southern Region
---------------
Haynesville/Cotton Valley 782.9 22% 46% -
Midcontinent 518.7 14% 36% 31%
Northern Region
---------------
Pinedale Anticline 1,531.0 42% 47% 23%
Uinta Basin 393.6 11% 46% 23%
Rockies Legacy 387.6 11% 50% 68%
----- ---
Total QEP Energy 3,613.8 100% 46% 24%
======= ===
For comparison, the year-end 2010 proved reserves by division or operating area, proved reserve category and percentage of total proved reserves comprised of crude oil and NGL (liquids) were as follows:
% of %
Total total PUD % liquids
(in
Bcfe) ----- ----- --------
-----
Southern Region
---------------
Haynesville/Cotton Valley 728.3 24% 55% -
Midcontinent 442.2 15% 32% 10%
Northern Region
---------------
Pinedale Anticline 1,348.9 44% 55% 5%
Uinta Basin 212.8 7% - 35%
Rockies Legacy 298.5 10% 47% 57%
Total QEP Energy 3,030.7 100% 47% 14%
======= ===
The trailing twelve-month weighted-average prices used to estimate QEP's year-end 2011 proved reserves were $3.46/Mcf for natural gas, $82.96/bbl for crude oil, and $41.55/bbl for NGL. Average natural gas prices were 10% lower, average oil prices were 26% higher, and average NGL prices were 6% higher than the applicable prices used to estimate year-end 2010 proved reserves. QEP's estimated proved reserves at December 31, 2011, were prepared by Ryder Scott Company L.P., independent petroleum engineers, in accordance with Securities and Exchange Commission regulations.
QEP Energy Operations Update
QEP adds 105 Pinedale well completions in 2011
At the Pinedale Anticline field in western Wyoming, QEP completed and turned to sales 105 new wells during 2011, including 16 new wells since the third quarter 2011 release. Drilling and completion efficiencies have allowed QEP to maintain industry-leading average gross completed well costs of $3.9 million per well in 2011. The average drill time from spud to total depth was 13.8 days in 2011, down from an average of 17 days in 2010. During the fourth quarter of 2011, QEP's Pinedale net production averaged approximately 258 MMcfed. As a result of the fee-based processing agreement entered into between QEP Energy and QEP Field Services effective August 1, 2011, QEP Energy average net equivalent production for the fourth quarter included a significant contribution from liquids (208 MMcf/day, 1,792 Bbl Oil/day and 6,637 Bbl NGL/day). The company suspends completion operations at Pinedale during the coldest months of the winter (generally from December through mid-March). QEP currently has 37 wells drilled and cased and waiting on completion. The company plans to operate 6 rigs at Pinedale for most of 2012.
Slides with maps and other supporting materials referred to in this release are posted on the Company's website www.qepres.com. Please refer to slides 5 and 6 for additional details on Pinedale.
Bakken/Three Forks oil production growth continues on QEP's 90,000 acre North Dakota leasehold
In the Williston Basin of North Dakota, QEP has completed and turned to sales 7 new Bakken and 4 new Three Forks Formation company-operated wells since the third quarter release. QEP's working interest in these wells ranges from 63% to 100%. The company operates 30 producing wells in the play (24 Bakken and 6 Three Forks) and has a working interest in 93 producing wells that are operated by others. During the fourth quarter of 2011, QEP's Bakken/Three Forks net production averaged approximately 5,019 Boepd.
QEP has 2 operated wells currently drilling and 2 operated wells waiting on completion. The company also has interests in 7 outside-operated wells currently being drilled and 13 outside-operated wells that are waiting on completion. Working interests in outside operated wells range from less than 1% to 13%.
The company has 2 rigs currently working in the play. A third rig will begin drilling on a 10-well pad within the next month. QEP currently estimates that the average completed well cost for a typical Bakken/Three Forks well (10,000' average lateral length) will range from $9.4 to $9.7 million in 2012. Slide 7 shows QEP's acreage and activity in the Bakken/Three Forks play.
Strong industry activity continues in the Woodford "Cana" Shale play
The company has completed and turned to sales 4 new QEP-operated Woodford "Cana" Shale wells in western Oklahoma since the last update. The company currently operates 25 producing wells and has working interests in an additional 197 producing Cana wells that are operated by others. During the fourth quarter of 2011, QEP net production from the play averaged approximately 49 MMcfed.
QEP has 2 operated wells currently drilling and 1 operated well waiting on completion and has interests in 6 wells currently being drilled and 12 wells waiting on completion that are operated by others. QEP plans to operate 2 to 3 rigs for the balance of 2012 in the liquids-rich gas portion of the core of the Cana play, with the majority of the activity focused on development drilling on 80-acre density. Slide 8 depicts QEP's acreage and additional details on the Cana play.
QEP commences development drilling in liquids-rich gas Mesaverde play in Uinta Basin
In the Uinta Basin of eastern Utah, QEP has commenced a two-rig vertical development drilling program targeting liquids-rich gas stacked sands in the Mesaverde Formation at average drill depths of 11,000 feet. The company has a 100% working interest in over 32,000 acres within the Red Wash Federal Unit, which it believes could be prospective for development of this emerging play.
At the end of 2011, the company had 20 producing wells in the play. QEP plans to drill at least 40 additional wells in the play in 2012. The company estimates gross completed well costs should average about $2.1 million with average gross per well estimated ultimate recoveries of 2.1 Bcfe. Slide 9 depicts QEP's acreage and additional details on the Mesaverde play.
Granite Wash, Tonkawa and Marmaton horizontal development in the Texas Panhandle and Western Oklahoma
In the Texas Panhandle Granite Wash play, the company has completed and turned to sales one additional QEP operated Cherokee horizontal well and one additional Caldwell zone horizontal well in Wheeler County, Texas since the last operations update. QEP has a 59% working interest in both newly completed wells. QEP has a working interest in a total of 61 producing horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle. During the fourth quarter of 2011, net production from this play (vertical and horizontal wells) averaged approximately 52 MMcfed. The company participated with a working interest in 5 outside-operated Granite Wash wells in the Texas Panhandle that were completed since the last operations update with working interests ranging from less than 1% to 23%. QEP is also participating in 6 outside-operated wells that are waiting on completion with working interests ranging from 2% to 19% and 4 outside-operated wells currently drilling with working interests ranging from 27% to 33%.
Excluding 7 wells completed in the Atoka formation which produces primarily gas, QEP participated in a total of 25 completed horizontal wells (both operated and non-operated) during 2011 in Wheeler County, Texas. The initial 30-day average rate for these 25 wells was approximately 1,460 Boepd.
In addition, since the last update QEP has drilled and completed 3 new Marmaton, 1 Tonkawa, and 1 Skinner horizontal oil wells in western Oklahoma and participated with a working interest in 8 outside operated wells in these plays with working interests ranging from 1% to 38%.
QEP participated in a total of 7 completed Marmaton horizontal wells (both operated and non-operated) during 2011 in western Oklahoma. The initial 30-day average rate for these wells was approximately 360 Boepd. QEP participated in a total of 27 completed Tonkawa horizontal wells (both operated and non-operated) during 2011 in western Oklahoma. The initial 30-day average rate for these wells was approximately 350 Boepd.
QEP currently has 2 rigs running in the combined Granite Wash/Marmaton/Tonkawa plays. See slide 10 for details on the Granite Wash play.
Reducing rig count in the Haynesville Shale of NW Louisiana
QEP has completed 11 additional company-operated Haynesville wells, since the last update, each with strong production rates and pressures. QEP drill times in the play averaged 32 days from spud to total depth in 2011, down from 37 days in 2010. QEP believes that improved drilling performance and completion efficiencies have allowed QEP to remain the lowest cost operator in its portion of the Haynesville play. QEP-operated gross completed well costs averaged $9.1 million in 2011 compared to $9.3 million in 2010. The company operates 108 producing wells in the play and has a working interest in 121 producing wells that are operated by others. During the fourth quarter of 2011, the company's Haynesville net production averaged approximately 239 MMcfd and Cotton Valley/Hosston net production averaged approximately 50 MMcfd. QEP net production from the Haynesville play continues to be impacted by the Company's decision to restrict the flowing rate of Haynesville wells to decrease near-wellbore pressure drawdown. The Company continues to restrict flow rates to minimize reservoir and propped fracture damage, which should lead to increased ultimate recoverable reserves.
QEP has 18 wells waiting on completion or being completed and currently has one operated rig working in the Haynesville play, down from a peak of 6 rigs in 2011. The Company also participated in 6 outside-operated Haynesville wells that were completed and turned to sales since the last operations update with working interests ranging from less than 1% to 12%. QEP has interests in 4 outside-operated Haynesville wells that are waiting on completion. Refer to slide 11 for additional information on QEP's Haynesville activities.
QEP Field Services Results
QEP Field Services (Field Services) Adjusted EBITDA increased 57% to $320.3 million compared to $203.9 million in 2010. During the fourth quarter of 2011, Adjusted EBITDA increased 66% to $87.2 million from the 2010 fourth quarter. Adjusted EBITDA increased for the year and quarter ended December 31, 2011, due to higher gathering and processing margins.
-- Gathering margin (total gathering revenues less gathering related
operating expenses) increased 22%, or $33.4 million, compared to 2010,
driven primarily by increased other gathering revenue related to a
third-party processing arrangement for certain gas volumes in the
Northern Region and a 6% increase in revenues from gathering fees.
During the fourth quarter of 2011, gathering margin increased 4%, or
$1.4 million compared to 2010. Total system throughput volume at end of
the year averaged 1.4 million MMBtu per day.
-- Processing margin (total processing plant revenues less plant operating
expenses and shrinkage) increased 93%, or $79.7 million compared to
2010, driven primarily by keep-whole processing margins that were 95%
higher and revenue from processing fees which were 53% higher. The
increased keep-whole processing margin was primarily the result of a 34%
increase in NGL prices and a 42% increase in NGL volumes. Processing
margin in the fourth quarter of 2011 increased 129%, or $30.2 million,
compared to the 2010 fourth quarter, driven primarily by keep-whole
processing margins that were 130% higher. The increased keep-whole
processing margin was primarily the result of a 31% increase in NGL
prices and a 90% increase in NGL volumes.
-- Approximately 70% of Field Services' 2011 net operating revenue was
derived from fee-based gathering and processing activities compared to
78% in 2010. During the fourth quarter of 2011, approximately 62% of
Field Services' net operating revenue was derived from fee-based
gathering and processing activities compared to 77% in the 2010 period.
-- Field Services gathering volumes totaled 495.4 million MMBtu in 2011
compared to 475.7 million MMBtu in 2010. For the fourth quarter of
2011, gathering volumes were 128.4 million MMBtu compared to 121.2
million MMBtu in the 2010 fourth quarter.
-- Fee-based processing revenues increased 53% compared to 2010, due to a
6% increase in fee-based processing volumes to 240.7 million MMBtu and a
38% increase in the average processing fee rate to $0.22 per MMBtu.
During the fourth quarter of 2011, fee-based processing revenues
increased 79%, due to a 3% increase in fee-based processing volumes and
an 80% increase in the average processing fee rate to $0.27 per MMBtu.
-- NGL sales volumes totaled 141.8 million gallons in 2011 compared to
100.2 million gallons in 2010, a 42% increase. NGL sales volumes
totaled 43.6 million gallons during the 2011 fourth quarter, a 90%
increased over the 2010 fourth quarter.
-- Field Services put into service two new major processing plant
facilities during 2011. The 150 MMcfd Iron Horse cryogenic gas
processing plant in eastern Utah was commissioned in January 2011 and
the 420 MMcfd Blacks Forks II cryogenic gas processing plant in
southwest Wyoming was commissioned in July 2011. Both of these
processing plants were major drivers in Field Services increased
operating results during 2011. Field Services owns and operates
processing plants in the Northern (Rocky Mountain) Region with an
aggregate processing capacity of 1.37 Bcfd of natural gas.
Fourth Quarter 2011 Results Conference Call
QEP Resources management will discuss full year and fourth quarter 2011 results in a conference call on Thursday, February 23, beginning at 11:00 a.m. ET. The call can be accessed at www.qepres.com. A replay of the teleconference will be available on the website and from February 23rd to March 8th by dialing (855) 859-2056 in the U.S. or Canada and (404) 537-3406 for international calls, and then entering passcode 44233321. In addition, QEP's Fourth Quarter Operations Update Slides, with updated maps showing QEP's leasehold and current activity for key operating areas discussed in this release, can be found on the company's website.
About QEP Resources
QEP Resources, Inc. (NYSE:QEP) is a leading independent natural gas and oil exploration and production company with operations focused in the Rocky Mountain and Midcontinent of the United States. QEP Resources also gathers, compresses, treats, processes and stores natural gas.
Forward-Looking Statements
This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as "anticipates", "believes", "forecasts", "plans", "estimates", "expects", "should", "will", or other similar expressions. Such statements are based on management's current expectations, estimates and projections, which are subject to a wide range of uncertainties and business risks. These forward-looking statements include statements regarding: forecasted Adjusted EBITDA, production and capital investment for 2012 and related assumptions for such guidance; number of rigs planned in operating areas; changes in lease operating expenses; the effects of restricting the flowing rate in the Haynesville Shale; estimated gross completed well costs and average estimated ultimate recoveries per well; QEP being the lowest cost operator in its portion of the Haynesville play; and anticipated growth from new projects of QEP Field Services. The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The SEC permits optional disclosure of probable and possible reserves, however QEP has made no such disclosures in our filings with the SEC. QEP uses certain terms in our periodic news releases and other presentation materials such as "estimated ultimate recovery" (or "EUR"), "resource potential", and "net resource potential". These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially more risks of actually being realized. The SEC guidelines strictly prohibit us from including such estimates in filings with the SEC. Investors are urged to closely consider the disclosures and risk factors in our most recent annual report on Form 10-K and in other reports on file with the SEC. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: the availability of capital; changes in local, regional, national and global demand for natural gas, oil and NGL; natural gas, NGL and oil prices; potential legislative or regulatory changes regarding the use of hydraulic fracture stimulation; impact of new laws and regulations, including the implementation of the Dodd-Frank Act; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; weather conditions; changes in maintenance and construction costs and possible inflationary pressures; the availability and cost of credit; and the other risks discussed in the Company's periodic filings with the Securities and Exchange Commission, including the Risk Factors section of the Company's Annual Report on Form 10-K for the year ended December 31, 2011.
QEP Resources undertakes no obligation to publicly correct or update the forward-looking statements in this news release, in other documents, or on the Web site to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
For more information, visit QEP Resources' website at: www.qepres.com.
The following table presents full year derivative positions as of February 16, 2012:
QEP Energy Hedge Positions - February 16, 2012
Swaps Collars
----- -------
Year Type of Index Total Average Floor Ceiling
price
---- Contract ----- ----- per price price
-------- unit ----- -----
----
(in
millions)
Natural gas sales (MMbtu)
2012 Swap IFCNPTE 2.8 $2.85
2012 Swap IFNPCR 76.9 4.97
2012 Swap IFPEPL 7.3 4.70
2012 Swap NYMEX 75.7 4.75
2013 Swap IFNPCR 65.7 5.66
2013 Swap NYMEX 29.2 3.68
Oil sales (Bbls)
2012 Swap NYMEX WTI 1.8 $97.03
2012 Collar NYMEX WTI 1.3 $87.39 $115.37
2013 Swap NYMEX WTI 0.2 105.80
Ethane sales (Gals)
Mt. Belvieu
2012 Swap Ethane 15.4 $0.64
Propane sales (Gals)
Mt. Belvieu
2012 Swap Propane 21.8 $1.28
QEP Field Services Hedge Positions
-February 16, 2012
Year Type of Index Total Average
Swap
---- Contract ----- ----- price
-------- per unit
--------
(in
millions)
Ethane sales (Gals)
Mt. Belvieu
2012 Swap Ethane 15.4 $0.64
Propane sales (Gals)
Mt. Belvieu
2012 Swap Propane 15.4 $1.36
QEP Marketing Hedge Positions -
February 16, 2012
Year Type of Index Total Average
Swap
---- Contract ----- ----- price
-------- per unit
--------
(in
millions)
Natural gas sales (MMbtu)
2012 Swaps IFNPCR 3.3 $4.41
2013 Swaps IFNPCR 0.9 4.77
Natural gas purchases (MMbtu)
2012 Swaps IFNPCR 0.3 $3.54
QEP RESOURCES, INC.
CONSOLIDATED
STATEMENTS OF
INCOME
(Unaudited)
Three Months Twelve Months
Ended Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
(in millions, except per share
amounts)
REVENUES (1)
Natural gas sales $318.0 $311.9 $1,239.1 $1,205.3
Oil sales 103.6 56.6 324.2 198.1
NGL sales 58.6 17.4 129.7 47.9
Gathering,
processing and
other 98.4 64.4 380.9 251.3
Purchased gas and
oil sales 274.7 137.6 1,085.3 598.0
Total Revenues 853.3 587.9 3,159.2 2,300.6
----- ----- ------- -------
OPERATING EXPENSES
Purchased gas and
oil expense 273.8 133.9 1,077.1 589.3
Lease operating
expense 41.1 35.3 145.2 125.0
Natural gas, oil and
NGL transportation
and other handling
costs (1) 29.0 15.9 102.2 54.2
Gathering,
processing and
other 27.9 20.6 107.3 83.2
General and
administrative 34.1 31.6 123.2 107.2
Separation costs - (0.7) - 13.5
Production and
property taxes 26.9 20.9 105.4 82.5
Depreciation,
depletion and
amortization 199.0 173.9 765.4 643.4
Exploration expenses 3.0 13.8 10.5 23.0
Abandonment and
impairment 202.0 17.0 218.4 46.1
Total Operating
Expenses 836.8 462.2 2,654.7 1,767.4
Net gain from asset
sales - (0.2) 1.4 12.1
--- ---- --- ----
OPERATING INCOME 16.5 125.5 505.9 545.3
Interest and other
income (loss) 4.6 (2.1) 4.1 2.3
Income from
unconsolidated
affiliates 1.0 0.5 5.5 3.0
Loss from early
extinguishment of
debt - - (0.7) (13.3)
Interest expense (23.0) (21.6) (90.0) (84.4)
----- ----- ----- -----
INCOME (LOSS) FROM
CONTINUING
OPERATIONS (0.9) 102.3 424.8 452.9
BEFORE INCOME TAXES
Income taxes 1.6 (36.5) (154.4) (167.0)
INCOME FROM
CONTINUING
OPERATIONS 0.7 65.8 270.4 285.9
Discontinued
operations, net of
income tax - - - 43.2
NET INCOME 0.7 65.8 270.4 329.1
Net income
attributable to
noncontrolling
interest (1.0) (0.8) (3.2) (2.9)
NET INCOME (LOSS)
ATTRIBUTABLE TO QEP $(0.3) $65.0 $267.2 $326.2
===== ===== ====== ======
Earnings (Loss) Per
Common Share
Attributable to QEP
Basic from
continuing
operations $(0.01) $0.37 $1.51 $1.61
Basic from
discontinued
operations - - - 0.25
Basic total $(0.01) $0.37 $1.51 $1.86
====== ===== ===== =====
Diluted from
continuing
operations $- $0.37 $1.50 $1.60
Diluted from
discontinued
operations - - - 0.24
Diluted total $- $0.37 $1.50 $1.84
=== ===== ===== =====
Weighted-average
common shares
outstanding
Used in basic
calculation 176.7 175.7 176.5 175.3
Used in diluted
calculation 178.2 177.4 178.4 177.3
(1) During the year ended December 31, 2011, QEP revised its reporting of transportation and handling costs. Transportation and handling costs have been recast on the Consolidated Income Statement from revenues to "Natural gas, oil and NGL transportation and other handling costs" for all periods presented.
QEP RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
December 31,
------------
2011 2010
---- ----
(in millions)
ASSETS
Current Assets
Cash and cash equivalents $- $-
Accounts receivable, net 397.4 269.9
Fair value of derivative contracts 273.7 257.3
Inventories, at lower of average cost or
market
Gas, oil and NGL 16.2 16.4
Materials and supplies 87.6 65.4
Prepaid expenses and other 43.7 45.2
Total Current Assets 818.6 654.2
----- -----
Property, Plant and Equipment (successful
efforts method for gas and oil properties)
Proved properties 8,172.4 6,874.3
Unproved properties, not being depleted 326.8 322.0
Midstream field services 1,463.6 1,360.5
Marketing and other 49.8 44.5
Total Property, Plant and Equipment 10,012.6 8,601.3
-------- -------
Less Accumulated Depreciation, Depletion and
Amortization
Exploration and production 3,339.2 2,454.4
Midstream field services 297.5 244.6
Marketing and other 14.6 12.3
Total Accumulated Depreciation, Depletion and
Amortization 3,651.3 2,711.3
------- -------
Net Property, Plant and Equipment 6,361.3 5,890.0
------- -------
Investment in unconsolidated affiliates 42.2 44.5
Other Assets
Goodwill 59.5 59.6
Fair value of derivative contracts 123.5 120.8
Other noncurrent assets 37.6 16.2
Total Other Assets 220.6 196.6
----- -----
TOTAL ASSETS $7,442.7 $6,785.3
======== ========
December 31,
------------
2011 2010
---- ----
(in millions)
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances $29.4 $19.5
Accounts payable and accrued expenses 457.3 332.2
Production and property taxes 40.0 18.9
Interest payable 24.4 28.1
Fair value of derivative contracts 1.3 139.3
Deferred income taxes 85.4 27.8
Current portion of long-term debt - 58.5
--- ----
Total Current Liabilities 637.8 624.3
----- -----
Long-term debt, less current portion 1,679.4 1,472.3
Deferred income taxes 1,484.7 1,377.7
Asset retirement obligations 163.9 148.3
Fair value of derivative contracts - 0.3
Other long-term liabilities 124.8 99.3
Commitments and contingencies
EQUITY
Common stock -par value $0.01 per share;
500.0 million shares authorized; 1.8 1.8
177.2 million and 176.0 million shares issued
at December 31, 2011 and
2010, respectively
Treasury stock -0.4 million and 0.1 million
shares at December 31, 2011 (13.1) (3.8)
and 2010, respectively
Additional paid-in capital 431.4 398.0
Retained earnings 2,673.5 2,420.0
Accumulated other comprehensive income 207.9 194.3
Total Common Shareholders' Equity 3,301.5 3,010.3
Noncontrolling interest 50.6 52.8
Total Equity 3,352.1 3,063.1
TOTAL LIABILITIES AND EQUITY $7,442.7 $6,785.3
======== ========
QEP RESOURCES, INC.
CONSOLIDATED CASH FLOWS
(Unaudited)
Year Ended
December 31,
-------------
2011 2010
---- ----
(in millions)
OPERATING ACTIVITIES
Net income $270.4 $329.1
Discontinued operations, net of income tax - (43.2)
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization 765.4 643.4
Deferred income taxes 156.8 188.2
Abandonment and impairment 218.4 46.1
Share-based compensation 22.0 16.1
Amortization of debt issuance costs and
discounts 4.1 2.4
Dry exploratory well expense 0.3 9.6
Net gain from asset sales (1.4) (12.1)
Income from unconsolidated affiliates (5.5) (3.0)
Distributions from unconsolidated
affiliates and other 7.8 2.2
Loss on early extinguishment of debt 0.7 13.3
Unrealized gain on basis-only swaps (117.7) (121.7)
Changes in operating assets and
liabilities
Accounts receivable (144.6) (32.6)
Inventories (22.0) 10.1
Prepaid expenses 1.6 (16.2)
Accounts payable and accrued expenses 127.8 4.2
Federal income taxes 17.0 (30.9)
Other (8.5) (7.5)
Net Cash Provided by Operating Activities
of Continuing Operations 1,292.6 997.5
------- -----
INVESTING ACTIVITIES
Property acquisitions (48.0) (109.3)
Property, plant and equipment, including
dry exploratory well expense (1,383.1) (1,359.7)
Proceeds from disposition of assets 8.2 25.6
Change in notes receivable - 52.9
Net Cash Used in Investing Activities of
Continuing Operations (1,422.9) (1,390.5)
-------- --------
FINANCING ACTIVITIES
Checks outstanding in excess of cash
balances 9.9 19.5
Long-term debt issued 591.5 1,034.4
Long-term debt issuance costs paid (10.6) (16.6)
Current portion long-term debt repaid (58.5) (91.5)
Repayments of notes payable - (39.3)
Long-term debt repaid (385.0) (761.5)
Long-term debt extinguishment costs - (4.9)
Other capital contributions 2.3 2.8
Equity contribution - 250.0
Dividends paid (14.1) (7.0)
Distribution from Questar 0.2 (7.2)
Distribution to noncontrolling interest (5.4) (5.0)
Net Cash Provided by Financing Activities
of Continuing Operations 130.3 373.7
----- -----
CASH PROVIDED BY (USED IN) CONTINUING
OPERATIONS - (19.3)
--- -----
Cash provided by operating activities of
discontinued operations - 68.6
Cash used in investing activities of
discontinued operations - (39.9)
Cash used in financing activities of
discontinued operations - (26.9)
Effect of change in cash and cash
equivalents of discontinued operations - (1.8)
Change in cash and cash equivalents - (19.3)
Beginning cash and cash equivalents - 19.3
Ending cash and cash equivalents $- $-
=== ===
Supplemental Disclosure of Cash Paid
(Received) During the Year for:
Interest $93.5 $83.3
Income taxes (28.5) 14.0
QEP RESOURCES, INC.
OPERATIONS BY LINE
OF BUSINESS
(Unaudited)
Three Months
Ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
(in millions)
Revenues from
Unaffiliated
customers (1)
QEP Energy $625.9 $387.2 $2,213.2 $1,456.3
QEP Field Services 95.4 63.3 369.3 245.5
QEP Marketing and
other 132.0 137.4 576.7 598.8
Total $853.3 $587.9 $3,159.2 $2,300.6
====== ====== ======== ========
Operating income
(loss)
QEP Energy $(56.7) $82.8 $240.4 $399.8
QEP Field Services 71.2 38.7 259.2 150.6
QEP Marketing and
other 2.0 3.3 6.3 8.4
Separation costs - 0.7 - (13.5)
Total $16.5 $125.5 $505.9 $545.3
===== ====== ====== ======
Net income (loss)
from continuing
operations
attributable to QEP
QEP Energy $(43.5) $38.9 $104.7 $203.9
QEP Field Services 40.3 22.6 154.5 91.1
QEP Marketing and
other 2.9 3.1 8.4 6.7
Separation and debt
extinguishment
costs - 0.4 (0.4) (18.7)
Total $(0.3) $65.0 $267.2 $283.0
===== ===== ====== ======
(1) During the year ended December 31, 2011, QEP revised its reporting of transportation and handling costs. Transportation and handling costs have been recast on the Consolidated Income Statement from revenues to "Natural gas, oil and NGL transportation and other handling costs" for all periods presented.
Three Months
Ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
QEP Energy production
volumes
Natural gas (Bcf) 60.5 54.6 236.4 203.8
Oil (Mbbl) 1,182.1 830.3 3,741.3 2,979.8
NGL (Mbbl) 1,040.6 438.9 2,715.6 1,225.8
Total production (Bcfe) 73.9 62.1 275.2 229.0
Average daily
production (MMcfe) 803.3 675.4 753.9 627.4
QEP Energy average net
realized price
Natural gas (per Mcf) $4.74 $5.14 $4.74 $5.32
Oil (per bbl) 87.56 68.30 86.63 66.48
NGL (per bbl) 56.34 39.30 47.76 39.04
Production by major
area
-------------------
QEP Energy -Natural
gas (Bcf)
Haynesville/Cotton
Valley 26.5 22.2 107.1 79.3
Midcontinent 8.6 7.9 32.9 30.8
Pinedale Anticline 19.1 17.6 69.3 65.1
Uinta Basin 3.1 3.7 14.9 14.9
Rockies Legacy 3.2 3.2 12.2 13.7
Total production 60.5 54.6 236.4 203.8
QEP Energy - Oil (Mbbl)
Haynesville/Cotton
Valley 14.8 16.6 51.0 78.4
Midcontinent 295.2 168.0 835.3 644.3
Pinedale Anticline 164.8 149.9 583.8 551.8
Uinta Basin 209.4 250.6 866.7 957.1
Rockies Legacy 497.9 245.2 1,404.5 748.2
Total production 1,182.1 830.3 3,741.3 2,979.8
===== === ===== =====
Three Months
Ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
QEP Energy - NGL (Mbbl)
Haynesville/Cotton
Valley 2.2 2.4 8.4 5.5
Midcontinent 364.3 377.4 1,371.2 997.0
Pinedale Anticline 610.6 1,099.6
Uinta Basin 23.3 32.2 106.4 121.5
Rockies Legacy 40.2 26.9 130.0 101.8
Total production 1,040.6 438.9 2,715.6 1,225.8
===== === ===== =====
QEP Energy -Total
Production (Bcfe)
Haynesville/Cotton
Valley 26.6 22.4 107.5 79.8
Midcontinent 12.7 10.9 46.2 40.6
Pinedale Anticline 23.8 18.6 79.4 68.5
Uinta Basin 4.6 5.5 20.8 21.4
Rockies Legacy 6.2 4.7 21.3 18.7
Total production 73.9 62.1 275.2 229.0
QEP Field Services
Operating Statistics
---------------------
Natural gas gathering
volumes (millions of
MMBtu)
For unaffiliated
customers 67.8 66.8 261.2 276.8
For affiliated
customers 60.6 54.4 234.2 198.9
Total gathering 128.4 121.2 495.4 475.7
===
Gathering revenue (per
MMBtu) $0.32 $0.32 $0.33 $0.32
QEP Field Services
Gathering Margin
Gathering $41.1 $39.2 $161.1 $152.5
Other Gathering 9.3 11.0 68.5 36.7
Gathering (expense) (9.3) (10.5) (44.6) (37.6)
Gathering Margin $41.1 $39.7 $185.0 $151.6
===== ===== ====== ======
QEP Field Services
Processing Margin
NGL sales $60.1 $24.2 $180.0 $94.8
Processing (fee-based)
revenues 16.1 9.0 53.7 35.2
Other processing fees 0.5 - 2.2 -
Processing (expense) (3.3) (3.1) (12.2) (11.9)
Processing plant fuel
and shrinkage
(expense) (15.1) (6.7) (49.2) (32.6)
Natural gas, oil and
NGL transportation and
other handling costs (4.7) - (9.3) -
Processing margin $53.6 $23.4 $165.2 $85.5
===== ===== ====== =====
Frac spread (NGL sales
less processing plant
fuel and shrinkage
less natural gas, oil
and $40.3 $17.5 $121.5 $62.2
NGL transportation and
other handling
costs)
Operating Statistics
Natural gas processing
volumes
NGL sales (MMgal) 43.6 22.9 141.8 100.2
Average NGL sales price
(per gal) $1.38 $1.05 $1.27 $0.95
Fee-based processing
volumes (in millions
of MMBtu)
For unaffiliated
customers 26.5 28.9 122.9 116.8
For affiliated
customers 33.1 28.9 117.8 109.4
Total fee-based
processing volumes 59.6 57.8 240.7 226.2
==== ==== ===== =====
Average fee-based
processing revenue $0.27 $0.15 $0.22 $0.16
(per MMBtu)
QEP RESOURCES, INC.
NON-GAAP MEASURES
(Unaudited)
This release contains reference to a non-GAAP
measure of earnings per diluted share from
continuing operations excluding gains and
losses from asset sales, asset impairments,
unrealized gains and losses on basis-only
swaps, separation costs and loss on early
extinguishment of debt. Management believes
earnings per diluted share excluding asset
sales, asset impairments, unrealized basis-
only swaps, separation costs and loss on
early extinguishment of debt is an important
measure of the Company's operational
performance relative to other gas and oil
producing companies.
The following table calculates earnings per
diluted share excluding gains and losses on
assets sales, unrealized gains and losses on
basis-only swaps, separation costs and loss
on early extinguishment of debt:
Three Months
Ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
(in millions, except earnings
per share)
Net income
(loss)
attributable to
QEP Resources $(0.3) $65.0 $267.2 $326.2
Less:
Discontinued
operations - - - (43.2)
--- --- --- -----
Net income
(loss) from
continuing
operations
attributable to
QEP Resources (0.3) 65.0 267.2 283.0
Exclusion of net
(gain) loss from
assets sales,
unrealized (gain)
loss on basis-only
swaps, separation
costs and loss on
early extinguishment
of debt from net
income
Net (gain) loss
from asset
sales - 0.2 (1.4) (12.1)
Income taxes on
net (gain) loss
on asset sales - (0.1) 0.5 4.5
Non-cash price-
related
impairment
charge 195.2 - 195.2 -
Income taxes on
non-cash
price-related
impairment
charge (70.5) - (70.5) -
Unrealized
(gain) loss on
basis-only
swaps (31.0) (31.7) (117.7) (121.7)
Income taxes on
unrealized
(gain) loss on
basis-only
swaps 11.2 11.8 42.5 45.4
Separation costs - (0.7) - 13.5
Income taxes on
separation
costs - 0.3 - (3.0)
Loss from early
extinguishment
of debt - - 0.7 13.3
Income taxes on
loss from early
extinguishment
of debt - - (0.3) (5.1)
After-tax
(gain) loss
from assets
sales,
unrealized
(gain) loss on
basis swap,
separation
costs and loss
on early
extinguishment
of debt 104.9 (20.2) 49.0 (65.2)
----- ----- ---- -----
Net income
(loss)
attributable to
QEP Resources
excluding
(gain) loss
from assets
sales,
unrealized
(gain) loss on
basis swap,
separation
costs and loss
on early
extinguishment
of debt $104.6 $44.8 $316.2 $217.8
====== ===== ====== ======
EARNINGS PER COMMON SHARE FROM CONTINUING
OPERATIONS ATTRIBUTABLE TO QEP RESOURCES
Diluted $- $0.37 $1.50 $1.60
Diluted after-
tax (gain) loss
from asset
sales,
unrealized
(gain) loss on
basis-only
swaps,
separation
costs and loss
on early
extinguishment
of debt 0.58 (0.12) 0.27 (0.37)
---- ----- ---- -----
Earnings (loss)
per diluted
share from
continuing
operations
attributable to
QEP Resources
excluding asset
sales,
unrealized
(gain) loss on
basis only
swaps,
separation
costs and loss
on early
extinguishment
of debt $0.58 $0.25 $1.77 $1.23
===== ===== ===== =====
Weighted-Average
Common Shares
Outstanding
Diluted 178.2 177.4 178.4 177.3
This release also contains reference to a non-GAAP measure of Adjusted EBITDA. Management defines Adjusted EBITDA as net income before the following items: discontinued operations, unrealized gains and losses on basis-only swaps, gains and losses from asset sales, interest and other income, income taxes, interest expense, separation costs, loss on early extinguishment of debt, depreciation, depletion, and amortization, abandonment and impairment, and exploration expense. Management uses Adjusted EBITDA to assess the Company's operating results. Management believes Adjusted EBITDA is an important measure of the Company's cash flow and liquidity, its ability to incur and service debt, fund capital expenditures and make distributions to shareholders and is an important measure for comparing the Company's financial performance to other gas and oil producing companies. In addition, Adjusted EBITDA is a part of the Company's debt covenants as defined in its revolving credit agreement.
The following table
reconciles QEP Resources'
net income to Adjusted
EBITDA:
Three Months
Ended Year Ended
December 31, December 31,
------------ ------------
2011 2010 2011 2010
---- ---- ---- ----
(in millions)
Net income
(loss)
attributable to
QEP Resources $(0.3) $65.0 $267.2 $326.2
Net income
attributable to
noncontrolling
interest 1.0 0.8 3.2 2.9
--- --- --- ---
Net income 0.7 65.8 270.4 329.1
Discontinued
operations, net
of tax - - - (43.2)
--- --- --- -----
Income from
continuing
operations 0.7 65.8 270.4 285.9
Unrealized
(gain) loss on
basis-only
swaps (31.0) (31.7) (117.7) (121.7)
Net (gain) loss
from asset
sales - 0.2 (1.4) (12.1)
Interest and
other income (4.6) 2.1 (4.1) (2.3)
Income taxes (1.6) 36.5 154.4 167.0
Interest expense 23.0 21.6 90.0 84.4
Separation costs - (0.7) - 13.5
Loss on early
extinguishment
of debt - - 0.7 13.3
Depreciation,
depletion and
amortization 199.0 173.9 765.4 643.4
Abandonment and
impairment 202.0 17.0 218.4 46.1
Exploration 3.0 13.8 10.5 23.0
EBITDA $390.5 $298.5 $1,386.6 $1,140.5
====== ====== ======== ========
SOURCE QEP Resources, Inc.
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