STATE OF DELAWARE
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001-34778
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87-0287750
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(State or other jurisdiction of incorporation)
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(Commission File No.)
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(I.R.S. Employer Identification No.)
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o
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Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
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o
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Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
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o
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Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
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o
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Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
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Item 2.02
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Results of Operations and Financial Condition
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Item 9.01
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Financial Statements and Exhibits.
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(d)
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Exhibits.
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Exhibit No. | Exhibit |
99.1 | Press release issued February 22, 2012, by QEP Resources, Inc. |
QEP Resources, Inc.
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||
(Registrant) | ||
February 23, 2012
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||
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/s/Richard J. Doleshek | |
Richard J. Doleshek | ||
Executive Vice President and Chief Financial Officer |
Exhibit No | Exhibit |
99.1 | Press release issued February 22, 2012, by QEP Resources, Inc. |
News Release | ||
QEP Resources, Inc. | ||
1050 17th Street, Suite 500 | ||
Denver, CO 80265 |
Three Months Ended
December 31,
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Year Ended
December 31,
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|||||||||||||||||||||||
2011
|
2010
|
Change
|
2011
|
2010
|
Change
|
|||||||||||||||||||
(in millions)
|
||||||||||||||||||||||||
QEP Energy
|
$ | 300.5 | $ | 242.4 | 24 | % | $ | 1,057.5 | $ | 926.2 | 14 | % | ||||||||||||
QEP Field Services
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87.2 | 52.4 | 66 | % | 320.3 | 203.9 | 57 | % | ||||||||||||||||
QEP Marketing and other
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2.8 | 3.7 | -24 | % | 8.8 | 10.4 | -15 | % | ||||||||||||||||
Total Adjusted EBITDA (1)
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$ | 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.
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Three months ended
December 31,
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Year Ended
December 31,
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|||||||||||||||||||||||
2011
|
2010
|
Change
|
2011
|
2010
|
Change
|
|||||||||||||||||||
(in millions, except per share amounts)
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||||||||||||||||||||||||
QEP Energy (1)
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$ | (43.5 | ) | $ | 38.9 | -212 | % | $ | 104.7 | $ | 203.9 | -49 | % | |||||||||||
QEP Field Services (2)
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40.3 | 22.6 | 78 | % | 154.5 | 91.1 | 70 | % | ||||||||||||||||
QEP Marketing and other
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2.9 | 3.1 | -6 | % | 8.4 | 6.7 | 25 | % | ||||||||||||||||
QEP Resources
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- | 0.4 | -100 | % | (0.4 | ) | (18.7 | ) | -98 | % | ||||||||||||||
Income from continuing operations (2)
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(0.3 | ) | 65.0 | -100 | % | 267.2 | 283.0 | -6 | % | |||||||||||||||
Discontinued operations (3)
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- | - | - | - | 43.2 | -100 | % | |||||||||||||||||
NET INCOME (2)
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$ | (0.3 | ) | $ | 65.0 | -100 | % | $ | 267.2 | $ | 326.2 | -18 | % | |||||||||||
Earnings per diluted share
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||||||||||||||||||||||||
From continuing operations
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$ | - | $ | 0.37 | $ | 1.50 | $ | 1.60 | ||||||||||||||||
Total earnings
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$ | - | $ | 0.37 | $ | 1.50 | $ | 1.84 | ||||||||||||||||
Weighted-average diluted shares
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178.2 | 177.4 | 178.4 | 177.3 |
(1)
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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.
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(2)
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Net income represents amounts attributable to QEP Resources after deducting non-controlling interest.
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(3)
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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.
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●
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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.
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●
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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.
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●
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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).
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●
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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.
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●
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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).
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●
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Net realized NGL prices at QEP Energy averaged $47.76 per barrel, up 22% compared to the 2010.
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●
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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.
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●
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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.
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●
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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.
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●
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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.
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●
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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.
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●
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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.
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●
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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.
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●
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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 $31.7 million related to properties in the Southern Region.
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2012
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||||||||
Current Forecast
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Previous Forecast
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|||||||
QEP Resources Adjusted EBITDA (millions)
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$ | 1,350 - $1,450 | $ | 1,450 - $1,550 | ||||
QEP Energy capital investment (millions)
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$ | 1,130 - $1,280 | $ | 1,330 | ||||
QEP Field Services capital investment (millions)
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$ | 170 | $ | 170 | ||||
QEP Marketing and other capital investment (millions)
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- | - | ||||||
Total QEP Resources capital investment (millions)
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$ | 1,300 - $1,450 | $ | 1,500 | ||||
QEP Energy production - Bcfe
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305 - 310 | 305 - 310 | ||||||
NYMEX gas price per MMBtu (1)
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$ | 2.00 - $3.00 | $ | 3.75 - $4.25 | ||||
NYMEX crude oil price per bbl (1)
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$ | 90.00 - $100.00 | $ | 90.00 - $100.00 | ||||
NYMEX/Rockies basis differential per MMBtu (1)
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$ | 0.20 - $0.15 | $ | 0.20 - $0.15 | ||||
NYMEX/Midcontinent basis differential per MMBtu (1)
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$ | 0.20 - $0.15 | $ | 0.20 - $0.15 |
(1)
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For remaining 2012 un-hedged volumes.
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Three months ended
December 31,
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Year Ended
December 31,
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|||||||||||||||||||||||
2011
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2010
|
Change
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2011
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2010
|
Change
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|||||||||||||||||||
(in Bcfe)
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Southern Region
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Haynesville/Cotton Valley
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26.6 | 22.4 | 19 | % | 107.5 | 79.8 | 35 | % | ||||||||||||||||
Midcontinent
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12.7 | 10.9 | 17 | % | 46.2 | 40.6 | 14 | % | ||||||||||||||||
Total Southern Region
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39.3 | 33.3 | 18 | % | 153.7 | 120.4 | 28 | % | ||||||||||||||||
Northern Region
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Pinedale Anticline
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23.8 | 18.6 | 28 | % | 79.4 | 68.5 | 16 | % | ||||||||||||||||
Uinta Basin (1)
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4.6 | 5.5 | -16 | % | 20.8 | 21.4 | -3 | % | ||||||||||||||||
Rockies Legacy
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6.2 | 4.7 | 32 | % | 21.3 | 18.7 | 14 | % | ||||||||||||||||
Total Northern Region
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34.6 | 28.8 | 20 | % | 121.5 | 108.6 | 12 | % | ||||||||||||||||
Total production
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73.9 | 62.1 | 19 | % | 275.2 | 229.0 | 20 | % |
(1)
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Includes 1.6 Bcfe in Q1 2011 from prior periods due to a change in ownership interest in a federal unit.
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Three months ended
December 31,
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Year Ended
December 31,
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2011
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2010
|
Change
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2011
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2010
|
Change
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|||||||||||||||||||
Natural gas price ($ per Mcf)
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||||||||||||||||||||||||
Average field-level natural gas price
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$ | 3.66 | $ | 3.65 | 0 | % | $ | 3.95 | $ | 4.18 | -6 | % | ||||||||||||
Natural gas hedging impact (2)
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1.59 | 2.07 | -23 | % | 1.29 | 1.74 | -26 | % | ||||||||||||||||
Average revenue
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5.25 | 5.72 | -8 | % | 5.24 | 5.92 | -11 | % | ||||||||||||||||
Realized losses on basis-only swaps (3)
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(0.51 | ) | (0.58 | ) | -12 | % | (0.50 | ) | (0.60 | ) | -17 | % | ||||||||||||
Net realized natural gas price
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$ | 4.74 | $ | 5.14 | -8 | % | $ | 4.74 | $ | 5.32 | -11 | % | ||||||||||||
Oil price ($ per bbl)
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||||||||||||||||||||||||
Average field-level oil price
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$ | 87.01 | $ | 72.50 | 20 | % | $ | 86.20 | $ | 69.39 | 24 | % | ||||||||||||
Oil hedging impact (2)
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0.55 | (4.20 | ) | -113 | % | 0.43 | (2.91 | ) | -115 | % | ||||||||||||||
Net realized oil price
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$ | 87.56 | $ | 68.30 | 28 | % | $ | 86.63 | $ | 66.48 | 30 | % | ||||||||||||
NGL price ($ per bbl)
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||||||||||||||||||||||||
Average field-level NGL price
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$ | 56.34 | $ | 39.30 | 43 | % | $ | 47.76 | $ | 39.04 | 22 | % |
(1)
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Recast to reflect exclusion of natural gas, oil and NGL transportation and other handling costs.
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(2)
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Reported in revenues in the consolidated income statement.
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(3)
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Reported below operating income in the consolidated income statement.
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Three months ended
December 31,
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Year Ended
December 31,
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|||||||||||||||||||||||
2011
|
2010
|
Change
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2011
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2010
|
Change
|
|||||||||||||||||||
(per Mcfe)
|
||||||||||||||||||||||||
Depreciation, depletion and amortization
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$ | 2.48 | $ | 2.58 | -4 | % | $ | 2.57 | $ | 2.59 | -1 | % | ||||||||||||
Lease operating expense
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0.57 | 0.58 | -2 | % | 0.54 | 0.56 | -4 | % | ||||||||||||||||
Natural gas, oil and NGL transportation and other handling costs
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0.75 | 0.57 | 32 | % | 0.68 | 0.55 | 24 | % | ||||||||||||||||
General and administrative expense
|
0.39 | 0.36 | 8 | % | 0.36 | 0.34 | 6 | % | ||||||||||||||||
Allocated interest expense
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0.29 | 0.31 | -6 | % | 0.30 | 0.34 | -12 | % | ||||||||||||||||
Production taxes
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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.
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●
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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.
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●
|
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.
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●
|
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.
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Natural Gas
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Oil
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NGL
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Natural Gas
Equivalents
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|||||||||||||
(Bcf)
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(Mbbl)
|
(Mbbl)
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(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
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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
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(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 |
Total
(in Bcfe)
|
% of total
|
PUD %
|
% liquids
|
|||||||||||||
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 | % | |||||||||
Legacy
|
387.6 | 11 | % | 50 | % | 68 | % | |||||||||
Total QEP Energy
|
3,613.8 | 100 | % | 46 | % | 24 | % |
Total
(in Bcfe)
|
% of total
|
PUD %
|
% liquids
|
|||||||||||||
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 | % | ||||||||||
Legacy
|
298.5 | 10 | % | 47 | % | 57 | % | |||||||||
Total QEP Energy
|
3,030.7 | 100 | % | 47 | % | 14 | % |
●
|
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.
|
●
|
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.
|
Swaps | Collars | |||||||||||||||||||
Year
|
Type of
Contract
|
Index
|
Total
|
Average
price per
unit
|
Floor
price
|
Ceiling
price
|
||||||||||||||
(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) | ||||||||||||||||||||
2012
|
Swap
|
Mt. Belvieu Ethane
|
$ | 15.4 | $ | 0.64 | ||||||||||||||
Propane sales (Gals) | ||||||||||||||||||||
2012
|
Swap
|
Mt. Belvieu Propane
|
$ | 21.8 | $ | 1.28 |
Year
|
Type of
Contract
|
Index
|
Total
|
Average
Swap price
per unit
|
||||||||
(in millions)
|
||||||||||||
Ethane sales (Gals)
|
||||||||||||
2012
|
Swap
|
Mt. Belvieu Ethane
|
$ | 15.4 | $ | 0.64 | ||||||
Propane sales (Gals)
|
||||||||||||
2012
|
Swap
|
Mt. Belvieu Propane
|
$ | 15.4 | $ | 1.36 |
Year
|
Type of
Contract
|
Index
|
Total
|
Average
Swap 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 |
Three Months Ended
December 31,
|
Twelve Months Ended
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 BEFORE INCOME TAXES
|
(0.9 | ) | 102.3 | 424.8 | 452.9 | |||||||||||
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.
|
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; 177.2 million and 176.0 million shares issued at December 31, 2011 and 2010, respectively
|
1.8 | 1.8 | ||||||
Treasury stock - 0.4 million and 0.1 million shares at December 31, 2011 and 2010, respectively
|
(13.1 | ) | (3.8 | ) | ||||
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 |
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 |
Three Months Ended
December 31, |
Year Ended
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
December 31,
|
Year Ended
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
December 31,
|
Year Ended
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 NGL transportation and other handling costs)
|
$ | 40.3 | $ | 17.5 | $ | 121.5 | $ | 62.2 | ||||||||
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 (per MMBtu)
|
$ | 0.27 | $ | 0.15 | $ | 0.22 | $ | 0.16 |
Three Months Ended
December 31,
|
Year Ended
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
|
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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 |
Three Months Ended
December 31,
|
Year Ended
December 31,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
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(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 |