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Supplemental Gas and Oil Information (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2013
Supplemental Gas and Oil Information (Unaudited) [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
 
December 31,
 
2013
 
2012
 
(in millions)
Proved properties
$
11,571.4

 
$
10,234.3

Unproved properties, net
665.1

 
937.9

Total proved and unproved properties
12,236.5

 
11,172.2

Accumulated depreciation, depletion and amortization
(4,930.9
)
 
(4,258.1
)
Net capitalized costs
$
7,305.6

 
$
6,914.1
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(in millions)
Property acquisitions
 
 
 
 
 
Unproved
$
9.3

 
$
692.6

 
$
48.0

Proved
31.6

 
714.4

 
0.1

Total property acquisitions
40.9

 
1,407.0

 
48.1

Exploration (capitalized and expensed)
14.6

 
14.3

 
36.5

Development
1,440.8

 
1,310.0

 
1,267.8

Total costs incurred
$
1,496.3

 
$
2,731.3

 
$
1,352.4
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]
Following are the results of operations of QEP Energy's oil and gas exploration and development activities, before allocated corporate overhead and interest expenses.

 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(in millions)
Revenues (1)
$
1,901.2

 
$
1,393.4

 
$
1,703.4

Production costs
583.3

 
501.1

 
433.3

Exploration expenses
11.9

 
11.2

 
10.5

Depreciation, depletion and amortization
954.2

 
838.4

 
707.4

Impairment
93.0

 
133.0

 
218.2

Total expenses
1,642.4

 
1,483.7

 
1,369.4

Income (loss) before income taxes
258.8

 
(90.3
)
 
334.0

Income tax benefit (expense)
(96.3
)
 
33.6

 
(119.0
)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses
$
162.5

 
$
(56.7
)
 
$
215.0

___________________________
(1) 
Revenue for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the years ended December 31, 2013 and 2012, are reflected below operating income (loss) on the Consolidated Statements of Operations. See Note 7 - Derivative Contracts.
Following are the results of operations of QEP Energy's oil and gas exploration and development activities, before allocated corporate overhead and interest expenses.

 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(in millions)
Revenues (1)
$
1,901.2

 
$
1,393.4

 
$
1,703.4

Production costs
583.3

 
501.1

 
433.3

Exploration expenses
11.9

 
11.2

 
10.5

Depreciation, depletion and amortization
954.2

 
838.4

 
707.4

Impairment
93.0

 
133.0

 
218.2

Total expenses
1,642.4

 
1,483.7

 
1,369.4

Income (loss) before income taxes
258.8

 
(90.3
)
 
334.0

Income tax benefit (expense)
(96.3
)
 
33.6

 
(119.0
)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses
$
162.5

 
$
(56.7
)
 
$
215.0

___________________________
(1) 
Revenue for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the years ended December 31, 2013 and 2012, are reflected below operating income (loss) on the Consolidated Statements of Operations. See Note 7 - Derivative Contracts.
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]
As of December 31, 2013, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil and gas reserves for the years ended December 31, 2011, 2012 and 2013 are as follows:
 
Gas
 
Oil
 
NGL
 
Total
 
(Bcf)
 
(MMbbl)
 
(MMbbl)
 
(Bcfe)
Balance at December 31, 2010
2,612.9

 
52.3

 
17.4

 
3,030.7

Revisions of previous estimates(6)
(270.1
)
 
1.7

 
39.3

 
(23.5
)
Extensions and discoveries (7)
641.9

 
17.4

 
22.6

 
881.6

Purchase of reserves in place
1.9

 
—

 
—

 
2.1

Sale of reserves in place
(0.8
)
 
(0.2
)
 
—

 
(1.9
)
Production
(236.4
)
 
(3.7
)
 
(2.7
)
 
(275.2
)
Balance at December 31, 2011
2,749.4

 
67.5

 
76.6

 
3,613.8

Revisions of previous estimates (3)
(240.6
)
 
(1.5
)
 
0.7

 
(244.8
)
Extensions and discoveries (4)
330.6

 
17.3

 
23.0

 
572.5

Purchase of reserves in place (5)
32.3

 
42.0

 
4.9

 
313.8

Sale of reserves in place
—

 
—

 
—

 
—

Production
(249.3
)
 
(6.3
)
 
(5.3
)
 
(319.2
)
Balance at December 31, 2012
2,622.4

 
119.0

 
99.9

 
3,936.1

Revisions of previous estimates (1)
(288.3
)
 
1.3

 
(8.0
)
 
(328.5
)
Extensions and discoveries (2)
455.6

 
38.3

 
16.4

 
783.8

Purchase of reserves in place
1.0

 
1.9

 
0.2

 
13.4

Sale of reserves in place
(16.9
)
 
(1.7
)
 
(1.1
)
 
(33.9
)
Production
(218.9
)
 
(10.2
)
 
(4.8
)
 
(309.0
)
Balance at December 31, 2013
2,554.9


148.6


102.6


4,061.9

Proved developed reserves
 
 
 
 
 
 
 
Balance at December 31, 2010
1,404.8

 
25.1

 
9.3

 
1,611.5

Balance at December 31, 2011
1,538.3

 
33.0

 
38.4

 
1,966.3

Balance at December 31, 2012
1,531.7

 
47.4

 
49.3

 
2,111.9

Balance at December 31, 2013
1,406.3

 
71.8

 
52.8

 
2,154.0

Proved undeveloped reserves
 
 
 
 
 
 
 
Balance at December 31, 2010
1,208.1

 
27.2

 
8.0

 
1,419.2

Balance at December 31, 2011
1,211.1

 
34.6

 
38.2

 
1,647.5

Balance at December 31, 2012
1,090.7

 
71.6

 
50.6

 
1,824.2

Balance at December 31, 2013
1,148.6

 
76.8

 
49.8

 
1,907.9

 ____________________________

(1) 
Revisions of previous estimates in 2013 include positive impacts due to 80.0 Bcfe pricing revisions, negative performance revisions of 265.5 Bcfe, 42.0 Bcfe negative operating cost revisions and 101.0 Bcfe other negative revisions. Pricing revisions were primarily due to increased gas prices which increased reserves by 68.4 Bcfe. Negative performance revisions were driven by a 129.5 Bcfe decrease in Pinedale reserves and 112.7 Bcfe decrease in Haynesville reserves related to reserve adjustments based on additional production history, well performance and current pricing causing a revised future development plan which includes lower density drilling in some areas and a change in well spacing assumptions in these areas.
(2) 
Extensions and discoveries in 2013 increased proved reserves by 783.8 Bcfe, primarily related to extensions and discoveries in the Williston Basin of 217.6 Bcfe, in Pinedale of 265.3 Bcfe, and 175.9 Bcfe in Haynesville. Extension and discoveries in Pinedale and Haynesville relate to certain less densely spaced wells with higher estimates of recoverable oil and gas, which were booked to replace wells removed from the Company's reserves through negative revisions caused by a change in well spacing assumptions in these areas. Of these extensions and discoveries 687.6 Bcfe related to new PUD locations.




(3) 
Revisions of previous estimates in 2012 include negative impacts due to 80.0 Bcfe pricing revisions, 35.6 Bcfe performance revisions, 27.6 Bcfe operating cost revisions and 29.1 Bcfe other revisions. The 152.4 Bcfe pricing revisions were due to lower gas prices which reduced gas reserve volumes by 147.7 Bcf. Negative performance revisions were driven by a 56.0 Bcfe decrease in Pinedale reserves. Pinedale reserve adjustments are based on additional production history, well performance and current pricing causing a revised future development plan which includes lower density drilling in some flank areas, resulting in 25 proved undeveloped (PUD) locations being eliminated. Reserve decreases are partially offset by a 35.9 Bcfe positive impact from revisions in the Uinta Basin, due to the installation of the Iron Horse Cryogenic plant to increase liquid recoveries and improved well performance in the Red Wash Mesaverde field.
(4) 
Extensions and discoveries in 2012 increased proved reserves by 572.5 Bcfe, primarily related to extensions and discoveries in the Uinta Basin of 258.3 Bcfe, in Pinedale of 151.6 Bcfe, and 162.6 Bcfe in the Williston Basin, Midcontinent and other Legacy areas of operation combined. All of these extensions and discoveries related to new well completions and the associated new PUD locations as part of the Company's development drilling plans.
(5) 
Purchase of reserves in place primarily relate to the Company's $1.4 billion 2012 Acquisition as discussed in Note 2 - Acquisitions and Divestitures.
(6) 
Revisions of previous estimates in 2011 include 173.7 Bcfe negative impact due to performance revisions offset by 150.2 Bcfe positive impact from other revisions. The 173.7 Bcfe performance revisions were due to the reduction of gas volumes of 209.8 Bcf, partially offset by an increase in NGL volumes of 33.2 MMbbls, which is included in other revisions. The primary reason for the increase in the NGL volumes, or 31.8 MMbbls, relates to the completion of the Blacks Fork II plant and the fee-based processing agreement entered into between QEP Energy and QEP Field Services for QEP Energy's Pinedale production, offset by a reduction in the dry gas reserve related to shrink of about 59.6 Bcf. The remaining performance related reduction in the gas reserves was primarily related to the removal of certain PUD locations in the Haynesville/Cotton Valley area to recognize the 80-acre increased density development plan.
(7) 
Extensions and discoveries increased proved reserves by 881.6 Bcfe, primarily related to extensions and discoveries at the Haynesville/Cotton Valley area (358.8 Bcfe), Uinta Basin area (189.1 Bcfe) and Pinedale Anticline area (161.2 Bcfe). All of these extensions and discoveries related to new well completions and associated new PUD locations. Estimates of the quantity of proved reserves from the Company's Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the years ended December 31, 2011 and 2010, because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure Price per Unit [Table Text Block]
The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:
 
For the year ended December 31,
 
2013
 
2012
 
2011
Average benchmark price per unit:
 
 
 
 
 
Gas price (per MMbtu)
$
3.67

 
$
2.76

 
$
4.12

Oil price (per Bbl)
96.94

 
94.71

 
96.19
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]
The standardized measure of future net cash flows relating to proved reserves is presented in the table below:
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(in millions)
Future cash inflows
$
24,805.7

 
$
18,200.2

 
$
18,300.6

Future production costs
(8,400.3
)
 
(5,027.2
)
 
(4,276.1
)
Future development costs
(4,056.7
)
 
(3,927.3
)
 
(3,250.0
)
Future income tax expenses
(3,284.6
)
 
(2,269.0
)
 
(2,837.1
)
 
9,064.1

 
6,976.7

 
7,937.4

10% annual discount for estimated timing of net cash flows
(4,680.2
)
 
(3,942.0
)
 
(4,411.8
)
Standardized measure of discounted future net cash flows
$
4,383.9

 
$
3,034.7

 
$
3,525.6
Principal Sources of Change in Standardized measure of Discounted Future Net Cash Flows [Table Text Block]
The principal sources of change in the standardized measure of future net cash flows relating to proved reserves is presented in the table below:
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(in millions)
Balance at January 1,
$
3,034.7

 
$
3,525.6

 
$
2,705.6

Sales of gas, oil and NGL produced during the period, net of production costs
(1,317.9
)
 
(892.3
)
 
(1,779.9
)
Net change in sales prices and in production (lifting) costs related to future production
1,236.3

 
(2,083.5
)
 
1,472.5

Net change due to extensions, discoveries and improved recovery
2,230.7

 
948.5

 
1,806.4

Net change due to revisions of quantity estimates
(709.6
)
 
(387.8
)
 
(48.2
)
Changes due to purchases of reserves in place
36.8

 
831.4

 
0.1

Changes due to sales of reserves in place
(73.2
)
 
—

 
(8.0
)
Previously estimated development costs incurred during the period
722.7

 
513.0

 
533.6

Changes in estimated future development costs
(596.5
)
 
(209.3
)
 
(1,110.4
)
Accretion of discount
402.2

 
499.4

 
355.4

Net change in income taxes
(601.7
)
 
273.6

 
(411.4
)
Other
19.4

 
16.1

 
9.9

Net change
1,349.2

 
(490.9
)
 
820.0

Balance at December 31,
$
4,383.9

 
$
3,034.7

 
$
3,525.6