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Supplemental Gas and Oil Information (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
 
December 31,
 
2015
 
2014
 
(in millions)
Proved properties
$
13,314.9

 
$
12,278.7

Unproved properties, net
691.0

 
825.2

Total proved and unproved properties
14,005.9

 
13,103.9

Accumulated depreciation, depletion and amortization
(6,870.2
)
 
(6,153.0
)
Net capitalized costs
$
7,135.7

 
$
6,950.9
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in millions)
Proved property acquisitions
$
49.6

 
$
465.4

 
$
31.6

Unproved property acquisitions
39.8

 
496.3

 
9.3

Exploration (capitalized and expensed)
8.7

 
23.6

 
14.6

Development
1,010.3

 
1,695.1

 
1,440.8

Total costs incurred
$
1,108.4

 
$
2,680.4

 
$
1,496.3
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 producing activities, before allocated corporate overhead and interest expenses.

 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in millions)
Revenues
$
1,390.4

 
$
2,374.6

 
$
1,901.2

Production costs
654.1

 
735.6

 
583.3

Exploration expenses
2.7

 
9.9

 
11.9

Depreciation, depletion and amortization
870.8

 
984.4

 
954.2

Impairment
55.6

 
1,143.2

 
93.0

Total expenses
1,583.2

 
2,873.1

 
1,642.4

Income (loss) before income taxes
(192.8
)
 
(498.5
)
 
258.8

Income tax benefit (provision)
70.6

 
182.5

 
(96.3
)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses
$
(122.2
)
 
$
(316.0
)
 
$
162.5
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]
As of December 31, 2015, 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 gas, oil and NGL reserves for the years ended December 31, 2013, 2014 and 2015 are as follows:
 
Gas
 
Oil
 
NGL
 
Total
 
(Bcf)
 
(MMbbl)
 
(MMbbl)
 
(Bcfe)
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

Revisions of previous estimates(3)
27.1

 
(4.0
)
 
1.4

 
11.3

Extensions and discoveries(4)
141.4

 
16.8

 
8.6

 
294.1

Purchase of reserves in place(5)
72.5

 
35.7

 
12.3

 
360.7

Sale of reserves in place(6)
(299.4
)
 
(7.5
)
 
(21.5
)
 
(473.4
)
Production
(179.3
)
 
(17.1
)
 
(6.8
)
 
(322.7
)
Balance at December 31, 2014
2,317.2

 
172.5

 
96.6

 
3,931.9

Revisions of previous estimates(7)
(463.8
)
 
(47.0
)
 
(55.3
)
 
(1,077.9
)
Extensions and discoveries(8)
467.7

 
85.6

 
21.8

 
1,111.9

Purchase of reserves in place(9)
3.2

 
2.0

 
0.6

 
18.7

Sale of reserves in place(10)
(34.3
)
 
(0.4
)
 
(0.2
)
 
(37.6
)
Production
(181.1
)
 
(19.6
)
 
(4.7
)
 
(326.8
)
Balance at December 31, 2015
2,108.9

 
193.1


58.8


3,620.2

Proved developed reserves
 
 
 
 
 
 
 
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

Balance at December 31, 2014
1,288.4

 
99.3

 
52.2

 
2,197.5

Balance at December 31, 2015
1,245.3

 
109.7

 
34.4

 
2,109.4

Proved undeveloped reserves
 
 
 
 
 
 
 
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

 


Balance at December 31, 2014
1,028.8

 
73.2

 
44.4

 
1,734.4

Balance at December 31, 2015
863.6

 
83.4

 
24.4

 
1,510.8

___________________________
(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 and a change in well spacing assumptions in some 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 2014 include 248.5 Bcfe negative performance revisions partially offset by positive other revisions of 197.7 Bcfe, operating cost revisions of 39.2 Bcfe and pricing revisions of 22.9 Bcfe. Negative performance revisions were driven by a 194.0 Bcfe decrease in Pinedale reserves related to downward forecast revisions on proved developed (PDP) wells, additional production history on PUD to PDP performance and a downward adjustment in the number of PUD locations. Other negative revisions related to adjustments to shrink and lease operating expense deducts. Pricing revisions were primarily due to increased gas prices, which increased reserves by 21.9 Bcfe.
(4) 
Extensions and discoveries in 2014 increased proved reserves by 294.1 Bcfe, primarily related to extensions and discoveries in Pinedale of 133.6 Bcfe and the Williston Basin of 123.3 Bcfe. 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 and new compression well projections in Pinedale.
(5) 
Purchase of reserves in place in 2014 relate to the Company's Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.
(6) 
Sale of reserves in place primarily related to property sales in the Midcontinent in the second and fourth quarters of 2014 as discussed in Note 2 – Acquisitions and Divestitures.
(7) 
Revisions of previous estimates in 2015 include: 756.9 Bcfe of negative revisions due to lower pricing and 403.2 Bcfe of negative revisions unrelated to pricing, partially offset by 82.2 Bcfe of positive performance revisions. Negative pricing revisions were driven by lower gas, oil, and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and Uinta Basin.
(8) 
Extensions and discoveries in 2015 increased proved reserves by 1,111.9 Bcfe, primarily related to extensions and discoveries in Williston Basin of 409.3 Bcfe, Uinta Basin of 318.9 Bcfe, and Permian Basin of 297.8 Bcfe. 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 and new compression well projections in Pinedale.
(9) 
Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP's operated wells in the Williston Basin as discussed in Note 2 – Acquisitions and Divestitures.
(10) 
Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure Price per Unit [Table Text Block]
he 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,
 
2015
 
2014
 
2013
Average benchmark price per unit:
 
 
 
 
 
Gas price (per MMBtu)
$
2.59

 
$
4.35

 
$
3.67

Oil price (per bbl)
50.28

 
94.99

 
96.94
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]
he standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in millions)
Future cash inflows
$
15,325.3

 
$
28,167.3

 
$
24,805.7

Future production costs
(7,389.9
)
 
(9,842.1
)
 
(8,400.3
)
Future development costs
(2,202.5
)
 
(3,521.3
)
 
(4,056.7
)
Future income tax expenses
(1,169.3
)
 
(4,304.0
)
 
(3,284.6
)
Future net cash flows
4,563.6

 
10,499.9

 
9,064.1

10% annual discount for estimated timing of net cash flows
(2,087.3
)
 
(5,159.9
)
 
(4,680.2
)
Standardized measure of discounted future net cash flows
$
2,476.3

 
$
5,340.0

 
$
4,383.9
Principal Sources of Change in Standardized measure of Discounted Future Net Cash Flows [Table Text Block]
he principal sources of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(in millions)
Balance at January 1,
$
5,340.0

 
$
4,383.9

 
$
3,034.7

Sales of gas, oil and NGL produced during the period, net of production costs
(736.3
)
 
(1,639.0
)
 
(1,317.9
)
Net change in sales prices and in production (lifting) costs related to future production
(6,307.8
)
 
726.6

 
1,236.3

Net change due to extensions, discoveries and improved recovery
1,765.7

 
979.9

 
2,230.7

Net change due to revisions of quantity estimates
(1,350.2
)
 
35.9

 
(709.6
)
Net change due to purchases of reserves in place
29.7

 
695.3

 
36.8

Net change due to sales of reserves in place
(48.8
)
 
(1,153.7
)
 
(73.2
)
Previously estimated development costs incurred during the period
865.0

 
867.5

 
722.7

Changes in estimated future development costs
560.7

 
409.6

 
(596.5
)
Accretion of discount
752.9

 
597.3

 
402.2

Net change in income taxes
1,554.4

 
(600.3
)
 
(601.7
)
Other
51.0

 
37.0

 
19.4

Net change
(2,863.7
)
 
956.1

 
1,349.2

Balance at December 31,
$
2,476.3

 
$
5,340.0

 
$
4,383.9