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Supplemental Gas and Oil Information (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
 
December 31,
 
2016
 
2015
 
(in millions)
Proved properties
$
14,232.5

 
$
13,314.9

Unproved properties, net
871.5

 
691.0

Total proved and unproved properties
15,104.0

 
14,005.9

Accumulated depreciation, depletion and amortization
(8,797.7
)
 
(6,870.2
)
Net capitalized costs
$
6,306.3

 
$
7,135.7
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions)
Proved property acquisitions
$
431.6

 
$
49.6

 
$
465.4

Unproved property acquisitions
208.7

 
39.8

 
496.3

Exploration (capitalized and expensed)
13.4

 
8.7

 
23.6

Development
509.2

 
1,010.3

 
1,695.1

Total costs incurred
$
1,162.9

 
$
1,108.4

 
$
2,680.4
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]
Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses.

 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions)
Revenues
$
1,271.0

 
$
1,390.4

 
$
2,374.6

Production costs
616.7

 
654.1

 
735.6

Exploration expenses
1.7

 
2.7

 
9.9

Depreciation, depletion and amortization
852.3

 
870.8

 
984.4

Impairment
1,194.3

 
55.6

 
1,143.2

Total expenses
2,665.0

 
1,583.2

 
2,873.1

Income (loss) before income taxes
(1,394.0
)
 
(192.8
)
 
(498.5
)
Income tax benefit (expense)
517.2

 
70.6

 
182.5

Results of operations from producing activities excluding allocated corporate overhead and interest expenses
$
(876.8
)
 
$
(122.2
)
 
$
(316.0
)
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]
As of December 31, 2016, 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, gas and NGL reserves for the years ended December 31, 2014, 2015 and 2016 are as follows:
 
 
Oil
 
Gas
 
NGL
 
Total(13)
 
 
(MMbbl)
 
(Bcf)
 
(MMbbl)
 
(MMboe)
Balance at December 31, 2013
 
148.6

 
2,554.9

 
102.6

 
677.0

Revisions of previous estimates(1)
 
(4.0
)
 
27.1

 
1.4

 
1.9

Extensions and discoveries(2)
 
16.8

 
141.4

 
8.6

 
49.0

Purchase of reserves in place(3)
 
35.7

 
72.5

 
12.3

 
60.1

Sale of reserves in place(4)
 
(7.5
)
 
(299.4
)
 
(21.5
)
 
(78.9
)
Production
 
(17.1
)
 
(179.3
)
 
(6.8
)
 
(53.8
)
Balance at December 31, 2014
 
172.5

 
2,317.2

 
96.6

 
655.3

Revisions of previous estimates(5)
 
(47.0
)
 
(463.8
)
 
(55.3
)
 
(179.6
)
Extensions and discoveries(6)
 
85.6

 
467.7

 
21.8

 
185.4

Purchase of reserves in place(7)
 
2.0

 
3.2

 
0.6

 
3.1

Sale of reserves in place(8)
 
(0.4
)
 
(34.3
)
 
(0.2
)
 
(6.3
)
Production
 
(19.6
)
 
(181.1
)
 
(4.7
)
 
(54.5
)
Balance at December 31, 2015
 
193.1

 
2,108.9

 
58.8

 
603.4

Revisions of previous estimates(9)
 
(9.7
)
 
412.8

 
(0.3
)
 
58.8

Extensions and discoveries(10)
 
13.0

 
158.1

 
3.3

 
42.6

Purchase of reserves in place(11)
 
62.7

 
54.6

 
11.5

 
83.3

Sale of reserves in place(12)
 
(0.2
)
 
(3.6
)
 
(0.1
)
 
(0.9
)
Production
 
(20.3
)
 
(177.0
)
 
(6.0
)
 
(55.8
)
Balance at December 31, 2016
 
238.6

 
2,553.8


67.2


731.4

Proved developed reserves
 
 
 
 
 
 
 
 
Balance at December 31, 2013
 
71.8

 
1,406.3

 
52.8

 
359.0

Balance at December 31, 2014
 
99.3

 
1,288.4

 
52.2

 
366.2

Balance at December 31, 2015
 
109.7

 
1,245.3

 
34.4

 
351.6

Balance at December 31, 2016
 
103.2

 
1,309.8

 
35.7

 
357.2

Proved undeveloped reserves
 
 
 
 
 
 
 
 
Balance at December 31, 2013
 
76.8

 
1,148.6

 
49.8

 
318.0

Balance at December 31, 2014
 
73.2

 
1,028.8

 
44.4

 
289.1

Balance at December 31, 2015
 
83.4

 
863.6

 
24.4

 
251.8

Balance at December 31, 2016
 
135.4

 
1,244.0

 
31.5

 
374.2

___________________________
(1) 
Revisions of previous estimates in 2014 include 41.4 MMboe negative performance revisions partially offset by positive other revisions of 33.0 MMboe, operating cost revisions of 6.5 MMboe and pricing revisions of 3.8 MMboe. Negative performance revisions were driven by a 32.3 MMboe 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. Pricing revisions were primarily due to increased gas prices, which increased reserves by 3.7 MMboe.
(2) 
Extensions and discoveries in 2014 increased proved reserves by 49.0 MMboe, primarily related to extensions and discoveries in Pinedale of 22.3 MMboe and the Williston Basin of 20.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations as well as new compression well projections in Pinedale.
(3) 
Purchase of reserves in place in 2014 relate to the Company's 2014 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.
(4) 
Sale of reserves in place primarily related to property sales in the Other Southern area in the second and fourth quarters of 2014 as discussed in Note 2 – Acquisitions and Divestitures.
(5) 
Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.
(6) 
Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations.
(7) 
Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston Basin as discussed in Note 2 – Acquisitions and Divestitures.
(8) 
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.
(9) 
Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.
(10) 
Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.
(11) 
Purchase of reserves in place in 2016 relate primarily to the Company's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.
(12) 
Sale of reserves in place in 2016 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,
 
2016
 
2015
 
2014
Average benchmark price per unit:
 
 
 
 
 
Oil price (per bbl)
$
42.75

 
$
50.28

 
$
94.99

Gas price (per MMBtu)
$
2.48

 
$
2.59

 
$
4.35
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,
 
2016
 
2015
 
2014
 
(in millions)
Future cash inflows
$
16,239.8

 
$
15,325.3

 
$
28,167.3

Future production costs
(7,789.0
)
 
(7,389.9
)
 
(9,842.1
)
Future development costs
(3,432.9
)
 
(2,202.5
)
 
(3,521.3
)
Future income tax expenses
(913.4
)
 
(1,169.3
)
 
(4,304.0
)
Future net cash flows
4,104.5

 
4,563.6

 
10,499.9

10% annual discount for estimated timing of net cash flows
(2,176.5
)
 
(2,087.3
)
 
(5,159.9
)
Standardized measure of discounted future net cash flows
$
1,928.0

 
$
2,476.3

 
$
5,340.0
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,
 
2016
 
2015
 
2014
 
(in millions)
Balance at January 1,
$
2,476.3

 
$
5,340.0

 
$
4,383.9

Sales of oil, gas and NGL produced, net of production costs
(654.3
)
 
(736.3
)
 
(1,639.0
)
Net change in sales prices and in production (lifting) costs related to future production
(739.4
)
 
(6,307.8
)
 
726.6

Net change due to extensions and discoveries
81.8

 
1,765.7

 
979.9

Net change due to revisions of quantity estimates
122.7

 
(1,350.2
)
 
35.9

Net change due to purchases of reserves in place
256.5

 
29.7

 
695.3

Net change due to sales of reserves in place
(4.3
)
 
(48.8
)
 
(1,153.7
)
Previously estimated development costs incurred during the period
374.6

 
865.0

 
867.5

Changes in estimated future development costs
(476.5
)
 
560.7

 
409.6

Accretion of discount
311.1

 
752.9

 
597.3

Net change in income taxes
205.4

 
1,554.4

 
(600.3
)
Other
(25.9
)
 
51.0

 
37.0

Net change
(548.3
)
 
(2,863.7
)
 
956.1

Balance at December 31,
$
1,928.0

 
$
2,476.3

 
$
5,340.0