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Supplemental Gas and Oil Information (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below and includes capitalized costs classified as “Noncurrent assets held for sale” on the Consolidated Balance Sheets:

 
December 31,
 
2019
 
2018
 
(in millions)
Proved properties
$
9,574.9

 
$
12,140.7

Unproved properties, net
599.1

 
759.1

Total proved and unproved properties
10,174.0

 
12,899.8

Accumulated depreciation, depletion and amortization
(5,250.5
)
 
(7,450.5
)
Net capitalized costs
$
4,923.5

 
$
5,449.3
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]
The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Costs associated with the Company's midstream and corporate activities are not included. Development costs are net of the change in accrued capital costs of $12.2 million and ARO additions and revisions of $1.2 million during the year ended December 31, 2019. The costs incurred for the development of reserves that were classified as proved undeveloped were approximately $426.1 million in 2019, $606.5 million in 2018 and $389.3 million in 2017.

 
Year Ended December 31,
 
2019
 
2018
 
2017
 
(in millions)
Proved property acquisitions
$
1.5

 
$
39.1

 
$
269.6

Unproved property acquisitions
2.0

 
25.8

 
532.4

Other acquisitions
—

 
0.8

 
13.2

Exploration costs (capitalized and expensed)
0.1

 
0.3

 
32.7

Development costs
556.2

 
1,133.1

 
1,189.3

Total costs incurred
$
559.8

 
$
1,199.1

 
$
2,037.2
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. Revenues and expenses relating to the Company's midstream and corporate activities are not included.

 
Year Ended December 31,
 
2019
 
2018
 
2017
 
(in millions)
Revenues
$
1,200.6

 
$
1,920.3

 
$
1,548.1

Production costs
361.9

 
507.3

 
675.4

Exploration expenses
0.1

 
0.3

 
22.0

Depreciation, depletion and amortization
528.5

 
836.4

 
735.1

Impairment
—

 
1,560.9

 
72.3

Total expenses
890.5

 
2,904.9

 
1,504.8

Income (loss) before income taxes
310.1

 
(984.6
)
 
43.3

Income tax benefit (expense)
(69.5
)
 
243.2

 
(16.0
)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses
$
240.6

 
$
(741.4
)
 
$
27.3
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]
As of December 31, 2019, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's changes in quantities of proved oil and condensate, gas and NGL reserves for the years ended December 31, 2017, 2018 and 2019 are as follows:
 
Oil and condensate
 
Gas
 
NGL
 
Total(13)
 
(MMbbl)
 
(Bcf)
 
(MMbbl)
 
(MMboe)
Balance at December 31, 2016
238.6

 
2,553.8

 
67.2

 
731.4

Revisions of previous estimates(1)
3.7

 
12.5

 
(3.1
)
 
2.7

Extensions and discoveries(2)
59.1

 
101.9

 
10.4

 
86.4

Purchase of reserves in place(3)
46.6

 
125.5

 
8.7

 
76.3

Sale of reserves in place(4)
(7.9
)
 
(831.2
)
 
(12.6
)
 
(159.0
)
Production
(19.6
)
 
(168.9
)
 
(5.4
)
 
(53.1
)
Balance at December 31, 2017
320.5

 
1,793.6

 
65.2

 
684.7

Revisions of previous estimates(5)
2.1

 
314.0

 
6.7

 
61.0

Extensions and discoveries(6)
57.1

 
56.5

 
9.8

 
76.3

Purchase of reserves in place(7)
8.2

 
7.9

 
1.3

 
10.9

Sale of reserves in place(8)
(24.9
)
 
(544.8
)
 
(7.1
)
 
(122.8
)
Production
(23.9
)
 
(139.6
)
 
(4.7
)
 
(51.9
)
Balance at December 31, 2018
339.1

 
1,487.6

 
71.2

 
658.2

Revisions of previous estimates(9)
(94.9
)
 
(23.0
)
 
(8.7
)
 
(107.3
)
Extensions and discoveries(10)
33.6

 
40.0

 
7.4

 
47.6

Purchase of reserves in place(11)
3.6

 
4.0

 
0.7

 
4.9

Sale of reserves in place(12)
(4.9
)
 
(1,102.2
)
 
(0.3
)
 
(188.9
)
Production
(21.6
)
 
(33.1
)
 
(5.1
)
 
(32.2
)
Balance at December 31, 2019
254.9

 
373.3


65.2


382.3

Proved developed reserves
 
 
 
 
 
 
 
Balance at December 31, 2016
103.2

 
1,309.8

 
35.7

 
357.2

Balance at December 31, 2017
116.0

 
655.5

 
27.9

 
253.1

Balance at December 31, 2018
133.6

 
382.3

 
31.5

 
228.9

Balance at December 31, 2019
117.5

 
217.0

 
36.7

 
190.4

Proved undeveloped reserves
 
 
 
 
 
 
 
Balance at December 31, 2016
135.4

 
1,244.0

 
31.5

 
374.2

Balance at December 31, 2017
204.5

 
1,138.1

 
37.3

 
431.6

Balance at December 31, 2018
205.5

 
1,105.3

 
39.7

 
429.3

Balance at December 31, 2019
137.4

 
156.3

 
28.5

 
191.9

___________________________
(1) 
Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin.
(2) 
Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.
(3) 
Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 3 – Acquisitions and Divestitures.
(4) 
Sale of reserves in place in 2017 was primarily related to QEP's Pinedale Divestiture as discussed in Note 3 – Acquisitions and Divestitures.
(5) 
Revisions of previous estimates in 2018 totaling 61.0 MMboe of positive revisions include 23.4 MMboe of other revisions, primarily related to changing our development plans in the Haynesville/Cotton Valley; 17.3 MMboe of
positive revisions related to pricing, primarily driven by higher oil prices; 11.7 MMboe of positive revisions related to lower operating costs; and 8.7 MMboe of positive performance revisions.
(6) 
Extensions and discoveries in 2018 primarily related to new well completions and associated new PUD locations in the Permian Basin.
(7) 
Purchase of reserves in place in 2018 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.
(8) 
Sale of reserves in place in 2018 was primarily related to QEP's Uinta Basin Divestiture as discussed in Note 3 – Acquisitions and Divestitures.
(9) 
Revisions of previous estimates in 2019 totaling 107.3 MMboe of negative revisions includes 44.5 MMboe of negative PUD revisions as a result of changes to the development sequence in the Permian Basin, to maximize capital efficiency (see offset in extensions and discoveries footnote 10 below); 25.8 MMboe of PUD removals, primarily in the Williston Basin, that will not be developed within five years of the initial date of booking due to the reduction in future capital expenditures; 17.0 MMboe of negative revisions related to pricing, primarily driven by lower oil prices; 13.7 MMboe of negative performance revisions, primarily associated with updated volume projections for high-density wells and certain undrilled locations in the Permian Basin; 10.9 MMboe of other negative revisions, partially offset by 4.6 MMboe of positive revisions related to lower operating costs.
(10) 
Extensions and discoveries in 2019 primarily related to new PUD locations in the Permian Basin due to changes in the development sequence in the Permian Basin to maximize capital efficiency. See partial offset in revisions to previous estimates in footnote 9 above.
(11) 
Purchase of reserves in place in 2019 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.
(12) 
Sale of reserves in place in 2019 was primarily related to QEP's Haynesville Divestiture as discussed in Note 3 – Acquisitions and Divestitures.
(13) 
Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

Stan
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,
 
2019
 
2018
 
2017
Average benchmark price per unit:
 
 
 
 
 
Oil price (per bbl)
$
55.51

 
$
65.56

 
$
51.34

Gas price (per MMBtu)
$
2.58

 
$
3.10

 
$
2.98
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

The standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:

 
Year Ended December 31,
 
2019
 
2018
 
2017
 
(in millions)
Future cash inflows
$
14,447.6

 
$
26,482.6

 
$
22,028.9

Future production costs
(6,070.6
)
 
(9,539.9
)
 
(9,074.2
)
Future development costs(1)
(2,275.2
)
 
(4,441.5
)
 
(4,726.0
)
Future income tax expenses(2)
(845.8
)
 
(2,553.6
)
 
(1,439.1
)
Future net cash flows
5,256.0

 
9,947.6

 
6,789.6

10% annual discount for estimated timing of net cash flows
(2,579.7
)
 
(4,991.9
)
 
(3,692.3
)
Standardized measure of discounted future net cash flows
$
2,676.3

 
$
4,955.7

 
$
3,097.3

___________________________
(1) 
Future development costs include future abandonment and salvage costs.
(2) 
The standardized measure of discounted future net cash flows for the year ended December 31, 2019, 2018 and 2017, were estimated assuming a 21% federal tax rate from the Tax Legislation enacted in December 2017.
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 discounted future net cash flows relating to proved reserves is presented in the table below:

 
Year Ended December 31,
 
2019
 
2018
 
2017
 
(in millions)
Balance at January 1,
$
4,955.7

 
$
3,097.3

 
$
1,928.0

Sales of oil and condensate, gas and NGL produced, net of production costs
(838.7
)
 
(1,413.0
)
 
(872.7
)
Net change in sales prices and in production (lifting) costs related to future production
(1,988.6
)
 
1,632.5

 
1,457.2

Net change due to extensions and discoveries
220.9

 
692.6

 
556.8

Net change due to revisions of quantity estimates
(2,079.2
)
 
732.0

 
9.9

Net change due to purchases of reserves in place
34.2

 
117.0

 
342.7

Net change due to sales of reserves in place
(617.8
)
 
(369.6
)
 
(504.7
)
Previously estimated development costs incurred during the period
460.8

 
735.6

 
475.4

Changes in estimated future development costs
1,064.7

 
(28.3
)
 
(283.4
)
Accretion of discount
622.8

 
375.4

 
235.7

Net change in income taxes
841.5

 
(615.7
)
 
(227.4
)
Other
—

 
(0.1
)
 
(20.2
)
Net change
(2,279.4
)
 
1,858.4

 
1,169.3

Balance at December 31,
$
2,676.3

 
$
4,955.7

 
$
3,097.3