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Supplemental Gas and Oil Information (Unaudited)
 12 Months Ended
Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Oil and Gas Exploration and Production Industries Disclosures [Text Block]
The Company is making the following supplemental disclosures of oil and gas producing activities, in accordance with ASC 932, Extractive Activities – Oil and Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and SEC Regulation S-X. The Company uses the successful efforts accounting method for its oil and gas exploration and development activities. All of QEP's properties are located in the United States.
Capitalized Costs
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:

 
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



Costs Incurred
The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs of $34.6 million and ARO additions and revisions of $23.5 million during the year ended December 31, 2016. The costs incurred to advance the development of reserves that were classified as proved undeveloped were approximately $258.1 million in 2016, $490.4 million in 2015, and $792.9 million in 2014. The costs incurred in 2016 related to the drilling and completion of PUD locations in QEP's operating areas were reduced from historical levels in conjunction with our efforts to reduce drilling and completion activities in 2016 due to lower commodity prices.
 
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
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
)


Estimated Quantities of Proved Oil and Gas Reserves
Estimates of proved oil and gas reserves have been completed in accordance with professional engineering standards and the Company's established internal controls, which includes the oversight of a multi-functional reserves review committee reporting to the Company's Audit Committee of the Board of Directors. The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2016, and retained RSC and DeGolyer and MacNaughton to prepare the estimates of all of its proved reserves as of December 31, 2015 and 2014. The estimated proved reserves have been prepared in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

All of QEP's proved undeveloped reserves at December 31, 2016, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. The Company plans to continue development of its leasehold and anticipates that it will have the financial capability to continue development in the manner estimated. While the majority of QEP's PUD reserves are located on leaseholds that are held by production, any PUD locations on expiring leaseholds are scheduled for development during the primary term of the lease.

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.
(13) 
Proved reserves include gas reserves that QEP expects to produce and use as field fuel.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
Future net cash flows were calculated at December 31, 2016, 2015 and 2014, by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for each of the 12 months during 2016, 2015 and 2014, with consideration of known contractual price changes. The prices used do not include any impact of QEP's commodity derivatives portfolio. 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,
 
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


Year-end operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved undeveloped reserves are approximately $503.0 million in 2017, $717.3 million in 2018 and $781.3 million in 2019. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEP believes cash flow from its operating activities, cash on hand and, if needed, availability under its revolving credit facility will be sufficient to cover these estimated future development costs.

The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating QEP or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:     
•
Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.
•
Future operating and capital costs will likely differ from those required to be used in these calculations.
•
Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and gas may cause production rates in future years to vary significantly from those rates used in the calculations.
•
Future revenues may be subject to different production, severance and property taxation rates.
•
The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.

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)
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


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,
 
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