XML 51 R42.htm IDEA: XBRL DOCUMENT v2.4.1.9
Supplemental Gas and Oil Information (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]
 
December 31,
 
2014
 
2013
 
(in millions)
Proved properties
$
12,278.7

 
$
11,571.4

Unproved properties, net
825.2

 
665.1

Total proved and unproved properties
13,103.9

 
12,236.5

Accumulated depreciation, depletion and amortization
(6,153.0
)
 
(4,930.9
)
Net capitalized costs
$
6,950.9

 
$
7,305.6
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Property acquisitions
 
 
 
 
 
Unproved
$
496.3

 
$
9.3

 
$
692.6

Proved
465.4

 
31.6

 
714.4

Total property acquisitions
961.7

 
40.9

 
1,407.0

Exploration (capitalized and expensed)
23.6

 
14.6

 
14.3

Development
1,695.1

 
1,440.8

 
1,310.0

Total costs incurred
$
2,680.4

 
$
1,496.3

 
$
2,731.3
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,
 
2014
 
2013
 
2012
 
(in millions)
Revenues
$
2,374.6

 
$
1,901.2

 
$
1,393.4

Production costs
735.6

 
583.3

 
501.1

Exploration expenses
9.9

 
11.9

 
11.2

Depreciation, depletion and amortization
984.4

 
954.2

 
838.4

Impairment
1,143.2

 
93.0

 
133.0

Total expenses
2,873.1

 
1,642.4

 
1,483.7

Income (loss) before income taxes
(498.5
)
 
258.8

 
(90.3
)
Income tax benefit (expense)
182.5

 
(96.3
)
 
33.6

Results of operations from producing activities excluding allocated corporate overhead and interest expenses
$
(316.0
)
 
$
162.5

 
$
(56.7
)
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]
As of December 31, 2014, 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, 2012, 2013 and 2014 are as follows:
 
Gas
 
Oil
 
NGL
 
Total
 
(Bcf)
 
(MMbbl)
 
(MMbbl)
 
(Bcfe)
Balance at December 31, 2011
2,749.4

 
67.5

 
76.6

 
3,613.8

Revisions of previous estimates(1)
(240.6
)
 
(1.5
)
 
0.7

 
(244.8
)
Extensions and discoveries(2)
330.6

 
17.3

 
23.0

 
572.5

Purchase of reserves in place(3)
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(4)
(288.3
)
 
1.3

 
(8.0
)
 
(328.5
)
Extensions and discoveries(5)
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(6)
27.1

 
(4.0
)
 
1.4

 
11.3

Extensions and discoveries(7)
141.4

 
16.8

 
8.6

 
294.1

Purchase of reserves in place(8)
72.5

 
35.7

 
12.3

 
360.7

Sale of reserves in place(9)
(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

Proved developed reserves
 
 
 
 
 
 
 
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

Balance at December 31, 2014
1,288.4

 
99.3

 
52.2

 
2,197.5

Proved undeveloped reserves
 
 
 
 
 
 
 
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

Balance at December 31, 2014
1,028.8

 
73.2

 
44.4

 
1,734.4

___________________________
(1) 
Revisions of previous estimates in 2012 include negative impacts due to 152.4 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.
(2) 
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 Northern 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.
(3) 
Purchase of reserves in place in 2012 primarily relate to the Company's $1.4 billion Williston Basin Acquisition as discussed in Note 2 - Acquisitions and Divestitures.
(4) 
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.
(5) 
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.
(6) 
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.
(7) 
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.
(8) 
Purchase of reserves in place in 2014 relate to the Company's Permian Basin Acquisition as discussed in Note 2 - Acquisitions and Divestitures.
(9) 
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.
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,
 
2014
 
2013
 
2012
Average benchmark price per unit:
 
 
 
 
 
Gas price (per MMBtu)
$
4.35

 
$
3.67

 
$
2.76

Oil price (per bbl)
94.99

 
96.94

 
94.71
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,
 
2014
 
2013
 
2012
 
(in millions)
Future cash inflows
$
28,167.3

 
$
24,805.7

 
$
18,200.2

Future production costs
(9,842.1
)
 
(8,400.3
)
 
(5,027.2
)
Future development costs
(3,521.3
)
 
(4,056.7
)
 
(3,927.3
)
Future income tax expenses
(4,304.0
)
 
(3,284.6
)
 
(2,269.0
)
Future net cash flows
10,499.9

 
9,064.1

 
6,976.7

10% annual discount for estimated timing of net cash flows
(5,159.9
)
 
(4,680.2
)
 
(3,942.0
)
Standardized measure of discounted future net cash flows
$
5,340.0

 
$
4,383.9

 
$
3,034.7
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,
 
2014
 
2013
 
2012
 
(in millions)
Balance at January 1,
$
4,383.9

 
$
3,034.7

 
$
3,525.6

Sales of gas, oil and NGL produced during the period, net of production costs
(1,639.0
)
 
(1,317.9
)
 
(892.3
)
Net change in sales prices and in production (lifting) costs related to future production
726.6

 
1,236.3

 
(2,083.5
)
Net change due to extensions, discoveries and improved recovery
979.9

 
2,230.7

 
948.5

Net change due to revisions of quantity estimates
35.9

 
(709.6
)
 
(387.8
)
Net change due to purchases of reserves in place
695.3

 
36.8

 
831.4

Net change due to sales of reserves in place
(1,153.7
)
 
(73.2
)
 
—

Previously estimated development costs incurred during the period
867.5

 
722.7

 
513.0

Changes in estimated future development costs
409.6

 
(596.5
)
 
(209.3
)
Accretion of discount
597.3

 
402.2

 
499.4

Net change in income taxes
(600.3
)
 
(601.7
)
 
273.6

Other
37.0

 
19.4

 
16.1

Net change
956.1

 
1,349.2

 
(490.9
)
Balance at December 31,
$
5,340.0

 
$
4,383.9

 
$
3,034.7