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 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,
	2013			2012
	(in millions)
Proved properties	$	11,571.4		$	10,234.3
Unproved properties, net	665.1			937.9
Total proved and unproved properties	12,236.5			11,172.2
Accumulated depreciation, depletion and amortization	(4,930.9		)	(4,258.1		)
Net capitalized costs	$	7,305.6		$	6,914.1

Costs Incurred

The costs incurred in oil and gas exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs for $21.4 million and ARO additions and revisions of $17.2 million during the year ended December 31, 2013. The costs incurred to advance the development of reserves that were classified as proved undeveloped were approximately $645.9 million in 2013, $513.0 million in 2012, and $533.6 million in 2011.



	Year Ended December 31,
	2013		2012		2011
	(in millions)
Property acquisitions
Unproved	$	9.3	$	692.6	$	48.0
Proved	31.6		714.4		0.1
Total property acquisitions	40.9		1,407.0		48.1
Exploration (capitalized and expensed)	14.6		14.3		36.5
Development	1,440.8		1,310.0		1,267.8
Total costs incurred	$	1,496.3	$	2,731.3	$	1,352.4

Results of Operations

Following are the results of operations of QEP Energy's oil and gas exploration and development activities, before allocated corporate overhead and interest expenses.



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Revenues ⁽¹⁾	$	1,901.2		$	1,393.4		$	1,703.4
Production costs	583.3			501.1			433.3
Exploration expenses	11.9			11.2			10.5
Depreciation, depletion and amortization	954.2			838.4			707.4
Impairment	93.0			133.0			218.2
Total expenses	1,642.4			1,483.7			1,369.4
Income (loss) before income taxes	258.8			(90.3		)	334.0
Income tax benefit (expense)	(96.3		)	33.6			(119.0		)
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	162.5		$	(56.7	)	$	215.0

___________________________


⁽¹⁾	Revenue for the year ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the years ended December 31, 2013 and 2012, are reflected below operating income (loss) on the Consolidated Statements of Operations. See Note 7 - Derivative Contracts.

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 compliance oversight of a multi-functional reserves review committee responsible to the Company's Board of Directors. QEP Energy's estimated proved reserves have been prepared by Ryder Scott Company, L.P., independent reservoir engineering consultants, 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 Energy's proved undeveloped reserves at December 31, 2013, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves, except for 120 Bcfe located within the northern portion of the Company's Pinedale Anticline leasehold in western Wyoming. Long-term development of gas reserves in the Pinedale Anticline Project Area (PAPA) is governed by the Bureau of Land Management's September 2008, Record of Decision (ROD) on the Final Supplemental Environmental Impact Statements. Under the ROD, QEP Energy is allowed to drill and complete wells year-round in designated concentrated development areas defined in the PAPA. The ROD contains additional requirements and restrictions on the sequence of development of the PAPA, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development of the PAPA that is beyond the control of the Company. The Company has an ongoing development plan for the PAPA and the financial capability to continue development in the manner estimated.

As of December 31, 2013, 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, 2011, 2012 and 2013 are as follows:



	Gas		Oil		NGL		Total
	(Bcf)		(MMbbl)		(MMbbl)		(Bcfe)
Balance at December 31, 2010	2,612.9		52.3		17.4		3,030.7
Revisions of previous estimates⁽⁶⁾	(270.1	)	1.7		39.3		(23.5	)
Extensions and discoveries ⁽⁷⁾	641.9		17.4		22.6		881.6
Purchase of reserves in place	1.9		—		—		2.1
Sale of reserves in place	(0.8	)	(0.2	)	—		(1.9	)
Production	(236.4	)	(3.7	)	(2.7	)	(275.2	)
Balance at December 31, 2011	2,749.4		67.5		76.6		3,613.8
Revisions of previous estimates ⁽³⁾	(240.6	)	(1.5	)	0.7		(244.8	)
Extensions and discoveries ⁽⁴⁾	330.6		17.3		23.0		572.5
Purchase of reserves in place ⁽⁵⁾	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 ⁽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
Proved developed reserves
Balance at December 31, 2010	1,404.8		25.1		9.3		1,611.5
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
Proved undeveloped reserves
Balance at December 31, 2010	1,208.1		27.2		8.0		1,419.2
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

____________________________

⁽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 in some areas and a change in well spacing assumptions in these 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 2012 include negative impacts due to 80.0 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.

⁽⁴⁾

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 Legacy 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.


⁽⁵⁾	Purchase of reserves in place primarily relate to the Company's $1.4 billion 2012 Acquisition as discussed in Note 2 - Acquisitions and Divestitures.

⁽⁶⁾

Revisions of previous estimates in 2011 include 173.7 Bcfe negative impact due to performance revisions offset by 150.2 Bcfe positive impact from other revisions. The 173.7 Bcfe performance revisions were due to the reduction of gas volumes of 209.8 Bcf, partially offset by an increase in NGL volumes of 33.2 MMbbls, which is included in other revisions. The primary reason for the increase in the NGL volumes, or 31.8 MMbbls, relates to the completion of the Blacks Fork II plant and the fee-based processing agreement entered into between QEP Energy and QEP Field Services for QEP Energy's Pinedale production, offset by a reduction in the dry gas reserve related to shrink of about 59.6 Bcf. The remaining performance related reduction in the gas reserves was primarily related to the removal of certain PUD locations in the Haynesville/Cotton Valley area to recognize the 80-acre increased density development plan.

⁽⁷⁾

Extensions and discoveries increased proved reserves by 881.6 Bcfe, primarily related to extensions and discoveries at the Haynesville/Cotton Valley area (358.8 Bcfe), Uinta Basin area (189.1 Bcfe) and Pinedale Anticline area (161.2 Bcfe). All of these extensions and discoveries related to new well completions and associated new PUD locations. Estimates of the quantity of proved reserves from the Company's Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the years ended December 31, 2011 and 2010, because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.

Standardized Measure of Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31, 2013, 2012 and 2011, 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 2013, 2012 and 2011, 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,
	2013		2012		2011
Average benchmark price per unit:
Gas price (per MMbtu)	$	3.67	$	2.76	$	4.12
Oil price (per Bbl)	96.94		94.71		96.19

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 booked proved undeveloped reserves are approximately $852.6 million in 2014, $1,183.8 million in 2015 and $1,094.4 million in 2016.

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



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Future cash inflows	$	24,805.7		$	18,200.2		$	18,300.6
Future production costs	(8,400.3		)	(5,027.2		)	(4,276.1		)
Future development costs	(4,056.7		)	(3,927.3		)	(3,250.0		)
Future income tax expenses	(3,284.6		)	(2,269.0		)	(2,837.1		)
	9,064.1			6,976.7			7,937.4
10% annual discount for estimated timing of net cash flows	(4,680.2		)	(3,942.0		)	(4,411.8		)
Standardized measure of discounted future net cash flows	$	4,383.9		$	3,034.7		$	3,525.6

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



	Year Ended December 31,
	2013			2012			2011
	(in millions)
Balance at January 1,	$	3,034.7		$	3,525.6		$	2,705.6
Sales of gas, oil and NGL produced during the period, net of production costs	(1,317.9		)	(892.3		)	(1,779.9		)
Net change in sales prices and in production (lifting) costs related to future production	1,236.3			(2,083.5		)	1,472.5
Net change due to extensions, discoveries and improved recovery	2,230.7			948.5			1,806.4
Net change due to revisions of quantity estimates	(709.6		)	(387.8		)	(48.2		)
Changes due to purchases of reserves in place	36.8			831.4			0.1
Changes due to sales of reserves in place	(73.2		)	—			(8.0		)
Previously estimated development costs incurred during the period	722.7			513.0			533.6
Changes in estimated future development costs	(596.5		)	(209.3		)	(1,110.4		)
Accretion of discount	402.2			499.4			355.4
Net change in income taxes	(601.7		)	273.6			(411.4		)
Other	19.4			16.1			9.9
Net change	1,349.2			(490.9		)	820.0
Balance at December 31,	$	4,383.9		$	3,034.7		$	3,525.6