Exhibit 99.1

News Release

Investors:	Greg Bensen
	Director, Investor Relations
	303-405-6665
Media:	Noel Ryan
	Director, Corporate Communications
	303-405-6655

QEP RESOURCES REPORTS SECOND QUARTER 2012 FINANCIAL AND OPERATIONAL RESULTS

DENVER — July 31, 2012// QEP Resources, Inc. (NYSE: QEP), reported Adjusted EBITDA (a non-GAAP measure) for the second quarter 2012 of $338.5 million, compared to $336.6 million in the second quarter 2011, a 1% increase.  QEP Resources reported a net loss during the second quarter 2012 of $0.7 million, or $0.00 per diluted share, compared to net income of $92.8 million, or $0.52 per diluted share, in the second quarter 2011.  Net income includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, costs associated with the early extinguishment of debt and non-cash price-related impairment charges.  Excluding these items, the Company’s Adjusted Net Income (a non-GAAP measure) was $54.6 million or $0.31 per diluted share in the second quarter 2012 compared to $75.4 million or $0.42 per diluted share in the second quarter 2011.  The lower Adjusted Net Income is primarily due to decreased natural gas, crude oil, and NGL prices in the second quarter 2012 compared to 2011.  A reconciliation of EBITDA and Adjusted Net Income to net income is provided within the financial tables of this release.

Second Quarter 2012 Highlights

§ QEP Energy reported record net production volumes of 79.6 Bcfe in the second quarter 2012, compared to 64.7 Bcfe in 2011, a 23% increase driven by crude oil and NGL volumes that more than doubled compared to 2011.

§ QEP Energy delivered continued liquids production growth with crude oil and NGL comprising 20% of reported production volumes in the second quarter 2012, compared to 12% of reported production in the second quarter 2011.

§ QEP Field Services’ NGL sales volumes increased by 14%, gathering volumes by 11% and total fee-based processing volumes by 7% in the second quarter 2012 compared to 2011.

“With natural gas prices near the lowest levels in over a decade, we continued to allocate capital to higher-return crude oil and liquids-rich-gas plays during the second quarter,” said Chuck Stanley, Chairman, President and CEO of QEP Resources.  “QEP Energy’s second quarter production was up 23% compared to the same period last year, driven by double-digit growth in each of our five major producing areas.  Crude oil and NGL production more than doubled on a year-over-year basis and represented 20% of QEP Energy’s second quarter 2012 total production.  At QEP Field Services, a 14% year-over-year increase in second quarter NGL sales volumes was more than offset by lower processing and gathering margins.  Despite the downturn in NGL prices, Field Services’ NGL extraction plants continued to run in ethane recovery mode during the quarter due to positive ethane margins resulting from firm transportation and fractionation agreements that give us access to higher value Mont Belvieu NGL markets.”

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QEP Financial Results Summary

ADJUSTED EBITDA BY SUBSIDIARY
	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
	(in millions)
QEP Energy	$	265.7	$	247.7		7	%	$	526.5	$	489.7		8	%
QEP Field Services		71.5		86.9		-18	%		155.8		148.3		5	%
QEP Marketing and other		1.3		2.0		-35	%		1.9		4.4		-57	%
Total Adjusted EBITDA (1)	$	338.5	$	336.6		1	%	$	684.2	$	642.4		7	%

(1) See attached schedule for a reconciliation of Adjusted EBITDA (a non-GAAP measure) to net income.

QEP Energy

§ Natural gas, crude oil and NGL net production increased to 79.6 Bcfe in the second quarter 2012, compared to 64.7 Bcfe in 2011.  Crude oil production increased 50% and NGL production increased 229% in the second quarter 2012 compared to 2011.

§ Adjusted EBITDA increased 7% compared to the second quarter 2011, driven by a 23% increase in production partially offset by decreases in net realized prices of 17% for natural gas, 10% for crude oil and 16% for NGL.

§ Crude oil and NGL revenues increased 56% compared to the second quarter 2011 and represented approximately 52% of field-level production revenues.

§ Capital investment (on an accrual basis) in the first six months of 2012 was $641.5 million.  Investments included $637.5 million in drilling, completion and other expenditures (including $0.1 million of dry hole exploration expense) and $4.0 million in property acquisitions.

§ QEP Energy recorded non-cash impairment charges of $48.9 million in the second quarter 2012 as a result of lower natural gas prices that impacted the carrying value of proved reserves in several Midcontinent Division (Southern Region) successful efforts pools.

§ In conjunction with second quarter results, QEP Energy today provided in a separate release an update on estimated probable and possible reserves and petroleum resource potential on its leasehold.  A summary of these estimates is included in slide 13 of the Q2 Operations Update slides.

§ The Q2 Operations Update slides for the second quarter 2012 with maps and other supporting materials referred to in this release are posted on the Company’s website www.qepres.com.

QEP Field Services

§ QEP Field Services’ Adjusted EBITDA decreased 18% in the second quarter 2012 compared to the prior-year period primarily due to a 24% decrease in net realized NGL prices partially offset by a 14% increase in NGL sale volumes.

§ Capital investment (on an accrual basis) for the first six months of 2012 totaled $85.9 million.

QEP Resources

§ The Company entered into a $300 million senior, unsecured term loan agreement with a group of financial institutions during the second quarter.  The term loan agreement provides for borrowing at short-term rates and contains covenants, restrictions and interest rates that are substantially the same as the Company’s $1.5 billion revolving credit facility. The term loan agreement matures in April 2017, and the maturity date may be extended one year, contingent upon lender approval.  The net proceeds of $298.2 million were used to repay indebtedness under QEP’s credit facility and for general corporate purposes.

§ QEP entered into $300 million of notional amounts in interest rate swaps to minimize the interest rate volatility risk in relation to its $300 million term loan agreement. In the swap transactions, the Company pays a fixed interest rate and receives one-month LIBOR from the counterparties. The interest rate swaps settle monthly and will mature in March 2017.

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QEP 2012 Adjusted EBITDA and Production Guidance

In response to a decline in second-half 2012 crude oil and NGL future prices, QEP Resources has revised its full-year 2012 guidance.  The Company’s guidance incorporates commodity price derivative positions in place on the date of this release and other assumptions summarized in the table below:

Guidance and Assumptions
	2012
	Current Forecast		Previous Forecast
QEP Resources Adjusted EBITDA (millions) (1)	$	1,350 - $1,400	$	1,350 - $1,450
QEP Energy capital investment (millions)	$	1,270 - $1,320	$	1,165 - $1,315
QEP Field Services capital investment (millions)	$	170	$	170
QEP Marketing capital investment (millions)	$	1	$	1
Corporate capital investment (millions)	$	9	$	14
Total QEP Resources capital investment (millions)	$	1,450 - $1,500	$	1,350 - $1,500
QEP Energy production - Bcfe		305 - 310		305 - 310
NYMEX gas price per MMBtu (2)	$	2.25 - $3.25	$	2.00 - $3.00
NYMEX crude oil price per bbl (2)	$	85.00 - $95.00	$	90.00 - $100.00
NYMEX/Rockies basis differential per MMBtu (2)	$	0.20 - $0.15	$	0.20 - $0.15
NYMEX/Midcontinent basis differential per MMBtu (2)	$	0.15 - $0.10	$	0.20 - $0.15

(1) Due to the forward-looking nature of this non-GAAP financial measure for future periods, information to reconcile it to the most directly comparable GAAP financial measure is not available at this time as management is unable to project special items or mark-to-market adjustments for future periods.

(2) For remaining 2012 forecasted volumes that are not protected by commodity price derivative contracts.  See attached schedule at the end of this release for summary of Commodity Derivative Positions in place on the date of this release.

QEP Operations Summary

QEP Energy

Pinedale Anticline:  Approximately 100 new well completions for the full-year 2012

During the second quarter 2012, the Company’s net production at Pinedale averaged 260 MMcfed.  As a result of a fee-based processing agreement entered into between QEP Energy and QEP Field Services in 2011, QEP Energy’s average net equivalent production for the second quarter 2012 was 23% oil and NGL compared to 5% in the second quarter 2011.

Drilling and completion efficiencies have allowed QEP to maintain industry-leading average gross completed well costs of approximately $4.1 million per well at Pinedale.  Average drill time from spud to total depth during the first half of 2012 was 13.4 days. A new QEP drill time record of 9.8 days was set during the second quarter 2012.

QEP’s average completed well cost has increased slightly in 2012, due primarily to an increase in the number of fracture stimulation stages and stage size.  The fracture stimulation stages target additional pay in the Mesaverde Formation.  The optimized completion design has resulted in wells with higher initial production rates and no perceptible change in decline which indicates recovery of incremental reserves at a finding and development cost of less than $0.60/Mcfe.

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In response to current natural gas and NGL prices, the Company has elected to defer completion of some Pinedale wells until 2013.  For the full-year 2012, the Company now expects to complete approximately 100 wells.

QEP normally suspends Pinedale completion operations during the coldest months of the winter, generally from December to mid-March.  In 2012, completion operations resumed in early March, and year-to-date QEP has completed and turned to sales 61 new wells with an average working interest of 71%.  There are currently 45 wells that have been drilled and cased that are awaiting completion.

Please refer to slide 5 of the Q2 2012 Operations Update for additional details on the Company’s Pinedale operations.

Uinta Basin:  Continued development drilling in the liquids-rich Lower Mesaverde Play

During the second quarter 2012, total Uinta Basin production averaged 65 MMcfed of which 19 MMcfed was from the Lower Mesaverde play. QEP has two operated rigs drilling vertical wells targeting liquids-rich gas in stacked discontinuous sands in the Lower Mesaverde Formation.

The Company currently holds over 32,000 net acres of leasehold which it believes are prospective for development of the Lower Mesaverde.  Most of the Company’s acreage is within the Red Wash Unit, where QEP owns a 100% working interest (86.5% net revenue interest).  If the Company determines 10-acre well density is appropriate for full development of the Lower Mesaverde play, QEP could have an inventory of up to 3,200 potential well locations.  Natural gas production from the Lower Mesaverde averages 1,117 Btu per cubic foot at the wellhead, with an average cryogenic processing NGL yield of 2.2 GPM (gallons of NGL per inlet Mcf).

QEP has commenced construction of two “Pinedale-style” multi-well pads in the play and plans to initially drill 20-acre density development wells from an average of two pads per square mile.  The pads and wellbore geometries will be designed to allow for future 10-acre density development wells.  Average measured depth for a typical Lower Mesaverde well in the play is approximately 11,000 feet.

The Company currently has 44 producing wells in the play, 24 of which were completed during 2012.  QEP intends to complete approximately 40 wells in the play during 2012 at an estimated gross completed well cost of approximately $2.3 million per well.  The Company estimates average gross ultimate recoverable reserves of 2.3 Bcfe per well.

QEP is also operating a third rig in the Uinta Basin that is drilling horizontal and vertical wells targeting multiple oil-bearing limestone and sandstone reservoirs within the lower Green River Formation, at an average drill depth of 5,500 feet.  QEP plans to complete approximately 11 oil wells during 2012 within the Uinta Basin, with an average working interest of 69%.

Slides 6 and 7 of the Q2 2012 Operations Update depict QEP’s acreage and additional details of the Lower Mesaverde play.

Williston Basin:  Continued growth in crude oil production on 90,000 acre Bakken/Three Forks leasehold

In the Williston Basin of North Dakota, the Company currently operates 37 producing wells, including 31 Bakken wells and six Three Forks Formation wells, and has a working interest in 118 producing outside-operated wells.  During the second quarter 2012, the Company’s Bakken/Three Forks net production averaged 6,088 Boe/day.

The Company completed and turned to sales five new Company-operated Bakken Formation wells since the last operations update.  QEP had an average 80% working interest in the recently completed wells.

QEP has four operated wells currently being drilled (including one well at intermediate casing) and nine Company-operated wells that have been drilled to total depth, cased and are waiting on completion.  QEP has an average 85% working interest in these operated wells that are drilling or waiting on completion.  Completion operations on five of the nine wells should commence during August of 2012.  Completion of all wells drilled from a pad (or a well-pod on a pad) will be delayed until all wells have been drilled and cased. The Company also has interests in 12 outside-operated wells currently being drilled and 12 outside-operated wells that are drilled and cased and waiting on completion.  The Company’s working interest in these outside-operated wells ranges from less than 1% to 30%.

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The Company currently has three rigs operating in the Bakken/Three Forks play.  A fourth rig was released earlier this month due to a combination of factors, including a delay in timely receipt of drilling permits on the Fort Berthold Reservation, the recent decline in crude oil prices, and increased well costs.  QEP currently estimates that completed well costs for a typical long-lateral Bakken/Three Forks well will average approximately $11 million for the balance of 2012. The majority of the increase in average completed well costs is due to expenses associated with water handling costs on the Fort Berthold Reservation.  Efforts are currently underway to lower water handling costs on the Reservation to a level consistent with that in other parts of the Bakken play.

Slide 8 of the Q2 2012 Operations Update shows QEP’s acreage and activity in the Bakken/Three Forks play.

Powder River Basin:  QEP completes first operated Sussex Formation crude oil well; one waiting on completion and one drilling

In the Powder River Basin of Wyoming, QEP has completed and turned to sales one Company-operated horizontal Sussex Formation oil well, the Hardy 4-23-39-74SXH well, in which QEP has a 33% working interest. The well was completed in late June, and produced at a peak 24-hour rate of 1,606 Boe/day (90% oil).  The Hardy 16-14-39-74SXH well, in which QEP has a 46% working interest, has been drilled and cased and should be completed in August 2012.  A third QEP-operated Sussex well, the Hardy 12-26H, in which QEP has a 35% working interest, is currently being drilled. In addition to recent QEP-operated activity, the Company also has an average 22% working interest in two outside-operated horizontal Sussex Formation wells that have been on production for more than one year.

QEP currently estimates average gross completed well costs of approximately $6.5 - $7 million and estimated ultimate recoveries of 450 to 525 Mboe for a typical horizontal Sussex well.  QEP has approximately 39,000 net leasehold acres in the Spearhead Ranch area of the Powder River Basin and intends to drill additional wells targeting the Sussex Formation, as well as other zones, including the Shannon, Niobrara and Frontier formations.

Slide 9 of the Q2 2012 Operations Update shows QEP’s acreage and activity in the Powder River Basin oil play.

Woodford “Cana”:  Currently operating 29 producing wells, with working interests in more than 200 others

During the second quarter 2012, QEP’s net production from the Woodford “Cana” play averaged 53 MMcfed.

QEP currently operates 29 producing horizontal Cana wells and has working interests in an additional 225 producing Cana wells that are operated by others.

Since the last operations update, the Company completed and turned to sales ­two new QEP-operated horizontal Woodford “Cana” Shale wells located in western Oklahoma in which the Company has an average 57% working interest.  In addition, the Company participated in 18 additional completed wells operated by others in which QEP has working interests ranging from less than 1% to 25%.

QEP has three operated rigs currently drilling 80-acre development wells within a single section. QEP has a 100% working interest in this unit.  Also, there are three wells in the section waiting on completion. The Company has interests in seven wells that are currently being drilled and 28 outside-operated wells that are waiting on completion.  The Company’s working interest in the outside-operated wells ranges from less than 1% to 51%.QEP intends to operate two to three rigs for the balance of 2012 in the liquids-rich gas portion of the core of the Cana play, with the majority of the Company’s activity focused on development drilling on 80-acre density.

Slide 10 of the Q2 2012 Operations Update depicts QEP’s acreage and additional details on the Cana play.

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Granite Wash, Marmaton and Tonkawa horizontal development in the Texas Panhandle and Western Oklahoma

During the second quarter 2012, net production from the Texas Panhandle Granite Wash play (vertical and horizontal wells) averaged 36 MMcfed.  QEP has a working interest in a total of 83 producing horizontal Granite Wash/Atoka Wash wells.

The Company is currently completing one QEP-operated horizontal well in Wheeler County, Texas, the Jolly 21-7H well, a Missourian Kansas City Formation test and has participated in eight outside-operated Granite Wash wells in the Texas Panhandle that were completed since the last operations update with working interests ranging from 5% to 33%.  QEP has working interests ranging from 1% to 51% in four outside-operated wells that are waiting on completion and has a 51% working interest in one well that is currently drilling.

In addition, since the last update, QEP has completed one Marmaton oil well with a peak 24-hour rate of 423 Boe/day in which the Company has a 95% working interest and is currently completing one Marmaton well (80% working interest).  The Company has one Marmaton well drilling (99% working interest) and one waiting on completion (96% working interest).  The Company has also completed two new Tonkawa (average 63% working interest) horizontal oil wells, which had an average peak 24-hour rate of 356 Boe/day.  In addition, the Company has an average 16% working interest in two outside-operated Tonkawa wells that are waiting on completion.

See slide 11 of the Q2 2012 Operations Update for details on the Granite Wash play.

Haynesville:  Last QEP operated rig released in the Haynesville Shale play of NW Louisiana

During the second quarter 2012, the Company’s Haynesville net production averaged 297 MMcfed and Cotton Valley/Hosston net production averaged 43 MMcfed.  In response to current natural gas prices, QEP has released its last operated drilling rig in the Haynesville Shale play and has not completed any additional Company-operated Haynesville wells since the last update.  The Company currently operates 126 producing wells in the play and has a working interest in 126 producing wells that are operated by others.  QEP has five operated wells drilled and cased (48% working interest) and currently plans to defer completion of these wells until 2013. The Company participated with a 6% working interest in one outside-operated Haynesville well that was turned to sales since the last operations update.

Refer to slide 12 of the Q2 2012 Operations Update for additional information on QEP’s Haynesville activities.

QEP Field Services

Field Services’ second quarter 2012 gathering volumes were up 11%, NGL sales volumes were up 14%, and fee-based processing volumes were up 7% compared to the prior-year quarter.

Processing margin (total processing plant revenues less plant operating expenses, shrink and transportation) was $33.1 million in the second quarter 2012 compared to $42.8 million in the second quarter 2011, a 23% decline, primarily due to a decrease in the average net realized NGL sales price to the plant (NGL sales price less transportation and fractionation expenses) of 50% between the two periods.

Gathering margin (total gathering revenues less gathering related operating expenses) of $46.8 million during the second quarter 2012 decreased by 9% compared to the second quarter 2011, driven primarily by decreased other gathering revenue related to the elimination of a third-party interruptible processing agreement for certain gas volumes in the Northern Region.  The short-term processing arrangement was in effect through the second quarter 2011 before the expansion of the Blacks Fork processing plant was put into service in the third quarter 2011.

Approximately 78% of Field Services’ second quarter 2012 net operating revenue was derived from fee-based gathering and processing activities compared to 69% in the second quarter 2011.

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Construction on Iron Horse II, a 150 MMcfed cryogenic gas processing plant in the Uinta Basin, is proceeding as planned.  The plant should be operational by early 2013.  Fifty percent of the processing capacity in this new facility is contracted to a third-party customer with the remaining capacity available to QEP Energy and other third-party customers.

During the second quarter, Field Services commenced construction on its planned 10,000 Bbl per day NGL fractionator expansion at QEP’s Blacks Fork plant in southwestern Wyoming. When complete in mid-2013, NGL fractionation capacity at Blacks Fork will total 15,000 barrels per day.  To support this expansion, QEP is doubling existing railcar loading capacity at Blacks Fork to facilitate access to what are often higher-value local, regional, and national NGL markets.

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Second Quarter 2012 Results Conference Call

QEP Resources’ management will discuss second quarter 2012 results in a conference call on Wednesday, August 1, 2012 beginning at 11:00 a.m. EDT.  The conference call can be accessed at www.qepres.com.  You may also participate in the conference call by dialing (888) 813-5202 in the U.S. or Canada and (706) 902-0993 for international calls, and then entering the conference ID # 10340516.  A replay of the teleconference will be available on the website immediately after the call through August 15, 2012, or by dialing (855) 859-2056 in the U.S. or Canada and (404) 537-3406 for international calls, and then entering passcode 10340516.  In addition, QEP’s Second Quarter Operations Update Slides, with updated maps showing QEP’s leasehold and current activity for key operating areas discussed in this release, can be found on the Company’s website.

About QEP Resources, Inc.

QEP Resources, Inc. (NYSE: QEP) is a leading independent natural gas and crude oil exploration and production company focused in two major regions: the Northern Region (primarily in the Rockies) and the Southern Region (primarily Oklahoma, Louisiana, and the Texas Panhandle) of the United States.  QEP Resources also gathers, compresses, treats, processes and stores natural gas.  For more information, visit QEP Resources’ website at: www.qepres.com.

Forward-Looking Statements

This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended.  Forward-looking statements can be identified by words such as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,” “expects,” “should,” “will” or other similar expressions.  Such statements are based on management’s current expectations, estimates and projections, which are subject to a wide range of uncertainties and business risks.  These forward-looking statements include statements regarding:  forecasted Adjusted EBITDA, production and capital investment for 2012 and related assumptions for such guidance; number of rigs planned in operating areas; estimated number of wells to be completed; estimated gross completed well costs; average estimated ultimate recoveries per well; completion dates for new projects of QEP Field Services.  Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to:  the availability of capital; changes in local, regional, national and global demand for natural gas, oil and NGL; natural gas, NGL and oil prices; potential legislative or regulatory changes regarding the use of hydraulic fracture stimulation; impact of new laws and regulations, including the implementation of the Dodd-Frank Act; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; weather conditions; changes in maintenance and construction costs and possible inflationary pressures; permitting delays; the availability and cost of credit; and the other risks discussed in the Company’s periodic filings with the Securities and Exchange Commission, including the Risk Factors section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.  QEP Resources undertakes no obligation to publicly correct or update the forward-looking statements in this news release, in other documents, or on the website to reflect future events or circumstances.  All such statements are expressly qualified by this cautionary statement.

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Disclosures regarding Estimated Ultimate Recovery (EUR)

The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions.  The SEC permits optional disclosure of probable and possible reserves, however QEP has made no such disclosures in our filings with the SEC.  QEP uses certain terms in our periodic news releases and other presentation materials such as “estimated ultimate recovery” or “EUR”, “resource potential”, and “net resource potential”.  These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially more risks of actually being realized.  The SEC guidelines strictly prohibit us from including such estimates in filings with the SEC.  Investors are urged to closely consider the disclosures about the Company’s reserves in its Annual Report on Form 10-K for the year ended December 31, 2011, and in other reports on file with the SEC.

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QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUES (1) (2)	(in millions, except per share amounts)
Natural gas sales	$	138.9		$	298.7		$	300.1		$	611.3
Oil sales		107.2			80.7			218.0			143.7
NGL sales		82.1			63.8			179.5			111.7
Gathering, processing and other		45.8			58.9			95.6			105.5
Purchased gas, oil and NGL sales		125.3			306.0			309.3			453.8
Total Revenues		499.3			808.1			1,102.5			1,426.0
OPERATING EXPENSES
Purchased gas, oil and NGL expense		124.9			303.9			313.3			450.6
Lease operating expense		40.5			34.3			80.6			67.1
Natural gas, oil and NGL transportation and other handling costs (1)		40.7			24.0			75.2			45.7
Gathering, processing and other		20.6			27.2			44.3			52.4
General and administrative		36.8			28.7			72.8			60.4
Production and property taxes		19.4			27.1			44.1			50.8
Depreciation, depletion and amortization		214.1			186.6			413.3			377.4
Exploration expenses		2.1			2.3			4.1			5.1
Abandonment and impairment		55.7			5.3			62.3			10.7
Total Operating Expenses		554.8			639.4			1,110.0			1,120.2
Net gain from asset sales		-			0.2			1.5			0.2
OPERATING INCOME (LOSS)		(55.5	)		168.9			(6.0	)		306.0
Realized and unrealized gains on derivative contracts(2)		82.3			-			298.6			-
Interest and other income		0.9			(0.4	)		2.6			0.2
Income from unconsolidated affiliates		1.4			1.3			3.3			2.2
Loss from early extinguishment of debt		(0.6	)		-			(0.6	)		-
Interest expense		(28.2	)		(22.1	)		(52.9	)		(44.2	)
INCOME BEFORE INCOME TAXES		0.3			147.7			245.0			264.2
Income taxes		(0.1	)		(54.2	)		(88.8	)		(96.9	)
NET INCOME		0.2			93.5			156.2			167.3
Net income attributable to noncontrolling interest		(0.9	)		(0.7	)		(1.7	)		(1.3	)
NET INCOME (LOSS) ATTRIBUTABLE TO QEP	$	(0.7	)	$	92.8		$	154.5		$	166.0
Earnings Per Common Share Attributable to QEP
Basic total	$	-		$	0.52		$	0.87		$	0.94
Diluted total	$	-		$	0.52		$	0.87		$	0.93
Weighted-average common shares outstanding
Used in basic calculation		177.7			176.6			177.6			176.4
Used in diluted calculation		177.7			178.6			178.5			178.5

(1) During the fourth quarter 2011, QEP revised its reporting of transportation and handling costs.  Transportation and handling costs, previously netted against revenues, have been recast on the Condensed Consolidated Income Statement from revenues to “Natural gas, oil and NGL transportation and other handling costs” for the 2011 periods presented herein.

(2) In addition, on January 1, 2012, QEP discontinued hedge accounting.  During the first and second quarters of 2012, commodity derivative realized gains and losses from derivative contract settlements were included in “Realized and unrealized gains on derivative contracts” on the Condensed Consolidated Income Statement.  Conversely, during the first and second quarters of 2011, the commodity derivative realized gains and losses on settlements were included in each of the respective revenue categories in the Condensed Consolidated Income Statement, in conjunction with hedge accounting and the realization of the underlying contract.

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QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)	June 30,			December 31,
	2012			2011
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	146.4		$	-
Accounts receivable, net		236.9			397.4
Fair value of derivative contracts		268.2			273.7
Inventories, at lower of average cost or market
Gas, oil and NGL		11.6			16.2
Materials and supplies		90.0			87.6
Prepaid expenses and other		42.5			43.7
Total Current Assets		795.6			818.6
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties		8,822.3			8,172.4
Unproved properties, not being depleted		305.4			326.8
Midstream field services		1,550.1			1,463.6
Marketing and other		53.6			49.8
Total Property, Plant and Equipment		10,731.4			10,012.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production		3,763.7			3,339.2
Midstream field services		327.8			297.5
Marketing and other		16.3			14.6
Total Accumulated Depreciation, Depletion and Amortization		4,107.8			3,651.3
Net Property, Plant and Equipment		6,623.6			6,361.3
Investment in unconsolidated affiliates		41.9			42.2
Goodwill		59.5			59.5
Fair value of derivative contracts		76.2			123.5
Other noncurrent assets		40.8			37.6
TOTAL ASSETS	$	7,637.6		$	7,442.7
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	-		$	29.4
Accounts payable and accrued expenses		373.8			457.3
Production and property taxes		47.2			40.0
Interest payable		33.0			24.4
Fair value of derivative contracts		2.3			1.3
Deferred income taxes		31.0			85.4
Total Current Liabilities		487.3			637.8
Long-term debt		1,866.6			1,679.4
Deferred income taxes		1,563.1			1,484.7
Asset retirement obligations		172.2			163.9
Fair value of derivative contracts		2.4			-
Other long-term liabilities		129.8			124.8
Commitments and contingencies
EQUITY
Common stock		1.8			1.8
Treasury stock		(24.0	)		(13.1	)
Additional paid-in capital		450.4			431.4
Retained earnings		2,820.7			2,673.5
Accumulated other comprehensive income		118.1			207.9
Total Common Shareholders' Equity		3,367.0			3,301.5
Noncontrolling interest		49.2			50.6
Total Equity		3,416.2			3,352.1
TOTAL LIABILITIES AND EQUITY	$	7,637.6		$	7,442.7

11

QEP RESOURCES, INC.

CONSOLIDATED CASH FLOWS

(Unaudited)	Six Months Ended June 30,
	2012			2011
OPERATING ACTIVITIES	(in millions)
Net income	$	156.2		$	167.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		413.3			377.4
Deferred income taxes		77.1			95.7
Abandonment and impairment		62.3			10.7
Share-based compensation		12.3			10.8
Amortization of debt issuance costs and discounts		2.4			1.5
Dry exploratory well expense		0.1			0.5
Net gain from asset sales		(1.5	)		(0.2	)
Income from unconsolidated affiliates		(3.3	)		(2.2	)
Distributions from unconsolidated affiliates and other		3.5			2.6
Loss on early extinguishment of debt		0.1			-
Unrealized gain on derivative contracts		(89.9	)		(58.8	)
Changes in operating assets and liabilities		61.7			23.3
Net Cash Provided by Operating Activities of Continuing Operations		694.3			628.6
INVESTING ACTIVITIES
Property acquisitions		(4.0	)		(29.8	)
Property, plant and equipment, including dry exploratory well expense		(681.5	)		(632.0	)
Proceeds from disposition of assets		3.6			1.6
Net Cash Used in Investing Activities of Continuing Operations		(681.9	)		(660.2	)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances		(29.4	)		(1.5	)
Long-term debt issued		800.0			-
Long-term debt issuance costs paid		(8.8	)		-
Long-term debt repaid		(6.7	)		(58.5	)
Proceeds from credit facility		194.5			200.0
Repayments of credit facility		(801.0	)		(100.0	)
Other capital contributions		(6.4	)		(0.4	)
Dividends paid		(7.1	)		(7.1	)
Excess tax benefit from share-based compensation		2.0			1.4
Distribution from Questar		-			0.2
Distribution to noncontrolling interest		(3.1	)		(2.5	)
Net Cash Provided by Financing Activities of Continuing Operations		134.0			31.6
Change in cash and cash equivalents		146.4			-
Beginning cash and cash equivalents		-			-
Ending cash and cash equivalents	$	146.4		$	-

12

QEP RESOURCES, INC.

OPERATIONS BY LINE OF BUSINESS

(Unaudited)

QEP Energy - Production by Region
	Three months ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
	(in Bcfe)
Southern Region
Haynesville/Cotton Valley		30.9		25.8		20	%		58.9		54.1		9	%
Midcontinent		12.6		11.1		14	%		25.2		21.6		17	%
Total Southern Region		43.5		36.9		18	%		84.1		75.7		11	%
Northern Region
Pinedale Anticline		23.7		17.8		33	%		45.9		34.0		35	%
Uinta Basin (1)		5.9		5.0		18	%		10.5		11.4		-8	%
Legacy		6.5		5.0		30	%		13.3		9.5		40	%
Total Northern Region		36.1		27.8		30	%		69.7		54.9		27	%
Total production		79.6		64.7		23	%		153.8		130.6		18	%

(1) Includes 1.6 Bcfe from the first quarter 2011 production from prior periods due to change in ownership interest in a federal unit.

QEP Energy - Total Production

	Three months ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
	(in Bcfe)
QEP Energy production volumes
Natural gas (Bcf)		64.0		57.0		12	%		123.5		116.1		6	%
Oil (Mbbl)		1,308.0		873.6		50	%		2,530.5		1,636.6		55	%
NGL (Mbbl)		1,297.8		394.3		229	%		2,519.5		780.6		223	%
Total production (Bcfe)		79.6		64.7		23	%		153.8		130.6		18	%
Average daily production (MMcfe)		875.1		710.8		23	%		845.1		721.7		17	%

13

QEP Energy - Prices (1)

	Three months ended June 30,							Six Months Ended June 30,
	2012 (2)		2011 (3)		Change			2012 (2)			2011 (3)		Change
Natural gas (per Mcf)
Average field-level price	$	2.17	$	4.11				$	2.43		$	4.08
Commodity derivative impact		1.75		0.64					1.60			0.68
Net realized price	$	3.92	$	4.75		-17	%	$	4.03		$	4.76		-15	%
Oil (per bbl)
Average field-level price	$	81.90	$	92.24				$	86.14		$	87.73
Commodity derivative impact		1.70		0.14					(0.19	)		0.08
Net realized price	$	83.60	$	92.38		-10	%	$	85.95		$	87.81		-2	%
NGL (per bbl)
Average field-level price	$	35.27	$	44.22				$	37.98		$	45.86
Commodity derivative impact		2.04		-					1.23			-
Net realized price	$	37.31	$	44.22		-16	%	$	39.21		$	45.86		-15	%

(1) Recast to reflect exclusion of natural gas, oil and NGL transportation and other handling costs.

(2) Reported in revenues in the consolidated income statement.

(3) Reported below operating income in the consolidated income statement.

QEP Energy - Operating Expenses

	Three months ended June 30,							Six Months Ended June 30,
	2012		2011		Change			2012		2011		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.48	$	2.67		-7	%	$	2.47	$	2.68		-8	%
Lease operating expense		0.52		0.54		-4	%		0.53		0.52		2	%
Natural gas, oil and NGL transportation and other handling costs		0.72		0.65		11	%		0.70		0.66		6	%
General and administrative expense		0.37		0.35		6	%		0.40		0.36		11	%
Allocated interest expense		0.29		0.32		-9	%		0.31		0.31		0	%
Production taxes		0.23		0.39		-41	%		0.27		0.37		-27	%
Total Operating Expenses	$	4.61	$	4.92		-6	%	$	4.68	$	4.90		-4	%

14

QEP Field Services

	Three Months Ended June 30,									Six Months Ended June 30,
	2012			2011			Change			2012			2011			Change
QEP Field Services Gathering Operating Statistics
Natural gas gathering volumes  (millions of MMBtu)		133.9			121.1			11	%		257.6			240.1			7	%
Gathering revenue (per MMBtu)	$	0.34		$	0.32			6	%	$	0.34		$	0.33			3	%
QEP Field Services Gathering Margin
Gathering	$	45.8		$	38.7			18	%	$	87.7		$	78.1			12	%
Other Gathering		9.3			25.0			-63	%		20.6			42.7			-52	%
Gathering (expense)		(8.3	)		(12.4	)		-33	%		(17.9	)		(24.3	)		-26	%
Gathering Margin	$	46.8		$	51.3			-9	%	$	90.4		$	96.5			-6	%
QEP Field Services Processing Margin
NGL sales	$	36.3		$	46.3			-22	%	$	83.8		$	75.8			11	%
Realized gains from derivative contract settlements		3.3			-			-			4.4			-			-
Processing (fee-based) revenues		17.6			12.2			44	%		33.6			22.2			51	%
Other processing fees		-			-			-			3.0			-			-
Processing expense		(3.7	)		(3.1	)		19	%		(7.4	)		(5.8	)		28	%
Processing plant fuel and shrinkage expense		(8.4	)		(11.4	)		-26	%		(18.5	)		(21.6	)		-14	%
Natural gas, oil and NGL transportation and other handling costs		(12.0	)		(1.2	)		900	%		(20.8	)		(2.1	)		890	%
Processing margin	$	33.1		$	42.8			-23	%	$	78.1		$	68.5			14	%
Keep-whole processing margin (1)	$	19.2		$	33.7			-43	%	$	48.9		$	52.1			-6	%
QEP Field Services Processing Operating Statistics
Natural gas processing volumes
NGL sales (MMgal)		41.4			36.4			14	%		86.6			64.2			35	%
Average net realized NGL sales price    (per gal)	$	0.96		$	1.27			-24	%	$	1.02		$	1.18			-14	%
Total fee-based processing volumes    (in millions of MMBtu)		64.5			60.3			7	%		124.2			117.3			6	%
Average fee-based processing revenue  (per MMBtu)	$	0.27		$	0.21			29	%	$	0.27		$	0.19			42	%

(1) NGL sales less processing plant fuel and shrink less natural gas, oil and NGL transportation and other handling costs.

15

QEP RESOURCES, INC.

NON-GAAP MEASURES

(Unaudited)

This release also contains reference to a non-GAAP measure of Adjusted EBITDA.  Management defines Adjusted EBITDA as net income before the following items: unrealized gains and losses on derivative contracts, gains and losses from asset sales, interest and other income, income taxes, interest expense, depreciation, depletion, and amortization, abandonment and impairment, exploration expense and loss on early extinguishment of debt.  Management uses Adjusted EBITDA to assess the Company's operating results.  Management believes Adjusted EBITDA is an important measure of the Company's cash flow and liquidity and its ability to incur and service debt, fund capital expenditures and make distributions to shareholders and is an important measure for comparing the Company's financial performance to other gas and oil producing companies.  In addition, Adjusted EBITDA is a part of the Company's debt covenants as defined in its revolving credit agreement and term loan agreement.

The following table reconciles QEP Resources’ and its subsidiaries’ net income to Adjusted EBITDA:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
QEP Energy	(in millions)
Net income (loss) attributable to QEP Energy	$	(30.3	)	$	46.8		$	77.8		$	89.9
Net income attributable to noncontrolling interest		-			-			-			-
Net income (loss)		(30.3	)		46.8			77.8			89.9
Unrealized gain on derivative contracts		34.9			(27.6	)		(88.8	)		(58.8	)
Net gain from asset sales		-			(0.2	)		(1.5	)		(0.2	)
Interest and other income		(0.7	)		0.5			(2.4	)		(0.2	)
Income taxes		(16.6	)		27.7			47.7			53.3
Interest expense		23.4			20.4			47.0			40.3
Depreciation, depletion and amortization		197.2			172.5			380.3			349.6
Abandonment and impairment		55.7			5.3			62.3			10.7
Exploration		2.1			2.3			4.1			5.1
Adjusted EBITDA	$	265.7		$	247.7		$	526.5		$	489.7

QEP Field Services
Net income attributable to QEP Field Services	$	33.3		$	44.2		$	78.7		$	72.2
Net income attributable to noncontrolling interest		0.9			0.7			1.7			1.3
Net income		34.2			44.9			80.4			73.5
Unrealized gain on derivative contracts		(1.5	)		-			(4.5	)		-
Net gain from asset sales		-			(0.1	)		-			(0.1	)
Interest and other income		(0.1	)		-			(0.1	)		-
Income taxes		19.2			25.5			42.7			41.6
Interest expense		3.6			3.1			5.9			6.6
Depreciation, depletion and amortization		16.1			13.5			31.4			26.7
Adjusted EBITDA	$	71.5		$	86.9		$	155.8		$	148.3

16

QEP Marketing and other
Net income (loss) attributable to QEP Marketing and other	$	(3.7	)	$	1.8		$	(2.0	)	$	3.9
Net income attributable to noncontrolling interest		-			-			-			-
Net income (loss)		(3.7	)		1.8			(2.0	)		3.9
Unrealized gain on derivative contracts		5.0			-			3.4			-
Net gain from asset sales		-			0.1			-			0.1
Interest and other income		(0.1	)		(0.1	)		(0.1	)		-
Income taxes		(2.5	)		1.0			(1.6	)		2.0
Interest expense		1.2			(1.4	)		-			(2.7	)
Loss on early extinguishment of debt		0.6			-			0.6			-
Depreciation, depletion and amortization		0.8			0.6			1.6			1.1
Adjusted EBITDA	$	1.3		$	2.0		$	1.9		$	4.4

QEP Resources
Net income (loss) attributable to QEP Resources	$	(0.7	)	$	92.8		$	154.5		$	166.0
Net income attributable to noncontrolling interest		0.9			0.7			1.7			1.3
Net income		0.2			93.5			156.2			167.3
Unrealized gain on derivative contracts		38.4			(27.6	)		(89.9	)		(58.8	)
Net gain from asset sales		-			(0.2	)		(1.5	)		(0.2	)
Interest and other income		(0.9	)		0.4			(2.6	)		(0.2	)
Income taxes		0.1			54.2			88.8			96.9
Interest expense		28.2			22.1			52.9			44.2
Loss on early extinguishment of debt		0.6			-			0.6			-
Depreciation, depletion and amortization		214.1			186.6			413.3			377.4
Abandonment and impairment		55.7			5.3			62.3			10.7
Exploration		2.1			2.3			4.1			5.1
Adjusted EBITDA	$	338.5		$	336.6		$	684.2		$	642.4

17

This release also contains reference to a non-GAAP measure of Adjusted Net Income.  Management defines Adjusted Net Income as earnings excluding gains and losses from asset sales, non-cash price-related asset impairments, costs from early extinguishment of debt and unrealized gains and losses on derivative contracts.  Management believes Adjusted Net Income is an important measure of the Company’s operational performance relative to other gas and oil producing companies.

The following table reconciles net income attributable to QEP Resources’ to Adjusted Net Income:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions, except earnings per share)
Net income (loss) attributable to QEP Resources	$	(0.7	)	$	92.8		$	154.5		$	166.0
Adjustments to net income
Net (gain) from asset sales		-			(0.2	)		(1.5	)		(0.2	)
Income taxes on net (gain) on asset sales		-			0.1			0.6			0.1
Unrealized (gain)/loss on derivative contracts		38.4			(27.6	)		(89.9	)		(58.8	)
Income taxes on unrealized (gain)/loss on derivative contracts		(14.2	)		10.3			33.5			21.9
Loss from early extinguishment of debt		0.6			-			0.6			-
Income taxes on loss from early extinguishment of debt		(0.2	)		-			(0.2	)		-
Non-cash price-related impairment charge		48.9			-			49.3			-
Income taxes on non-cash price-related impairment charge		(18.2	)		-			(18.3	)		-
Total after-tax adjustments to net income		55.3			(17.4	)		(25.9	)		(37.0	)
Adjusted Net Income attributable to QEP Resources	$	54.6		$	75.4		$	128.6		$	129.0
EARNINGS PER COMMON SHARE ATTRIBUTABLE TO QEP RESOURCES
Diluted earnings per share	$	-		$	0.52		$	0.87		$	0.93
Diluted after-tax adjustments to net income per share		0.31			(0.10	)		(0.15	)		(0.21	)
Diluted Adjusted Net Income per share	$	0.31		$	0.42		$	0.72		$	0.72
Weighted-Average Common Shares Outstanding Diluted
Diluted (1)		178.6			178.6			178.5			178.5
Weighted Average Common Shares Outstanding Diluted Non-GAAP Reconciliation (1)
Weighted-Average Common Shares Outstanding used in GAAP diluted calculation		177.7
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan		0.9
Weighted-Average Common Shares Outstanding used in Non-GAAP diluted calculation		178.6

(1) The three months ended June 30, 2012, diluted common shares outstanding for purposes of calculating Diluted Adjusted Net Income per share include potential increases in shares that could result from the exercise of in-the-money stock options.  These potential shares are excluded for the three months ended June 30, 2012, in calculating earnings-per-share for GAAP purposes because the effect is antidilutive.

18

The following table presents remaining 2012 derivative positions as of July 27, 2012:

QEP Energy Commodity Derivatives Positions - July 27, 2012

					Swaps		Collars
Year	Type of Contract	Index	Total  Volumes		Average price  per unit		Floor  price		Ceiling  price
			(in millions)
Natural gas sales (MMbtu)
2012	Swap	NYMEX		39.9	$	4.66
2012	Swap	IFPEPL		4.9		4.14
2012	Swap	IFNPCR		45.4		4.61
2012	Swap	IFCNPTE		5.5		2.66
2013	Swap	NYMEX		29.2		3.68
2013	Swap	IFNPCR		65.7		5.66
Oil sales (Bbls)
2012	Swap	NYMEX WTI		0.9	$	97.03
2012	Collar	NYMEX WTI		0.7			$	87.50	$	115.36
2013	Swap	NYMEX WTI		0.9		104.12
Ethane sales (Gals)
2012	Swap	Mt. Belvieu Ethane		7.7	$	0.64
Propane sales (Gals)
2012	Swap	Mt. Belvieu Propane		11.6	$	1.28

 QEP Field Services Commodity Derivative Positions - July 27, 2012

Year	Type of Contract	Index	Total Volumes		Average  Swap price per unit
			(in millions)
Ethane sales (Gals)
2012	Swap	Mt. Belvieu Ethane		7.7	$	0.64
Propane sales (Gals)
2012	Swap	Mt. Belvieu Propane		3.9	$	1.28

QEP Marketing Commodity Derivative Positions - July 27, 2012

Year	Type of Contract	Index	Total Volumes		Average  Swap price  per unit
			(in millions)
Natural gas sales (MMbtu)
2012	Swap	IFNPCR		1.8	$	4.06
2013	Swap	IFNPCR		1.6		4.24
Natural gas purchases (MMbtu)
2012	Swap	IFNPCR		1.1	$	2.83
2013	Swap	IFNPCR		-	$	2.59

19