• Reduced capital expenditures by over 30% compared with fourth quarter 2015
• Delivered record crude oil production of 56,900 barrels per day
• Completed four gross operated Spraberry Shale wells with an average peak 24-hour IP of 1,602 Boed
• Increased development inventory in the Williston Basin through infill and deeper bench drilling
• Maintained strong liquidity, including $616 million of cash at quarter-end and an undrawn revolving credit facility

DENVER, April 27, 2016 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported first quarter 2016 financial and operating results.  The Company reported a net loss of $863.8 million, or $4.55 per diluted share, for the first quarter 2016 compared with a net loss of $55.6 million, or $0.32 per diluted share, for the first quarter 2015. 

Net loss includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, impairment, and other non-cash and/or non-recurring items.  Excluding these items, the Company’s first quarter 2016 Adjusted Net Loss (a non-GAAP measure) was $101.0 million, or $0.53 per diluted share compared with an Adjusted Net Loss of $8.7 million, or $0.05 per diluted share, for the first quarter 2015. The increase in Adjusted Net Loss was primarily due to lower average field-level prices for crude oil, NGL and natural gas and decreased proceeds from settled commodity derivatives, partially offset by higher crude oil, NGL and natural gas volumes and lower production taxes.

Adjusted EBITDA (a non-GAAP measure) for the first quarter 2016 was $115.1 million compared with $222.8 million for the first quarter 2015, a 48% decrease, primarily due to decreased average realized prices, partially offset by increased production.  The definitions and reconciliations of Adjusted EBITDA and Adjusted Net Loss to net loss are provided within the financial tables of this release.

“Our first quarter operational performance demonstrates the quality of QEP's diversified E&P asset portfolio, our focus on prudently managing our balance sheet, and our ability to operate successfully in a difficult commodity price environment,” commented Chuck Stanley, Chairman, President and CEO of QEP.

“We delivered our strongest well results to date from our Spraberry Shale program in the Permian Basin.  In the Williston Basin, our high-density infill and second and third bench Three Forks delineation-drilling programs continued to outperform our internal type-curves and further validate the productivity of these zones. As a result, we are organically growing our drilling inventory with these core assets and generating solid financial returns.  We believe our well results in the Williston Basin continue to demonstrate that our acreage is home to some of the strongest wells of any unconventional resource play in the United States.”

“We also took steps during the quarter to further solidify our financial position, raising approximately $368.6 million through an equity offering.  At the end of the quarter we had $616 million of cash on our balance sheet and an undrawn revolving credit facility, which positions us to capitalize on acquisition opportunities in the current market and play offense as the commodity market recovers.  Our focus in 2016 remains on capital discipline and on maintaining an approximately flat year-over-year production profile,” concluded Stanley.

Slides for the first quarter 2016 with maps and other supporting materials referred to in this release are posted on the Company’s website at www.qepres.com.

QEP Financial Results Summary

• Net natural gas equivalent production was 82.7 Bcfe for the first quarter 2016 compared with 75.2 Bcfe for the first quarter 2015, an increase of 10%.  This increase was primarily due to increased production in the Williston, Permian and Uinta basins and in Pinedale, partially offset by decreased production in Haynesville/Cotton Valley.
  
• Crude oil, NGL and natural gas production increased 16%, 44% and 2%, respectively, in the first quarter 2016 compared with the first quarter 2015. First quarter 2016 crude oil production was positively impacted by improved well results in the Williston and Permian basins.  NGL production was higher, primarily in the Williston Basin, due to a third-party midstream provider’s decision to continue to operate in ethane recovery, despite negative ethane realizations, and in the Permian Basin due to an overall increase in production.
  
• Field-level revenues decreased 24% in the first quarter 2016 compared with the first quarter 2015, due to lower crude oil, NGL and natural gas prices.  Crude oil and NGL production accounted for 65% of field-level revenues in the first quarter 2016. 
  
• Capital investment (on an accrual basis) for the first quarter 2016 was $145.5 million, down $69.6 million from the fourth quarter 2015, excluding acquisitions and exploratory drilling.  The Company expects capital expenditures to trend lower from first quarter 2016 levels for the remainder of 2016 based on a three to four rig drilling program in its core operating areas.
  
• During the quarter, the Company invested $21 million to acquire various oil and gas properties, including additional interests in QEP-operated wells, in the Williston and Permian basins of which $14.8 million was cash.  The cost of these acquisitions was partially offset by the receipt of cash proceeds from the sale of certain non-core assets.
  
• During the first quarter 2016 the Company invested approximately $12 million in exploratory capital to test a new play concept.
  
• The Company recorded $1,182.4 million of impairment expense during the first quarter 2016, primarily in Pinedale as a result of lower future prices.
  
• Cash and cash equivalents were $616.4 million at the end of the first quarter 2016, and the Company had no borrowings under its unsecured revolving credit facility, which is not subject to semi-annual borrowing base redeterminations.
  
• General and administrative expense for the first quarter 2016 was $48.7 million, an increase of 3% compared with the first quarter 2015, due to an increase in legal expenses in the first quarter of 2016, partially offset by a decrease in labor, benefits and other employee expenses.
  
• Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing and QEP Energy.  QEP Energy now markets its own gas, oil and NGL production. In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts have been assigned to QEP Energy, except those contracts related to natural gas storage activities and the Haynesville gathering system in Northwest Louisiana.  QEP will no longer be the first purchaser of other working interest owners' production.  As a result, QEP will be reporting lower resale revenue and expenses than in prior periods, and the Company has one reporting segment. 
  
• In April 2016, QEP restructured and streamlined its organizational structure in response to the lower commodity price environment.  This restructuring resulted in an approximately 6% decrease in the Company's workforce and approximate cost of $2.2 million in one-time termination benefits, which will be recorded in the second quarter 2016.

QEP 2016 Guidance

In response to the current commodity price environment, QEP has reduced its full-year capital budget for drilling and completions by over 50% compared with 2015. Due to efficiency gains, strong well performance and ongoing cost reduction initiatives, the Company anticipates approximately flat year-over-year crude oil production in 2016. 

The guidance assumes the following:

• A reduction in QEP's operated rig count from nine at year-end 2015 to three by early second quarter 2016
  • At least one rig in the Williston and Permian basins and Pinedale for the remainder of 2016
  • Assumes the addition of a fourth rig in the second half of 2016
• No additional asset acquisitions or divestitures
• No exploratory drilling costs
• Partial recovery of ethane in the Williston and Permian basins, to the extent that QEP cannot elect to reject ethane, for the entire year

QEP's full-year 2016 guidance is shown below.

2016 Guidance
		2016			2016
	Previous Forecast			Current Forecast
Oil production (MMbbl)	18.5 - 20.5			19.0 - 20.5
NGL production (MMbbl)	4 - 5			4 - 5
Natural gas production (Bcf)	165 - 175			165 - 175
Total natural gas equivalent production (Bcfe)	300 - 328			303 - 328
Lease operating and transportation expense (per Mcfe)	$1.60 - $1.70			$1.60 - $1.70
Depletion, depreciation and amortization (per Mcfe)	$3.00 - $3.30			$2.70 - $3.00
Production and property taxes (% of field-level revenue)		8.5	%		8.5	%
(in millions)
General and administrative expense(1)	$150 - $160			$150 - $160
Capital investment (excluding acquisitions and exploratory drilling costs)	$450 - $500			$450 - $500

⁽¹⁾ Forecasted general and administrative expense includes approximately $35.0 million of non-cash expenses primarily related to share-based compensation.

Operations Summary

The table below presents a summary of QEP-operated and non-operated well completions for the three months ended March 31, 2016:

	Operated Completions						Non-operated Completions
	Gross			Net			Gross			Net
Northern Region
Pinedale	—			—			—			—
Williston Basin	17			16.8			3			0.0
Uinta Basin	8			8.0			2			0.0
Other Northern	—			—			—			—
Southern Region
Haynesville/Cotton Valley	—			—			5			1.1
Permian Basin	7			6.7			—			—
Other Southern	—			—			—			—

Williston Basin

Williston Basin net production averaged approximately 53.8 Mboed (89% liquids) during the first quarter 2016, a 4% increase compared with the fourth quarter 2015 and a 14% increase over the first quarter 2015. The Company completed and turned to sales 17 gross-operated wells during the first quarter 2016 (average working interest 99%) all at South Antelope. (See Slide 6)

During the first quarter 2016, the Company completed and turned to sales five additional high-density infill pilot wells and also completed its first 12-well high-density pad.  At the end of the quarter, all of these wells were still in the early stages of cleanup and had not achieved peak rates.  The original 10 high-density infill pilot wells completed in 2015 are still performing strongly.  The first pad of five wells, completed in the second quarter 2015, has averaged over 217 Mboe per well in the first 270 days of production, while the second pad of five wells, completed in the third quarter 2015, has averaged over 140 Mboe in the first 120 days of production.

The Company continues to test the second and third benches of the Three Forks. The eight second bench wells, completed in 2015, continue to outperform expectations. The well within this group with the longest time on production has produced 270 Mboe in its first 270 days of production.  Four second bench wells were completed and turned to sales late in the quarter and were still in the early stages of cleanup and had not achieved peak rates.  At the end of the first quarter 2016 there were three wells, all targeting the second bench of the Three Forks, waiting on completion and two additional second bench wells actively drilling.

At the end of the first quarter 2016, there were three wells, all targeting the third bench of the Three Forks, waiting on completion and one additional third bench well in the process of being drilled.  The third bench test completed in the fourth quarter 2015 has achieved 162 Mboe during its first 120 days of production.  (See Slides 7-11)

At the end of the first quarter 2016, QEP had 20 gross operated wells waiting on completion in the Williston Basin (average working interest 85%), comprised of 17 at South Antelope and three at Ft. Berthold.  In addition, the Company had interest in 26 gross non-operated wells waiting on completion (average working interest 4%) at the end of the quarter. 

Current average gross QEP-operated drilled and completed authorization for expenditure (AFE) well costs, assuming sliding sleeve completions, are $5.3 million at South Antelope and $5.8 million at Ft. Berthold, with costs associated with facilities and artificial lift adding approximately $0.8 million per well at South Antelope and $1.1 million per well at Ft. Berthold.  At the end of the first quarter the Company had two operated rigs working in the Williston Basin, both at South Antelope, and released one rig subsequent to the end of the quarter.

Slides 5-12 depict QEP's acreage and activity in the Williston Basin.

Permian Basin

Permian Basin net production averaged approximately 16.7 Mboed (85% liquids) during the first quarter 2016, a 21% increase compared with the fourth quarter 2015 and an 86% increase over the first quarter 2015.  QEP completed and turned to sales seven gross-operated wells during the first quarter 2016 (average working interest 96%).  Four wells targeted the Spraberry Shale and two wells targeted the Middle Spraberry.

Six of the wells turned to sales during the quarter reached peak production.  The University 7-1627 N 9SS, University 7-1627 N 10SS, University 7-1627 S 2SS, and University 7-1627 S 3SS, completed in the Spraberry Shale, achieved peak 24-hour IP rates of 1,557 Boed, 1,785 Boed, 1,566 Boed, and 1,499 Boed, respectively.  The Mabee KJ West H 3MS and Mabee KJ West H 4MS, targeting the Middle Spraberry, achieved peak 24-hour IP rates of 848 Boed and 813 Boed, respectively.

At the end of the first quarter 2016, the Company had four gross-operated horizontal wells targeting the Spraberry Shale waiting on completion (average working interest 100%).

Current average gross QEP-operated drilled and completed AFE well costs are $5.2 million for Spraberry wells, with costs associated with facilities and artificial lift adding approximately $0.7 million per well.  At the end of the first quarter, the Company had one operated rig in the Permian Basin drilling horizontal targets.

Slides 13-15 depict QEP's acreage and activity in the Permian Basin.

Pinedale

Pinedale net production averaged 277 MMcfed (14% liquids), during the first quarter 2016, a 9% decrease compared with the fourth quarter 2015 and a 14% increase over the first quarter 2015.  There were no wells completed and turned to sales during the quarter.

The new completion design utilizing 100 mesh sand, which the Company implemented in late 2014, continues to provide impressive results. The initial wells completed with this completion design have delivered a 360-day cumulative production improvement of approximately 28%, with no increase in capital investment.

At the end of the first quarter, the Company had 31 gross-operated Pinedale wells waiting on completion (average working interest 61%).

Current average gross QEP-operated drilled and completed AFE well costs are $2.7 million in Pinedale, with costs associated with facilities and plunger lift adding approximately $0.2 million per well.  At the end of the first quarter, the Company had one operated rig running in Pinedale.

Slide 16 depicts QEP's acreage and activity in Pinedale.

Uinta Basin

Uinta Basin net production averaged 80 MMcfed (21% liquids) during the first quarter 2016, of which 52 MMcfed (9% liquids) was from the Lower Mesaverde play.  This represents a 13% increase compared with the fourth quarter 2015 and a 4% increase over the first quarter 2015.

QEP continues to see encouraging results in the Lower Mesaverde play. In the first quarter 2016, the Company completed a new pad of eight directionally-drilled vertical wells targeting the Lower Mesaverde.  These wells achieved a combined peak 24-hour IP rate of 29.1 MMcfed and gross cumulative production of 0.6 Bcfe after 29 days online (post refrigeration-processing).  The two horizontal wells targeting the Lower Mesaverde, turned to sales in the second half of 2015, each surpassed 1.0 Bcfe of gross cumulative production in the first 200 days of production.  These wells continue to be among the top horizontal producers in the Company’s Lower Mesaverde play.  The new completions increased gross production to over 100 MMcfed for the first time since 2008.  QEP believes it has an extensive inventory of vertical and horizontal well locations in the Lower Mesaverde play and recent results continue to further de-risk this multi-Tcfe resource.

Current average gross QEP-operated drilled and completed directional vertical AFE well costs are $2.1 million in the Uinta Basin, with costs associated with facilities and artificial lift adding approximately $0.3 million per well.

At the end of the first quarter, the Company had no rigs operating in the Uinta Basin. 

Slides 17-18 depict QEP's acreage and activity in the Lower Mesaverde play in the Uinta Basin.

First Quarter 2016 Results Conference Call

QEP Resources’ management will discuss first quarter 2016 results in a conference call on Thursday, April 28, 2016, beginning at 9:00 a.m. EDT.  The conference call can be accessed at www.qepres.com.  You may also participate in the conference call by dialing (877) 869-3847 in the U.S. or Canada and (201) 689-8261 for international calls.  A replay of the teleconference will be available on the website immediately after the call through May 28, 2016, or by dialing (877) 660-6853 in the U.S. or Canada and (201) 612-7415 for international calls, and then entering the conference ID # 13634147.  In addition, QEP’s slides for the first quarter 2016, 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 an independent natural gas and crude oil exploration and production company focused in two geographic regions: the Northern Region (primarily the Rockies and the Williston Basin) and the Southern Region (primarily Texas and Louisiana) of the United States. 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, but are not limited to, statements regarding: our 2016 Capital Investment Plan, including the amount of planned capital expenditures; the number and location of drilling rigs to be deployed; anticipated production levels; the quality of our E&P asset portfolio; our financial position and liquidity; our focus on capital discipline; expected gross completed well costs and additional costs for facilities and artificial lift; forecasted production amounts, lease operating and transportation expense, depletion, depreciation and amortization expense, general and administrative expense, and production and property taxes, and related assumptions for such guidance; plans regarding ethane recovery; the amount of employee termination expense and the timing of the recognition of such expense; our extensive inventory of drilling locations; and the use and importance of non-GAAP financial measures. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: changes in natural gas, NGL and oil prices; liquidity constraints, including those resulting from the cost or unavailability of financing due to debt and equity capital and credit market conditions, changes in our credit rating, our compliance with loan covenants, the increasing credit pressure on our industry or demands for cash collateral by counterparties to derivative and other contracts; global geopolitical and macroeconomic factors; the activities of the Organization of Petroleum Exporting Countries (OPEC), including the ability of members of OPEC to agree to and maintain oil price and production controls and the ability of Iran to market its oil following the lifting of trade sanctions; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural gas, oil and NGL; changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions, natural resources, and fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures; impact of U.S. dollar exchange rates on oil, NGL and natural gas prices; elimination of federal income tax deductions for oil and gas exploration and development; drilling results; shortages of oilfield equipment, services and personnel; the availability of storage and refining capacity; operating risks such as unexpected drilling conditions; transportation constraints; weather conditions; changes in maintenance, service and construction costs; permitting delays; outcome of contingencies such as legal proceedings; inadequate supplies of water and/or lack of water disposal sources; 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, 2015 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2016. 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.

QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
	Three Months Ended
	March 31,
	2016				2015
REVENUES	(in millions, except per share amounts)
Gas sales	$	85.1			$	122.0
Oil sales	143.8				178.8
NGL sales	13.6				19.1
Other revenue	2.3				4.4
Purchased gas and oil sales	16.5				143.8
Total Revenues	261.3				468.1
OPERATING EXPENSES
Purchased gas and oil expense	16.9				145.9
Lease operating expense	60.0				61.8
Gas, oil and NGL transportation and other handling costs	73.6				65.1
Gathering and other expense	1.3				1.7
General and administrative	48.7				47.4
Production and property taxes	17.8				27.8
Depreciation, depletion and amortization	240.0				195.4
Exploration expenses	0.3				1.1
Impairment	1,182.4				20.0
Total Operating Expenses	1,641.0				566.2
Net gain (loss) from asset sales	0.5				(30.5		)
OPERATING INCOME (LOSS)	(1,379.2		)		(128.6		)
Realized and unrealized gains (losses) on derivative contracts	50.9				80.9
Interest and other income (expense)	2.3				(2.6		)
Interest expense	(36.7		)		(36.8		)
INCOME (LOSS) BEFORE INCOME TAXES	(1,362.7		)		(87.1		)
Income tax (provision) benefit	498.9				31.5
NET INCOME (LOSS)	$	(863.8	)		$	(55.6	)
Earnings (loss) per common share
Basic	$	(4.55	)		$	(0.32	)
Diluted	$	(4.55	)		$	(0.32	)
Weighted-average common shares outstanding
Used in basic calculation	189.7				176.2
Used in diluted calculation	189.7				176.2
Dividends per common share	$	—			$	0.02

QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,  2016				December 31,  2015
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	616.4			$	376.1
Accounts receivable, net	115.5				278.2
Income tax receivable	170.1				87.3
Fair value of derivative contracts	134.4				146.8
Gas, oil and NGL inventories, at lower of average cost or market	7.9				13.3
Prepaid expenses and other	20.9				30.1
Total Current Assets	1,065.2				931.8
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	13,472.2				13,314.9
Unproved properties	678.6				691.0
Marketing and other	296.8				297.9
Materials and supplies	31.1				38.5
Total Property, Plant and Equipment	14,478.7				14,342.3
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	8,252.4				6,870.2
Marketing and other	90.6				87.5
Total Accumulated Depreciation, Depletion and Amortization	8,343.0				6,957.7
Net Property, Plant and Equipment	6,135.7				7,384.6
Fair value of derivative contracts	20.8				23.2
Other noncurrent assets	60.9				58.6
TOTAL ASSETS	$	7,282.6			$	8,398.2
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	—			$	29.8
Accounts payable and accrued expenses	204.7				351.7
Production and property taxes	41.5				46.1
Interest payable	33.7				36.4
Fair value of derivative contracts	—				0.8
Current portion of long-term debt	176.7				176.8
Total Current Liabilities	456.6				641.6
Long-term debt	2,016.2				2,014.7
Deferred income taxes	1,033.3				1,479.8
Asset retirement obligations	207.4				204.9
Fair value of derivative contracts	3.4				4.0
Other long-term liabilities	108.0				105.3
Commitments and contingencies
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 217.6 million and 177.3 million shares issued, respectively	2.2				1.8
Treasury stock – 0.8 million and 0.5 million shares, respectively	(18.2		)		(14.6		)
Additional paid-in capital	931.4				554.8
Retained earnings	2,554.5				3,418.3
Accumulated other comprehensive income	(12.2		)		(12.4		)
Total Common Shareholders' Equity	3,457.7				3,947.9
TOTAL LIABILITIES AND EQUITY	$	7,282.6			$	8,398.2

QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
	2016				2015
	(in millions)
OPERATING ACTIVITIES
Net income (loss)	$	(863.8	)		$	(55.6	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	240.0				195.4
Deferred income taxes	(446.7		)		(4.8		)
Impairment	1,182.4				20.0
Share-based compensation	8.0				9.1
Amortization of debt issuance costs and discounts	1.6				1.9
Net (gain) loss from asset sales	(0.5		)		30.5
Unrealized (gains) losses on marketable securities	(0.2		)		—
Unrealized (gains) losses on derivative contracts	13.5				23.5
Changes in operating assets and liabilities	(52.6		)		(492.7		)
Net Cash Provided by (Used in) Operating Activities	81.7				(272.7		)
INVESTING ACTIVITIES
Property acquisitions	(14.8		)		—
Property, plant and equipment, including dry exploratory well expense	(185.8		)		(342.1		)
Proceeds from disposition of assets	22.9				1.6
Net Cash Provided by (Used in) Investing Activities	(177.7		)		(340.5		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(29.8		)		(38.9		)
Treasury stock repurchases	(2.9		)		(1.9		)
Other capital contributions	0.2				(0.4		)
Dividends paid	—				(3.5		)
Proceeds from issuance of common stock, net	368.6				—
Excess tax (provision) benefit on share-based compensation	0.2				(1.8		)
Net Cash Provided by (Used in) Financing Activities	336.3				(46.5		)
Change in cash and cash equivalents	240.3				(659.7		)
Beginning cash and cash equivalents	376.1				1,160.1
Ending cash and cash equivalents	$	616.4			$	500.4

Production by Region
	Three Months Ended March 31,
	2016			2015			Change
	(in Bcfe)
Northern Region
Pinedale	25.2			21.8			16	%
Williston Basin	29.4			25.4			16	%
Uinta Basin	7.3			6.9			6	%
Other Northern	2.3			2.7			(15	)%
Total Northern Region	64.2			56.8			13	%
Southern Region
Haynesville/Cotton Valley	9.1			11.7			(22	)%
Permian Basin	9.1			4.9			86	%
Other Southern	0.3			1.8			(83	)%
Total Southern Region	18.5			18.4			1	%
Total production	82.7			75.2			10	%

Total Production
	Three Months Ended March 31,
	2016			2015			Change
Production Volumes
Gas (Bcf)	43.4			42.6			2	%
Oil (Mbbl)	5,176.4			4,481.4			16	%
NGL (Mbbl)	1,365.0			947.4			44	%
Total production (Bcfe)	82.7			75.2			10	%
Average daily production (MMcfe)	908.8			835.6			9	%

Prices
	Three Months Ended March 31,
	2016				2015				Change
Gas (per Mcf)
Average field-level price	$	1.96			$	2.87
Commodity derivative impact	0.50				0.42
Net realized price	$	2.46			$	3.29			(25	)%
Oil (per bbl)
Average field-level price	$	27.77			$	39.89
Commodity derivative impact	7.87				18.75
Net realized price	$	35.64			$	58.64			(39	)%
NGL (per bbl)
Average field-level price	$	9.97			$	20.09
Commodity derivative impact	—				—
Net realized price	$	9.97			$	20.09			(50	)%
Average net equivalent price (per Mcfe)
Average field-level price	$	2.93			$	4.25
Commodity derivative impact	0.75				1.36
Net realized price	$	3.68			$	5.61			(34	)%

Operating Expenses
	Three Months Ended March 31,
	2016				2015				Change
	(per Mcfe)
Lease operating expense	$	0.73			$	0.82			(11	)%
Gas, oil and NGL transport & other handling costs	0.89				0.87				2	%
Production and property taxes	0.22				0.37				(41	)%
Total production costs	$	1.84			$	2.06			(11	)%

QEP RESOURCES, INC.
NON-GAAP MEASURES
(Unaudited)

Adjusted EBITDA

This release contains references to the non-GAAP measure of Adjusted EBITDA. Management believes Adjusted EBITDA is an important measure of the Company's financial and operating performance that allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA) adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items. The following tables reconcile net income to Adjusted EBITDA:

	Three Months Ended March 31,
	2016				2015
Net income (loss)	$	(863.8	)		$	(55.6	)
Interest expense	36.7				36.8
Interest and other (income) expense	(2.3		)		2.6
Income tax provision (benefit)	(498.9		)		(31.5		)
Depreciation, depletion and amortization	240.0				195.4
Unrealized (gain) loss on derivative contracts	13.5				23.5
Exploration expenses	0.3				1.1
Net (gain) loss from asset sales	(0.5		)		30.5
Impairment	1,182.4				20.0
Other (1)	7.7				—
Adjusted EBITDA	$	115.1			$	222.8
________________________________

⁽¹⁾ Reflects additional legal expenses that the Company believes do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore they have been excluded from the calculation of Adjusted EBITDA.

Adjusted Net Income (Loss)

This release also contains references to the non-GAAP measure of Adjusted Net Income (Loss).  Management defines Adjusted Net Income (Loss) as earnings excluding gains and losses from asset sales, unrealized gains and losses on derivative contracts, asset impairments and certain other non-cash and/or non-recurring items. Management believes Adjusted Net Income (Loss) is an important measure of the Company’s operational performance relative to other gas and oil producing companies.

The following table reconciles net loss to Adjusted Net Income (Loss):

	Three Months Ended
	March 31,
	2016				2015
	(in millions, except earnings per share)
Net income (loss)	$	(863.8	)		$	(55.6	)
Adjustments to net income (loss)
Unrealized (gains) losses on derivative contracts	13.5				23.5
Income taxes on unrealized (gains) losses on derivative contracts	(4.9		)		(8.6		)
Net (gain) loss from asset sales	(0.5		)		30.5
Income taxes on net (gain) loss from asset sales	0.2				(11.2		)
Impairment	1,182.4				20.0
Income taxes on impairment	(432.8		)		(7.3		)
Other	7.7				—
Income taxes on other	(2.8		)		—
Total after tax adjustments to net income	762.8				46.9
Adjusted Net Income (Loss)	$	(101.0	)		$	(8.7	)
Earnings (Loss) per Common Share
Diluted earnings per share	$	(4.55	)		$	(0.32	)
Diluted after-tax adjustments to net income (loss) per share	4.02				0.27
Diluted Adjusted Net Income per share	$	(0.53	)		$	(0.05	)
Weighted-average common shares outstanding
Diluted	189.7				176.2

The following tables present open 2016 derivative positions as of April 22, 2016:

Production Commodity Derivative Swap Positions
Year		Index		Total Volumes			Average Swap Price per Unit
				(in millions)
Gas sales				(MMBtu)			($/MMBtu)
2016		NYMEX HH		38.0			$	2.79
2016		IFNPCR		49.0			$	2.53
2017		NYMEX HH		73.0			$	2.75
2017		IFNPCR		32.9			$	2.51
2018		NYMEX HH		7.3			$	2.80
Oil Sales				(bbls)			($/bbl)
2016 (April through June)		NYMEX WTI		1.7			$	57.09
2016 (July through December)		NYMEX WTI		5.2			$	51.82
2017		NYMEX WTI		5.1			$	50.18

Production Gas Collars
Year		Index		Total Volume			Average Price Floor				Average Price Ceiling
				(in millions)
				(MMBtu)			($/MMBtu)				($/MMBtu)
2016		NYMEX HH		4.9			$	2.75			$	3.89
2017		NYMEX HH		3.7			$	2.50			$	3.35

Production Gas Basis Swaps
Year		Index Less Differential		Index		Total Volumes			Weighted-Average Differential
						(in millions)
						(MMBtu)			($/MMBtu)
2016		NYMEX HH		IFNPCR		24.5			$	(0.16	)
2017		NYMEX HH		IFNPCR		51.1			$	(0.18	)
2018		NYMEX HH		IFNPCR		7.3			$	(0.16	)

Storage Commodity Derivative Positions
Year		Type of Contract		Index		Total Volumes			Average Swap Price per MMBtu
						(in millions)
Gas sales						(MMBtu)			($/MMBtu)
2016		SWAP		IFNPCR		2.7			$	2.20
2017		SWAP		IFNPCR		1.0			$	2.72
Gas purchases
2016		SWAP		IFNPCR		1.2			$	2.07

 

Contact
Investors:
William I. Kent, IRC
Director, Investor Relations
303-405-6665

Media:
Brent Rockwood
Director, Communications
303-672-6999

QEP Resources, Inc.