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News Release

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QEP Resources Reports First Quarter 2015 Financial and Operating Results
  • Enhanced well completions improved economics in core plays
    • 85% increase in 120-day cumulative production in the Williston Basin
    • 50% increase in 90-day cumulative production at Pinedale
  • New Lower Mesaverde horizontal well produced almost 1.1 Bcfe in the first 80 days online
  • Reiterated 2015 capital budget and increased production guidance

DENVER, April 29, 2015 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported first quarter 2015 financial and operating results. The Company reported a net loss from continuing operations of $55.6 million, or $0.32 per diluted share, for the first quarter 2015 compared with net income from continuing operations of $12.7 million, or $0.07 per diluted share, in the first quarter 2014.

Net income or loss includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, and impairment charges. Excluding these items, the Company's first quarter 2015 Adjusted Net Loss (a non-GAAP measure) was $8.7 million, or $0.05 per diluted share, compared with Adjusted Net Income from continuing operations of $41.1 million, or $0.23 per diluted share, for the comparable 2014 period. The decrease in Adjusted Net Income from continuing operations was due primarily to significantly lower average field-level prices for crude oil, natural gas and NGLs, partially offset by higher crude oil volumes, lower production taxes and higher proceeds from realized commodity derivatives.

Adjusted EBITDA (a non-GAAP measure) for the first quarter 2015 was $222.8 million, compared with $333.1 million on a continuing operations basis in the first quarter 2014, a 33% decrease. The definitions and reconciliations of Adjusted EBITDA and Adjusted Net Income to net income are provided within the financial tables of this release.

"Our strong first quarter operational performance, coupled with our premier E&P asset portfolio and solid financial position, demonstrates the flexibility we have built into our business to manage through the current volatile commodity price environment," commented Chuck Stanley , Chairman, President and CEO of QEP Resources. "As we forecasted, production volumes declined in the first quarter of 2015, driven by a deliberate slowdown in activities in response to lower commodity prices. We have significantly decelerated drilling activity to manage through the commodity price trough and we are continuing to actively manage the timing of well completions to take advantage of the contango in forward crude oil and natural gas prices. These actions should allow us to capture additional service cost savings, preserve liquidity and be profitable in the long-term. With the slowdown in activity, we have redoubled our focus on driving greater efficiencies in our operations as evidenced by outstanding results from enhanced completion designs in the Williston Basin and Pinedale, which are greatly improving well productivity and overall economics. We are also very excited about the strong performance of our most recent Lower Mesaverde horizontal well and its implications on the economic viability of our multi-Tcfe liquids-rich natural gas play in the Uinta Basin, which, in addition to high-density development in the Williston Basin, could add significantly to our inventory of future development locations," concluded Stanley.

Slides for the first quarter 2015 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

Adjusted EBITDA by Operating Segment(1)
 Three Months Ended March 31,
 2015 2014 Change
  (in millions)
QEP Energy$221.1 $328.6 (33)%
QEP Marketing and Other1.7 4.5 (62)%
Discontinued Operations53.2 (100)%
Adjusted EBITDA$222.8 $386.3 (42)%
(1) See attached financial tables of this release for a reconciliation of Adjusted EBITDA to net income.

QEP Energy

  • Adjusted EBITDA decreased 33% compared with the first quarter 2014, driven by significant decreases in average field level prices for crude oil, natural gas and NGLs, partially offset by higher crude oil production volumes and proceeds from settled commodity derivatives combined with decreases in both production and property taxes.
  • Net natural gas equivalent production increased by 2% to 75.2 Bcfe in the first quarter 2015 compared with 73.7 Bcfe in the first quarter 2014. The increase was due primarily to increased crude oil and NGL production in the Williston Basin and a full quarter of production from the Permian Basin acquisition, partially offset by decreased Haynesville production and the divestiture of Midcontinent assets during the second and fourth quarters of 2014.
  • Crude oil production increased 35%, while natural gas production decreased 4% and NGL production decreased 40% in the first quarter 2015 compared with the first quarter 2014. The decrease in NGL production was primarily driven by the Company's decision to reject ethane during the first quarter of 2015.
  • Crude oil and NGL revenues decreased 44% compared with the first quarter 2014, and represented approximately 62% of field-level production revenues.
  • During the quarter QEP Energy realized $101.9 million in commodity derivative gains compared with $33.3 million derivative losses in the first quarter of 2014.
  • QEP Energy's capital investment (on an accrual basis) for the first quarter of 2015 was $280.2 million, down $164.4 million from the fourth quarter 2014.

QEP Marketing and Other

  • During the first quarter of 2015, QEP paid $509.8 million in federal income taxes primarily related to the $2.5 billion sale of substantially all of its midstream business which closed on December 2, 2014.
  • In February 2015, QEP restructured and streamlined several functional areas within the company in response to the lower commodity price environment. This restructuring resulted in an approximately 7.5% decrease in company-wide headcount and approximately $2.3 million in associated severance costs.

QEP 2015 Guidance 

QEP Resources' full year 2015 guidance and related assumptions are shown below. The Company's updated guidance assumes no asset acquisitions or divestitures and that QEP will not recover ethane from its produced gas for the entire year: 

Guidance and Assumptions
  2015 2015
 QEP Energy oil production (MMBbl) 16.5 - 18.5 17.0 - 18.5
 QEP Energy NGL production (MMBbl) 4.0 - 4.5 4.0 - 4.3
 QEP Energy natural gas production (Bcf) 155 - 175 165 - 175
QEP Energy total equivalent production (Bcfe) 278 - 313 291 - 312
Lease operating and transportation expense (per Mcfe) $1.70 - $1.85 $1.70 - $1.85
QEP Energy Depletion, Depreciation and Amortization (per Mcfe) $3.00 - $3.30 $2.70 - $3.00
Production and property taxes, % of field-level revenue 8.5% - 9.0% 8.5% - 9.0%
Figures below in millions
QEP Resources General and Administrative Expense $165 - $185 $170 - $185
QEP Resources Capital Investment $900 - $1,050 $900 - $1,050

Operations Summary 

Operated Completions
 Three Months Ended March 31, 2015
Northern Region    
Pinedale 20 14.5
Williston Basin 16 12.8 22 1.7
Uinta Basin 1 1.0
Other Northern 1 1.0
Southern Region        
Haynesville/Cotton Valley9 0.4
Permian Basin 11 10.1 1 0.3
Midcontinent3 0.1

Williston Basin

Williston Basin net production averaged approximately 47.0 Mboed (89% liquids) during the first quarter 2015, a 13% decrease over the fourth quarter 2014, and a 51% increase over the first quarter 2014. Production in the Williston Basin, during the first quarter 2015 was impacted by a deliberate slowdown in completions and increased shut-in times for offset fracs. The Company completed and turned to sales 16 gross-operated wells during the quarter (average working interest 80%), nine of which were in South Antelope. The Company also participated in 22 gross outside-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 8%).

QEP completed three operated wells in the quarter utilizing cemented liners with "plug and perf" completion technology to further evaluate optimum stimulation design. These wells were completed over 50 stages utilizing approximately 1,000 pounds of proppant per lateral foot. Production results from the "plug and perf" wells are still being evaluated; however, early results indicate a modest improvement over prior offset sliding sleeve completions. QEP continues to make drilling efficiency improvements and during the first quarter set a new drilling record of 10.5 days from spud to total depth of approximately 20,500 feet.

Results from the new enhanced well completion design introduced in the Williston Basin during the second half of 2014 continue to exceed expectations. The Company initially switched from pumping approximately 350 pounds of proppant per lateral foot to approximately 825 pounds of proppant per lateral foot over approximately 33 stages. In more recent wells, QEP has been pumping approximately 1,000 pounds of proppant per lateral foot over approximately 50 stages. Comparing performance from the two families of new completion designs, increasing the proppant volume, but keeping the stage count constant at roughly 33 stages, resulted in an average increase in cumulative production of approximately 37 MBoe in the first 120 days online. Combining larger proppant volumes with more stages (an average of 50) resulted in an average increase in cumulative production of about 75 MBoe in the first 120 days online compared to our original completion design, an 85% improvement to over 160 MBoe. The Company expects gross completed well costs in the Williston Basin, incorporating the enhanced completion design and a mixture of sliding sleeve and "plug and perf" technology, to average $9.5 million during 2015.

During the quarter the Company continued work on a pilot program to evaluate high-density infill development drilling on its South Antelope acreage. The Company drilled and completed a total of four pilot wells spaced at 400 and 600-foot intervals, between existing producing wells, in the Middle Bakken and first bench of the Three Forks. The Company also drilled its first well in the second bench of the Three Forks. Flowback on these infill wells began in April 2015 and initial production results are encouraging.

At the end of the first quarter, QEP had 40 gross operated wells waiting on completion (average working interest 75%) in the Williston Basin and four operated rigs running, including three rigs on South Antelope and one rig on the Fort Berthold Indian Reservation. In addition, the Company had interests in seven gross outside-operated wells being drilled (average working interest 3%) and 17 gross outside-operated wells waiting on completion (average working interest 5%) at the end of the first quarter.

Slides 5-9 depict QEP's acreage and activity in the Williston Basin.

Permian Basin

Permian Basin daily production during the first quarter 2015 averaged 9.0 Mboed (85% liquids). QEP completed and turned to sales seven vertical and four horizontal wells in the first quarter 2015. Three of the horizontal operated wells, composed of one Wolfcamp B, and two Wolfcamp D, had an average maximum daily production rate of 1,021 Boed and a maximum average 30-day production rate of 711 Boed. The fourth operated horizontal Wolfcamp B well was still in the early stages of cleaning up as of quarter end.

At the end of the first quarter, the Company had three operated rigs in the Permian Basin: one drilling vertical Atokaberry wells and two drilling horizontal targets in the Spraberry Shale and Wolfcamp D. The Company had six gross operated horizontal wells waiting on completion (average working interest of 65%) at end of the first quarter.

Slides 10-11 depict QEP's acreage and activity in the Permian Basin.

Pinedale Anticline

During the first quarter 2015, QEP's Pinedale net production averaged 242 MMcfed (13% liquids). QEP recovered ethane for all of 2014, and began rejecting ethane at Pinedale in the first quarter of 2015. While ethane rejection resulted in 7-8% less natural gas-equivalent sales volumes during the quarter, it had a negligible impact on gross revenues as ethane is still sold as part of the natural gas stream.

At the end of the first quarter, the Company had three rigs operating at Pinedale. The Company completed and turned to sales 20 gross Pinedale wells in the quarter, including one well QEP operates, but in which QEP owns only a small overriding royalty interest. At the end of the first quarter, the Company had 46 gross Pinedale wells with QEP working interests drilled, cased and waiting on completion (average working interest 61%).

All Pinedale wells turned to sales during the first quarter were completed utilizing a new fracture stimulation design that was tested in late 2014. The enhanced completion design, which does not increase completed well costs, continues to yield positive results with an average increase in 90-day average cumulative production of over 50% compared with the previous completion design. QEP expects Pinedale gross completed well cost to average $3.5 million during 2015.

The Company currently expects to complete approximately 90 - 95 gross wells during the remainder of 2015, including approximately seven wells for which QEP is the designated operator, but owns only a small overriding royalty interest.

Slides 12-13 depict QEP's acreage and activity in the Pinedale field.

Uinta Basin

During the first quarter 2015, Uinta Basin net production averaged 77 MMcfed (29% liquids) of which 44 MMcfed (18% liquids) was from the Red Wash Lower Mesaverde play.  QEP recovered ethane from Uinta Basin gas production throughout 2014 and rejected ethane for the first quarter 2015.

QEP's continued focus on drilling and completion optimization is yielding encouraging results in the Lower Mesaverde play.  The Company's most recent horizontal well, which was completed in the first quarter of 2015, has achieved almost 1.1 Bcfe of gross cumulative production after 80 days online (post-processing, assumes ethane rejection).  Since the start of the horizontal program in 2013, the Company has made steady progress in reducing drill times and improving production performance while reducing well cost. The most recent well was drilled and completed at a gross cost of approximately $9.6 million and utilized improved drilling and completion designs which greatly improved well economics. The Company has a deep inventory of potential well locations in the Lower Mesaverde play and the strong recent results serve to further de-risk this multi-Tcfe resource.

At the end of the first quarter, QEP had one rig active in the Uinta Basin drilling an eight well vertical pad in the Lower Mesaverde play.

Slides 14-15 depict QEP's acreage and activity in the Red Wash Lower Mesaverde play in the Uinta Basin.

First Quarter 2015 Results Conference Call

QEP Resources' management will discuss first quarter 2015 results in a conference call on Thursday, April 30, 2015, 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 30, 2015, 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 # 13605944. In addition, QEP's slides for the first quarter 2015, 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 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 statements regarding: our financial position; expected completed well costs; forecasted production, lease operating and transportation expense, DD&A expense, general and administrative expense, property taxes and capital investment for 2015 and related assumptions for such guidance; plans to reject ethane in 2015; drilling times and completion designs; 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; the availability of capital; global geopolitical and macroeconomic factors; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural gas, oil and NGL; impact of new laws and regulations, including regulations regarding the flaring of natural gas, the use of hydraulic fracture stimulation and the implementation of the Dodd-Frank Act; 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; operating risks such as unexpected drilling conditions; transportation constraints; weather conditions; changes in maintenance 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/A for the year ended December 31, 2014. 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. 

 Three Months Ended
 March 31,
 2015 2014
REVENUES (in millions except per share data)
Gas sales$122.0 $222.5
Oil sales178.8 288.7
NGL sales19.1 63.2
Other revenue4.4 2.5
Purchased gas and oil sales167.3 240.6
Total Revenues491.6 817.5
Purchased gas and oil expense169.4 237.9
Lease operating expense61.8 56.4
Gas, oil and NGL transportation and other handling costs65.1 59.9
Gathering and other expense1.7 1.6
General and administrative47.4 45.3
Production and property taxes27.8 47.9
Depreciation, depletion and amortization195.4 225.9
Exploration expenses1.1 2.2
Impairment20.0 2.0
Total Operating Expenses589.7 679.1
Net gain (loss) from asset sales(30.5) 2.4
Realized and unrealized gains (losses) on derivative contracts80.9 (80.9)
Interest and other income (expense)(2.6) 2.9
Interest expense(36.8) (41.9)
Income tax (provision) benefit31.5 (8.2)
Net income from discontinued operations, net of income tax27.0
NET INCOME (LOSS)$(55.6) $39.7
Earnings Per Common Share    
Basic from continuing operations$(0.32) $0.07
Basic from discontinued operations0.15
Basic total$(0.32) $0.22
Diluted from continuing operations$(0.32) $0.07
Diluted from discontinued operations0.15
Diluted total$(0.32) $0.22
Weighted-average common shares outstanding    
Used in basic calculation176.2 179.7
Used in diluted calculation176.2 180.0
Dividends per common share$0.02 $0.02


 March 31,
December 31, 
ASSETS (in millions)
Current Assets    
Cash and cash equivalents$500.4 $1,160.1
Accounts receivable, net319.4 441.9
Fair value of derivative contracts311.7 339.0
Gas, oil and NGL inventories, at lower of average cost or market7.6 13.7
Prepaid expenses and other37.8 46.8
Total Current Assets1,176.9 2,001.5
Property, Plant and Equipment (successful efforts method for oil and gas properties)    
Proved properties12,558.9 12,278.7
Unproved properties821.9 825.2
Marketing and other296.3 293.8
Material and supplies50.4 54.3
Total Property, Plant and Equipment13,727.5 13,452.0
Less Accumulated Depreciation, Depletion and Amortization    
Exploration and production6,357.7 6,153.0
Marketing and other72.8 67.8
Total Accumulated Depreciation, Depletion and Amortization6,430.5 6,220.8
Net Property, Plant and Equipment7,297.0 7,231.2
Fair value of derivative contracts13.7 9.9
Other noncurrent assets36.8 44.2
TOTAL ASSETS$8,524.4 $9,286.8
Current Liabilities    
Checks outstanding in excess of cash balances$15.8 $54.7
Accounts payable and accrued expenses453.5 575.4
Income taxes payable532.1
Production and property taxes45.9 61.7
Interest payable33.7 36.4
Deferred income taxes94.0 84.5
Total Current Liabilities642.9 1,344.8
Long-term debt2,218.3 2,218.1
Deferred income taxes1,348.9 1,362.7
Asset retirement obligations196.3 193.8
Other long-term liabilities98.1 92.1
Commitments and contingencies    
Common stock - par value $0.01 per share; 500.0 million shares authorized;177.0 million and 176.2 million shares issued, respectively1.8 1.8
Treasury stock - 0.3 million and 0.8 million shares, respectively(11.0) (25.4)
Additional paid-in capital530.1 535.3
Retained earnings3,522.6 3,587.9
Accumulated other comprehensive income (loss)(23.6) (24.3)
Total Common Shareholders' Equity4,019.9 4,075.3
 Three Months Ended
 March 31,
 2015 2014
  (in millions)
Net income (loss)$(55.6) $39.7
Net income attributable to noncontrolling interests5.8
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation, depletion and amortization195.4 240.2
Deferred income taxes(4.8) 20.7
Impairment20.0 2.0
Share-based compensation9.1 7.5
Amortization of debt issuance costs and discounts1.9 1.7
Net (gain) loss from asset sales30.5 (2.4)
Income from unconsolidated affiliates(2.2)
Distributions from unconsolidated affiliates and other2.7
Unrealized (gains) losses on derivative contracts23.5 45.5
Changes in operating assets and liabilities(492.7) (38.8)
Net Cash (Used in) Provided by Operating Activities(272.7) 322.4
Property acquisitions(946.6)
Property, plant and equipment, including dry exploratory well expense(342.1) (330.2)
Proceeds from disposition of assets1.6 2.9
Acquisition deposit held in escrow50.0
Net Cash Used in Investing Activities(340.5) (1,223.9)
Checks outstanding in excess of cash balances(38.9) (12.5)
Long-term debt issued300.0
Long-term debt issuance costs paid(1.1)
Proceeds from credit facility1,643.0
Repayments of credit facility(1,021.5)
Treasury stock repurchases(1.9) (5.5)
Other capital contributions(0.4) 2.9
Dividends paid(3.5) (3.6)
Excess tax (provision) benefit on share-based compensation(1.8) (0.6)
Distribution to noncontrolling interest(7.6)
Net Cash (Used in) Provided by Financing Activities(46.5) 893.5
Change in cash and cash equivalents(659.7) (8.0)
Beginning cash and cash equivalents1,160.1 11.9
Ending cash and cash equivalents$500.4 $3.9


QEP Energy - Production by Region
 Three Months Ended
 March 31,
  (in Bcfe)
 2015 2014 Change
Northern Region      
Pinedale21.8 20.9 4%
Williston Basin25.4 16.8 51%
Uinta Basin6.9 6.2 11%
Other Northern2.7 2.5 8%
Total Northern Region56.8 46.4 22%
Southern Region      
Haynesville/Cotton Valley11.7 14.4 (19)%
Permian Basin4.9 1.2 308%
Midcontinent1.8 11.7 (85)%
Total Southern Region18.4 27.3 (33)%
Total production75.2 73.7 2%
QEP Energy - Total Production
 Three Months Ended
 March 31,
 2015 2014 Change
QEP Energy Production Volumes      
Gas (Bcf)42.6 44.5 (4)%
Oil (Mbbl)4,481.4 3,312.0 35%
NGL (Mbbl)947.4 1,568.3 (40)%
Total production (Bcfe)75.2 73.7 2%
Average daily production (MMcfe)835.6 819.3 2%


QEP Energy - Prices
 Three Months Ended
 March 31,
 2015 2014 Change
Gas (per Mcf)      
Average field-level price$2.87 $5.00  
Commodity derivative impact0.42 (0.46)  
Net realized price$3.29 $4.54 (28)%
Oil (per bbl)      
Average field-level price$39.89 $87.16  
Commodity derivative impact18.75 (3.91)  
Net realized price$58.64 $83.25 (30)%
NGL (per bbl)      
Average field-level price$20.09 $40.26  
Commodity derivative impact 
Net realized price$20.09 $40.26 (50)%
Average net equivalent price (per Mcfe)      
Average field-level price$4.25 $7.79  
Commodity derivative impact1.36 (0.45)  
Net realized price$5.61 $7.34 (24)%


QEP Energy - Operating Expenses
 Three Months Ended
 March 31,
 2015 2014 Change
  (per Mcfe)
Depreciation, depletion and amortization$2.56 $3.03 (16)%
Lease operating expense0.82 0.76 8%
Gas, oil and NGL transport & other handling costs0.90 0.88 2%
Production and property taxes0.37 0.65 (43)%
Total Operating Expenses$4.65 $5.32 (13)%




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 cash flow, liquidity, and ability to incur and services debt, fund capital expenditures and return capital to shareholders. The use of this measure 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 table reconciles net income, the most comparable GAAP financial measure, to Adjusted EBITDA: 


QEP Energy
Marketing &
Other (1)


Operations (2)

Three Months Ended March 31, 2015 (in millions)
Net income (loss)$(59.3)$3.7$(55.6)$$(55.6)
Unrealized (gains) losses on derivative contracts21.71.823.523.5
Net (gain) loss from asset sales27.82.730.530.5
Interest and other (income) expense3.5(0.9)2.62.6
Income tax provision (benefit)(33.6)2.1(31.5)(31.5)
Interest expense (income)47.2(10.4)36.836.8
Depreciation, depletion and amortization192.72.7195.4195.4
Exploration expenses1.11.11.1
Adjusted EBITDA$221.1$1.7$222.8$$222.8
Three Months Ended March 31, 2014          
Net income (loss) $5.1 $7.6 $12.7 $27.0 $39.7
Unrealized (gains) losses on derivative contracts 45.2 0.3 45.545.5
Net (gain) loss from asset sales (2.4)(2.4)(2.4)
Interest and other (income) expense (2.9)(2.9)(2.9)
Income tax provision (benefit) 7.1 1.1 8.2 15.2 23.4
Interest expense (income) (3) 48.9 (7.0) 41.9 0.4 42.3
Depreciation, depletion and amortization (4) 223.4 2.5 225.9 10.6 236.5
Exploration expenses
Adjusted EBITDA $328.6 $4.5 $333.1 $53.2 $386.3
(1) Includes intercompany eliminations.
(2) In December 2014, QEP sold substantially all of its wholly owned subsidiary, QEP Field Services, to Tesoro Logistics LP. The operating results of QEP Field Services, excluding the Haynesville Gathering System (which was retained by QEP), have been classified as discontinued operations.
(3) Excludes noncontrolling interest's share of $0.2 million during the three months ended March 31, 2014 of interest expense attributable to QEP Midstream.
(4) Excludes noncontrolling interest's share of $3.7 million during the three months ended March 31, 2014, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C. and QEP Midstream.

Adjusted Net Income

This release also contains references to the non-GAAP measure of Adjusted Net Income. Management defines Adjusted Net Income as earnings excluding gains and losses from asset sales, unrealized gains and losses on derivative contracts, and asset impairments. 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 to Adjusted Net Income:

  Three Months Ended March 31,
 2015 2014
  (in millions, except earnings per share)
Net income (loss)$(55.6) $39.7
Adjustments to net income    
Net (gain) loss from asset sales from continuing operations30.5 (2.4)
Income taxes on net (gain) loss from asset sales from continuing operations(11.2) 0.9
Unrealized (gains) losses on derivative contracts from continuing operations23.5 45.5
Income taxes on unrealized (gains) losses on derivative contracts from continuing operations(8.6) (16.9)
Impairment charges from continuing operations20.0 2.0
Income taxes impairment charges from continuing operations(7.3) (0.7)
Total after-tax adjustments to net income46.9 28.4
Adjusted net income(8.7) 68.1
Net income from discontinued operations, net of income tax(27.0)
Adjusted net income (loss) from continuing operations$(8.7) $41.1
Earnings (Loss) per Common Share    
Diluted earnings per share$(0.32) $0.22
Diluted after-tax adjustments to net income per share0.27 0.16
Diluted adjusted net income (loss) per share(0.05) 0.38
Diluted from discontinued operations(0.15)
Diluted adjusted net income (loss) from continuing operations per share$(0.05) $0.23
Weighted-average common shares outstanding    
Diluted176.2 180.0

The following tables present open 2015 derivative positions as of April 24, 2015: 

QEP Energy Commodity Derivative Positions


Type of Contract


Total Volumes
Average Swap Price
Per Unit
      (in millions)  
Gas sales     (MMBtu)  
2015 SWAP NYMEX HH 46.6 $3.48
2015 SWAP IFNPCR 31.9 $3.55
2016 SWAP NYMEX HH 18.3 $3.24
2016 SWAP IFNPCR 14.6 $2.91
Oil Sales     (bbls)  
2015 SWAP NYMEX WTI 7.1 $83.93
2015 SWAP ICE Brent 0.3 $104.95
2016 SWAP NYMEX WTI 2.2 $66.06


QEP Energy Crude Oil Collars



Total Volume

Average Price Floor
Average Price
    (in millions) ($/bbl) ($/bbl)
2015 NYMEX WTI 0.3 $50.00 $64.35


QEP Energy Gas Basis Swaps


Index Less

Total Volumes
Weighted Average
Gas basis swaps     (in millions) ($/MMBtu)
2015 NYMEX HH IFNPCR 24.5 $(0.30)


QEP Marketing Commodity Derivative Positions


Type of Contract


Total Volumes
Average Swap price
per MMBtu
      (in millions)  
Gas sales     (MMBtu)  
2015 SWAP IFNPCR 1.7 $3.29
2016 SWAP IFNPCR 1.7 $3.20
Gas purchases     (MMBtu)  
2015 SWAP IFNPCR 1.6 $2.77
CONTACT: Investors: William I. Kent Director, Investor Relations 303-405-6665 Media: Brent Rockwood Director, Communications 303-672-6999

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Source: QEP Resources
QEP Resources, INC.