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QEP Resources Reports First Quarter 2017 Financial and Operating Results
  • Completed five County Line high-density Spraberry Shale test wells, with an average peak 24-hour initial production rate (IP) of 1,803 Boed (average 9,900' lateral, 88% oil)
  • Mustang Springs parent well performance exceeding Company expectations, with three wells establishing an average peak 24-hour IP of 1,384 Boed (average 7,345' lateral, 85% oil)
  • Completed a nine-well pad on South Antelope with an average peak 24-hour IP of 2,817 Boed (average 9,575' lateral, 73% oil)
  • Refractured five wells in the Haynesville Shale, with an average incremental 24-hour rate increase of 11.5 MMcfed

DENVER, April 26, 2017 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported first quarter 2017 financial and operating results. The Company reported net income of $76.9 million, or $0.32 per diluted share, for the first quarter 2017 compared with net loss of $863.8 million, or $4.55 per diluted share, for the first quarter 2016. The increase in net income was primarily due to a decrease in impairment expense, an increase in the realized and unrealized gain on derivatives, and an increase in average realized prices, partially offset by a decrease in oil equivalent production and an increase in production and property taxes and lease operating expenses for the first quarter 2017 compared with the first quarter 2016.

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, asset impairments and certain other items. Excluding these items, the Company’s first quarter 2017 Adjusted Net Loss (a non-GAAP measure) was $34.5 million, or $0.14 per diluted share, compared with Adjusted Net Loss of $101.0 million, or $0.53 per diluted share, for the first quarter 2016.

Adjusted EBITDA (a non-GAAP measure) for the first quarter 2017 was $170.7 million compared with $115.3 million for the first quarter 2016, a 48% increase, primarily due to an increase in average realized prices and a decrease in general and administrative expenses, partially offset by a decrease in oil equivalent production and an increase in production and property taxes and lease operating expenses. The definitions and reconciliations of Adjusted Net Loss and Adjusted EBITDA to net income (loss) are provided within the financial tables at the end of this release.

"During the first quarter 2017 we commenced development on our Mustang Springs asset in the Permian Basin, completing four parent wells, three of which reached an average peak 24-hour IP of 1,384 Boed in the quarter, and initiated density pilot testing on the asset," commented Chuck Stanley, Chairman, President and CEO of QEP. "Also in the Permian, we delivered very strong well results from a five-well density pilot designed to test 16-wells per mile spacing in the Spraberry Shale on our County Line asset. The wells were drilled and completed utilizing our new 'tank-style' completion method, and delivered an average peak 24-hour IP of 1,803 Boed, with the best well of the group delivering a peak 24-hour IP of 2,193 Boed. The strong initial productivity of these wells is not only notable, but also helps confirm our development well spacing and completion design assumptions for both of our Permian assets going forward."

"In the Williston Basin, we completed nine high-density wells on South Antelope which are exhibiting some of our best high-density results to date. The performance of these wells further validates our high-density development plan and continues to demonstrate that our South Antelope assets contain some of the best rock in the Williston Basin."

"Our first quarter well results highlight our focus on operational execution on our core Permian and Williston basin assets. The majority of the wells we turned to sales during the first quarter were brought on-line in the latter half, contributing to a total company average oil production rate of nearly 55.5 Mbbls per day in March 2017, favorably positioning us to drive production growth for the remainder of 2017 and beyond."

"Finally, as part of the Company's ongoing portfolio optimization process, we have formally engaged an advisor to assist with the divestiture of our Pinedale asset. We believe this transaction will be the next step in the simplification of our asset base as we strive to generate long-term value for our shareholders," concluded Stanley.

Slides for the first quarter 2017 with maps and other supporting materials referred to in this release are posted on the Company’s website at www.qepres.com.

QEP First Quarter 2017 Financial Results Summary

  • Oil equivalent production was 13,090.3 Mboe for the first quarter 2017 compared with 13,776.5 Mboe for the first quarter 2016.
  • Oil, natural gas and NGL production decreased 10%, 3%, and 1% respectively, in the first quarter 2017 compared with the first quarter 2016. First quarter 2017 production declined slightly due to the timing of completions in the Permian Basin, as the Company transitions to "tank-style" completions, and fewer completions in the Williston Basin, offset by increased gas production in Haynesville/Cotton Valley, due to the Company's successful Haynesville Shale well refracturing (refrac) program.
  • Capital investment, excluding acquisitions (on an accrual basis), was $214.3 million for the first quarter 2017 compared with $157.0 million for the first quarter 2016.
  • QEP invested $68.2 million to acquire various oil and gas properties, including proved and unproved leasehold, and includes approximately $12.2 million for surface acreage in the Permian Basin.
  • Cash and cash equivalents were $338.4 million at the end of the first quarter 2017, and the Company had no borrowings under its unsecured revolving credit facility.
  • General and administrative expense for the first quarter 2017 was $33.6 million, a decrease of 31% compared with the first quarter 2016, driven primarily by a decrease in legal expenses and a decrease in share-based compensation from changes in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan.

2017 Guidance

QEP's full year 2017 guidance remains unchanged from February 22, 2017. The guidance assumes the following:

  • An average of seven rigs for the remainder of 2017, with
    * Five rigs in the Permian Basin (horizontal)
    * One rig in the Williston Basin (horizontal)
    * One rig in Pinedale (vertical/directional)
  • No property acquisitions or divestitures
  • Ethane rejection for the entire year where QEP can elect to make such an election

Slide 5 provides additional details on QEP's 2017 Guidance.

2017 Guidance Table
  2017
  Current Forecast
Oil production (MMbbl) 21.0 - 22.0
Gas production (Bcf) 180.0 - 190.0
NGL production (MMbbl) 5.75 - 6.25
Total oil equivalent production (MMboe) 57.0 - 60.0
   
Lease operating and transportation expense (per Boe) $9.50 - $10.50
Depletion, depreciation and amortization (per Boe) $16.00 - $17.00
Production and property taxes (% of field-level revenue)   8.5 %
(in millions)
General and administrative expense(1) $160 - $170
   
Capital investment (excluding property acquisitions)  
Drilling, Completion and Equip(2) $890 - $930
Infrastructure $50 - $60
Corporate $10  
Total capital investment (excluding property acquisitions) $950 - $1,000

____________________________
(1) General and administrative expense includes approximately $32.0 million of non-cash share-based compensation expense.
(2) Drilling, Completion and Equip includes approximately $50.0 million of non-operated well completion costs.

2018 Production Outlook

QEP's 2018 production outlook remains unchanged from February 22, 2017.

Based on current commodity prices, the Company expects 2018 oil equivalent production to increase by approximately 15% to 20% compared with the midpoint of the 2017 forecast. The increase in 2018 forecasted oil production will be primarily driven by the Permian Basin, where oil production is expected to increase by approximately 60% to 80% compared with the midpoint of 2017 Permian Basin oil production of approximately 6.75 MMbbl.

Operations Summary

The table below presents a summary of QEP-operated and non-operated well completions for the three months ended March 31, 2017 and forecasted QEP-operated well completions for the full year 2017:

  Operated Completions   Non-operated Completions
  Three Months Ended   Three Months Ended
  March 31, 2017   March 31, 2017
  Gross   Net   Gross   Net
Northern Region              
Williston Basin 15     12.8     5     0.1  
Pinedale              
Uinta Basin              
Other Northern              
               
Southern Region              
Permian Basin 9     9.0          
Haynesville/Cotton Valley         8     0.8  
Other Southern              

Permian Basin

Permian Basin net production averaged approximately 15.4 Mboed (86% liquids) during the first quarter 2017, a 3% increase compared with the fourth quarter 2016 and an 8% decrease compared with the first quarter 2016. 

QEP completed and turned to sales nine gross-operated horizontal wells during the first quarter 2017, three wells in late February and six wells in mid-March (average working interest 100%), with five on County Line and four on Mustang Springs. The five wells completed on County Line were drilled using a 16-well per mile spacing unit equivalent density pattern targeting the Spraberry Shale and had an average peak 24-hour IP of 1,803 Boed (88% oil) with an average lateral length of ~9,900 feet. QEP completed these five wells using the Company's unique "tank-style" completion method, in which QEP effectively fracture stimulates a group of wells simultaneously. The results of these five wells have exceeded expectations and going forward, the Company expects to complete all future wells on its Permian acreage position using this "tank-style" completion method. (See slide 8 for a more detailed overview of the Company's "tank-style" completion method.)

The four wells completed on Mustang Springs targeted four different zones, the Middle Spraberry, Spraberry Shale, Wolfcamp A and Wolfcamp B, had an average lateral length of ~7,345 feet and will serve as the baseline parent wells for the acreage. Three of the four wells were on production for a sufficient amount of time to record a peak 24-hour IP during the quarter, with the fourth well targeting the Middle Spraberry still cleaning up at quarter end. The Spraberry Shale well had a peak 24-hour IP of 1,102 Boed (86% oil), the Wolfcamp A well had a peak 24-hour IP of 1,343 Boed (84% oil) and the Wolfcamp B well had a peak 24-hour IP of 1,707 Boed (85% oil). Notably, the two Wolfcamp wells achieved peak 24-hour IP rates while flowing naturally up casing.

QEP also drilled a second oil exploration well on its Central Basin Platform Woodford Project in Winkler County, TX. QEP drilled, completed and turned to sales its first exploration well in this area in the first quarter of 2016 to test a new play concept outside the footprint of its County Line and Mustang Springs assets. The well drilled in the first quarter 2017 targeted the Woodford Shale and was drilled to a measured depth of 20,650 feet with a lateral length of 9,310 feet. The well is scheduled to be completed in the second quarter 2017.

At the end of the first quarter 2017, the Company had 16 gross-operated horizontal wells waiting on completion (average working interest 98%) including eight in the Spraberry Shale, four in the Middle Spraberry, two in the Wolfcamp A, one in the Leonard Shale and one Woodford (Central Basin Platform) and eight gross-operated horizontal wells in the drilling process (average working interest 100%).

Current average 7,500 foot gross QEP-operated drilled and completed authorization for expenditure (AFE) well costs are as follows:

Area Formation Drilling & Completion   Facilities & Artificial Lift
    ($ in millions)
County Line        
  Spraberry Shale $ 5.0     $ 0.8  
Mustang Springs        
  Middle Spraberry $ 5.0     $ 0.7  
  Spraberry Shale $ 5.0     $ 0.7  
  Wolfcamp A $ 6.3     $ 0.7  
  Wolfcamp B $ 6.6     $ 0.7  

At the end of the first quarter 2017, the Company had five operated rigs in the Permian Basin, with two on its County Line acreage and three at Mustang Springs.

Slides 6-11 depict QEP's acreage and activity in the Permian Basin.

Williston Basin

Williston Basin net production averaged approximately 53.7 Mboed (86% liquids) during the first quarter 2017, down slightly compared with the fourth quarter 2016 and the first quarter 2016.

The Company completed and turned to sales 15 gross-operated wells during the first quarter 2017, 11 wells in late February and four wells in late March (average working interest 85%), with nine on South Antelope and six at Ft. Berthold. The nine wells on South Antelope are performing strongly, with peak 24-hour IP rates averaging 2,817 Boed (73% oil). The six wells completed on Ft. Berthold were in the early stages of flowback at end of the first quarter 2017 and did not have measurable production during the quarter. The Company also participated in five gross non-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 2%).

At the end of the first quarter 2017, QEP had six gross operated wells waiting on completion in the Williston Basin (average working interest 83%), three on South Antelope and three at Ft. Berthold, and three wells in the drilling process on South Antelope (average working interest 67%). The Company also had interests in 12 gross non-operated wells waiting on completion (average working interest 3%) at the end of the first quarter.

Current average gross QEP-operated drilled and completed AFE well costs, assuming "plug-and-perf" completion design, are $5.6 million at South Antelope and $6.2 million at Ft. Berthold, with costs associated with facilities and artificial lift adding approximately $0.8 million per well in South Antelope and $1.3 million per well at Ft. Berthold. At the end of the first quarter 2017, the Company had one operated rig in the Williston Basin on South Antelope.

Slides 12-14 depict QEP's acreage and activity in the Williston Basin.

Haynesville/Cotton Valley

Haynesville/Cotton Valley net production averaged approximately 136.4 MMcfed (22.7 Mboed) (1% liquids) during the first quarter 2017, a 5% decrease compared with the fourth quarter 2016 and a 36% increase compared with the first quarter 2016. The increase from the first quarter 2016 was primarily due to recent well refracs whereas the decrease from fourth quarter 2016 was due to the timing of first quarter 2017 refracs. During the quarter, the Company completed five QEP operated refracs, one in late February and four in mid-March (average working interest 99%). The Company also participated in eight gross non-operated wells that were completed and turned to sales during the quarter (average working interest 10%).

The Company had interests in five gross non-operated wells waiting on completion (average working interest 10%) at the end of the first quarter.

Current average gross QEP operated refrac costs are approximately $4.6 million. The Company expects to refrac approximately 20 wells during 2017. At the end of the first quarter, the Company had no rigs operating in the Haynesville/Cotton Valley.

Slides 15-17 depict QEP's acreage and activity in Haynesville/Cotton Valley.

Pinedale

Pinedale net production averaged approximately 234.3 MMcfed (39.1 Mboed) (12% liquids) during the first quarter 2017, a 6% decrease compared with the fourth quarter 2016 and a 15% decrease compared with the first quarter 2016. The Company did not complete any operated wells during the quarter.

At the end of the first quarter 2017, the Company had 15 gross-operated Pinedale wells waiting on completion (average working interest 50%) and one well in the drilling process (average working interest 20%).

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 2017, the Company had one operated rig in Pinedale.

Slide 18 depicts QEP's acreage and activity in Pinedale.

Uinta Basin

Uinta Basin net production averaged approximately 64.6 MMcfed (10.8 Mboed) (21% liquids) during the first quarter 2017, of which 37.2 MMcfed (6.2 Mboed) (10% liquids) was from the Lower Mesaverde play. This represents a 2% increase compared with the fourth quarter 2016 and a 19% decrease compared with the first quarter 2016.

First Quarter 2017 Results Conference Call

QEP’s management will discuss first quarter 2017 results in a conference call on Thursday, April 27, 2017, 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 27, 2017, 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 # 13658643. In addition, QEP’s slides for the first quarter 2017, 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 crude oil and natural gas exploration and production company focused in two regions of the United States: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Texas and Louisiana). For more information, visit QEP's' 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 capital expenditures budget; the number and location of drilling rigs; liquidity; the quality of our E&P asset portfolio; expected gross completed well costs and additional costs for facilities and artificial lift; forecasted well completions; forecasted production amounts, anticipated acquisitions or divestitures, 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; and the usefulness 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 maintain oil price and production controls; the impact of Brexit; 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; strength of the U.S. dollar; 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, 2016, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2017. 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,
  2017   2016
REVENUES (in millions, except per share amounts)
Oil sales $ 221.7     $ 143.8  
Gas sales 134.5     85.1  
NGL sales 29.0     13.6  
Other revenue 4.0     2.3  
Purchased oil and gas sales 30.9     16.5  
Total Revenues 420.1     261.3  
OPERATING EXPENSES      
Purchased oil and gas expense 29.4     16.9  
Lease operating expense 69.2     60.0  
Transportation and processing costs 70.2     73.6  
Gathering and other expense 1.5     1.3  
General and administrative 33.6     48.5  
Production and property taxes 29.1     17.8  
Depreciation, depletion and amortization 191.8     240.0  
Exploration expenses 0.4     0.3  
Impairment 0.1     1,182.4  
Total Operating Expenses 425.3     1,640.8  
Net gain (loss) from asset sales     0.5  
OPERATING INCOME (LOSS) (5.2 )   (1,379.0 )
Realized and unrealized gains (losses) on derivative contracts 160.9     50.9  
Interest and other income (expense) 0.6     2.1  
Interest expense (33.8 )   (36.7 )
INCOME (LOSS) BEFORE INCOME TAXES 122.5     (1,362.7 )
Income tax (provision) benefit (45.6 )   498.9  
NET INCOME (LOSS) $ 76.9     $ (863.8 )
       
Earnings (loss) per common share      
Basic $ 0.32     $ (4.55 )
Diluted $ 0.32     $ (4.55 )
       
Weighted-average common shares outstanding      
Used in basic calculation 240.2     189.7  
Used in diluted calculation 240.3     189.7  
Dividends per common share $     $  



QEP RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

  March 31,
 2017
  December 31,
 2016
ASSETS (in millions)
Current Assets      
Cash and cash equivalents $ 338.4     $ 443.8  
Accounts receivable, net 136.2     155.7  
Income tax receivable 18.6     18.6  
Hydrocarbon inventories, at lower of average cost or market 6.5     10.4  
Prepaid expenses and other 12.9     11.6  
Total Current Assets 512.6     640.1  
Property, Plant and Equipment (successful efforts method for oil and gas properties)      
Proved properties 14,492.6     14,232.5  
Unproved properties 881.8     871.5  
Gathering and other 307.1     301.8  
Materials and supplies 33.1     32.7  
Total Property, Plant and Equipment 15,714.6     15,438.5  
Less Accumulated Depreciation, Depletion and Amortization      
Exploration and production 8,980.4     8,797.7  
Gathering and other 106.6     101.8  
Total Accumulated Depreciation, Depletion and Amortization 9,087.0     8,899.5  
Net Property, Plant and Equipment 6,627.6     6,539.0  
Fair value of derivative contracts 21.1      
Other noncurrent assets 73.7     66.3  
TOTAL ASSETS $ 7,235.0     $ 7,245.4  
       
LIABILITIES AND EQUITY      
Current Liabilities      
Checks outstanding in excess of cash balances $ 9.2     $ 12.3  
Accounts payable and accrued expenses 296.2     269.7  
Production and property taxes 30.7     30.1  
Interest payable 32.8     32.9  
Fair value of derivative contracts 45.3     169.8  
Total Current Liabilities 414.2     514.8  
Long-term debt 2,022.4     2,020.9  
Deferred income taxes 872.7     825.9  
Asset retirement obligations 227.9     225.8  
Fair value of derivative contracts 0.3     32.0  
Other long-term liabilities 114.5     123.3  
Commitments and contingencies      
EQUITY      
Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.2 million and 240.7 million shares issued, respectively 2.4     2.4  
Treasury stock – 1.7 million and 1.1 million shares, respectively (29.9 )   (22.9 )
Additional paid-in capital 1,375.1     1,366.6  
Retained earnings 2,250.2     2,173.3  
Accumulated other comprehensive income (loss) (14.8 )   (16.7 )
Total Common Shareholders' Equity 3,583.0     3,502.7  
TOTAL LIABILITIES AND EQUITY $ 7,235.0     $ 7,245.4  


QEP RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

  Three Months Ended
  March 31,
  2017   2016
OPERATING ACTIVITIES (in millions)
Net income (loss) $ 76.9     $ (863.8 )
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:      
Depreciation, depletion and amortization 191.8     240.0  
Deferred income taxes 45.6     (446.7 )
Impairment 0.1     1,182.4  
Bargain purchase gain from acquisition 0.4      
Share-based compensation 6.0     8.0  
Amortization of debt issuance costs and discounts 1.5     1.6  
Net (gain) loss from asset sales     (0.5 )
Unrealized (gains) losses on marketable securities (0.8 )   (0.2 )
Unrealized (gains) losses on derivative contracts (177.3 )   13.5  
Changes in operating assets and liabilities 5.2     (52.6 )
Net Cash Provided by (Used in) Operating Activities 149.4     81.7  
INVESTING ACTIVITIES      
Property acquisitions (68.2 )   (14.8 )
Property, plant and equipment, including dry exploratory well expense (177.3 )   (185.8 )
Proceeds from disposition of assets 0.2     22.9  
Net Cash Provided by (Used in) Investing Activities (245.3 )   (177.7 )
FINANCING ACTIVITIES      
Checks outstanding in excess of cash balances (3.1 )   (29.8 )
Treasury stock repurchases (6.4 )   (2.9 )
Other capital contributions     0.2  
Proceeds from issuance of common stock, net     368.6  
Excess tax (provision) benefit on share-based compensation     0.2  
Net Cash Provided by (Used in) Financing Activities (9.5 )   336.3  
Change in cash and cash equivalents (105.4 )   240.3  
Beginning cash and cash equivalents 443.8     376.1  
Ending cash and cash equivalents $ 338.4     $ 616.4  


  Production by Region
  Three Months Ended March 31,
  2017   2016   Change
  (in Mboe)
Northern Region          
Williston Basin 4,834.0     4,892.6     (1 )%
Pinedale 3,514.9     4,192.5     (16 )%
Uinta Basin 968.3     1,223.6     (21 )%
Other Northern 330.4     378.7     (13 )%
Total Northern Region 9,647.6     10,687.4     (10 )%
Southern Region          
Permian Basin 1,389.5     1,521.3     (9 )%
Haynesville/Cotton Valley 2,046.7     1,523.2     34 %
Other Southern 6.5     44.6     (85 )%
Total Southern Region 3,442.7     3,089.1     11 %
Total production 13,090.3     13,776.5     (5 )%


  Total Production
  Three Months Ended March 31,
  2017   2016   Change
Oil (Mbbl) 4,682.7     5,176.4     (10 )%
Gas (Bcf) 42.3     43.4     (3 )%
NGL (Mbbl) 1,355.4     1,365.0     (1 )%
Total production (Mboe) 13,090.3     13,776.5     (5 )%
Average daily production (Mboe) 145.4     151.4     (4 )%


  Prices
  Three Months Ended March 31,
  2017   2016   Change
Oil (per bbl)          
Average field-level price $ 47.35     $ 27.77      
Commodity derivative impact (0.43 )   7.87      
Net realized price $ 46.92     $ 35.64     32 %
Gas (per Mcf)          
Average field-level price $ 3.18     $ 1.96      
Commodity derivative impact (0.34 )   0.50      
Net realized price $ 2.84     $ 2.46     15 %
NGL (per bbl)          
Average field-level price $ 21.36     $ 9.97      
Commodity derivative impact          
Net realized price $ 21.36     $ 9.97     114 %
Average net equivalent price (per Boe)          
Average field-level price $ 29.43     $ 17.60      
Commodity derivative impact (1.24 )   4.52      
Net realized price $ 28.19     $ 22.12     27 %


  Operating Expenses
  Three Months Ended March 31,
  2017   2016   Change
  (per Boe)
Lease operating expense $ 5.29     $ 4.36     21 %
Transportation and processing costs 5.36     5.34     %
Production and property taxes 2.23     1.29     73 %
Total production costs $ 12.88     $ 10.99     17 %


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

Adjusted EBITDA
This release contains references to the non-GAAP measure of Adjusted EBITDA. 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 items. Management uses Adjusted EBITDA to evaluate QEP's financial performance and trends, make operating decisions and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP's performance from period to period. QEP's Adjusted EBITDA may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.

Below is a reconciliation of Net Income (Loss) (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.

  Three Months Ended March 31,
  2017   2016
  (in millions)
Net income (loss) $ 76.9     $ (863.8 )
Interest expense 33.8     36.7  
Interest and other (income) expense (0.6 )   (2.1 )
Income tax provision (benefit) 45.6     (498.9 )
Depreciation, depletion and amortization 191.8     240.0  
Unrealized (gains) losses on derivative contracts (177.3 )   13.5  
Exploration expenses 0.4     0.3  
Net (gain) loss from asset sales     (0.5 )
Impairment 0.1     1,182.4  
Other(1)     7.7  
Adjusted EBITDA $ 170.7     $ 115.3  

 ____________________________
(1) Reflects legal expenses incurred during the three months ended March 31, 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts 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 items. Management uses Adjusted Net Income (Loss) to evaluate QEP’s financial performance and trends, make operating decisions, and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP’s performance from period to period. QEP’s Adjusted Net Income (Loss) may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.

Below is a reconciliation of Net Income (Loss) (a GAAP measure) to Adjusted Net Income (Loss). This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.

  Three Months Ended March 31,
  2017   2016
  (in millions, except earnings per share)
Net income (loss) $ 76.9     $ (863.8 )
Adjustments to net income (loss)      
Unrealized (gains) losses on derivative contracts (177.3 )   13.5  
Income taxes on unrealized (gains) losses on derivative contracts(1) 65.8     (4.9 )
Net (gain) loss from asset sales     (0.5 )
Income taxes on net (gain) loss from asset sales(1)     0.2  
Impairment 0.1     1,182.4  
Income taxes on impairment(1)     (432.8 )
Other(2)     7.7  
Income taxes on other(1)     (2.8 )
Total after tax adjustments to net income (111.4 )   762.8  
Adjusted Net Income (Loss) $ (34.5 )   $ (101.0 )
       
Earnings (Loss) per Common Share      
Diluted earnings per share $ 0.32     $ (4.55 )
Diluted after-tax adjustments to net income (loss) per share (0.46 )   4.02  
Diluted Adjusted Net Income per share $ (0.14 )   $ (0.53 )
       
Weighted-average common shares outstanding      
Diluted 240.3     189.7  

 ____________________________
(1) Income tax impact of adjustments is calculated using QEP’s statutory rate of 37.1% and 36.6% for the three months ended March 31, 2017 and 2016, respectively.
(2) Reflects legal expenses incurred during the three months ended March 31, 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.


The following tables present QEP's volumes and average prices for its open derivative positions as of April 21, 2017:

Production Commodity Derivative Swaps
Year   Index   Total Volumes   Average Swap Price
per Unit
        (in millions)    
Oil sales       (bbls)   ($/bbl)
2017   NYMEX WTI   10.7     $ 51.50  
2018   NYMEX WTI   9.9     $ 53.59  
Gas sales       (MMBtu)   ($/MMBtu)
2017   NYMEX HH   66.2     $ 2.87  
2017   IFNPCR   22.1     $ 2.51  
2018   NYMEX HH   91.3     $ 2.98  


Production Commodity Derivative Gas Collars
Year   Index   Total Volumes   Average Price Floor   Average Price Ceiling
        (in millions)        
        (MMBtu)   ($/MMBtu)   ($/MMBtu)
2017   NYMEX HH   7.4     $ 2.50     $ 3.50  


Production Commodity Derivative Basis Swaps
Year   Index Less Differential   Index   Total Volumes   Weighted-Average
Differential
            (in millions)    
Oil sales           (bbls)   ($/bbl)
2017   NYMEX WTI   Argus WTI Midland   3.2     $ (0.66 )
2018   NYMEX WTI   Argus WTI Midland   3.7     $ (1.01 )
Gas sales           (MMBtu)   ($/MMBtu)
2017   NYMEX HH   IFNPCR   34.3     $ (0.18 )
2018   NYMEX HH   IFNPCR   7.3     $ (0.16 )


Storage Commodity Derivative Gas Swaps
Year   Type of Contract   Index   Total Volumes   Average Swap Price
per Unit
            (in millions)    
Gas sales           (MMBtu)   ($/MMBtu)
2017   SWAP   IFNPCR   1.8     $ 2.75  

 

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

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

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