QEP Resources, Inc.

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News Release

QEP Resources Announces Strategic Initiatives for an Accelerated Transition to a Pure-Play Permian Basin Company, Reports Fourth Quarter and Full Year 2017 Financial and Operating Results, and Provides Initial 2018 Guidance and Capital Investment Plan

Hires financial advisors to assist with divestiture of Williston and Uinta basin assets

Authorizes $1.25 billion share repurchase program to be funded primarily with proceeds from asset sales

DENVER, Feb. 28, 2018 (GLOBE NEWSWIRE) --   QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today announced strategic initiatives to transition to a pure-play Permian Basin company, reported fourth quarter and full year 2017 financial and operating results, and provided initial 2018 guidance and capital investment plan.

2018 Strategic and Financial Initiatives

QEP’s Board of Directors has unanimously approved several strategic and financial initiatives to transition the Company to a pure-play Permian Basin company and to address the significant discount to net asset value reflected in the Company's share price.

Strategic Initiatives

  • Engaged financial advisors to assist with the divestiture of the Company’s Williston and Uinta basin assets, with data rooms expected to be opened in late March or early April
  • Market remaining non-Permian assets, including the Haynesville/Cotton Valley (Haynesville), in the second half of 2018

Financial Initiatives

  • Use proceeds from asset sales to fund Permian Basin development program, until the program reaches operating cash flow neutrality in 2019, reduce debt and return cash to shareholders through share repurchases
  • Authorized a $1.25 billion share repurchase program(1)
  • Approved 2018 capital investment plan of approximately $1.075 billion, of which approximately 65% will be directed toward the Permian Basin

"The strategic initiatives announced today are responsive to ongoing shareholder feedback and fit with our long-term goal of becoming a more oil-focused company. The initiatives will allow us to simplify our portfolio, streamline our operations, and sharpen our focus on our Permian Basin assets, quickly resulting in QEP becoming a leading pure-play Permian company. Today our Permian Basin assets consist of approximately 44,000 net acres in the core of the northern Midland Basin. The assets delivered 8.2 MMboe of net production in 2017 with estimated total proved year-end 2017 reserves of 272.7 MMboe,” commented Chuck Stanley, Chairman, President and CEO of QEP.

____________________________
(1)        Subject to available liquidity, market conditions and proceeds from asset sales.

"We expect to continue to make progress developing our Permian Basin assets in 2018 utilizing “tank-style” completions. We believe this approach maximizes the economic recovery of oil through the simultaneous development of multiple subsurface targets, while improving capital efficiency through shared surface facilities, which we believe will reduce per-unit operating costs and result in expanded operating margins and improve our returns on invested capital. Based on our current plan, which contemplates running five to six rigs and assumes commodity prices averaging $55 per barrel and $3 per MMBtu, we expect the Permian Basin assets will achieve operating cash flow neutrality in 2019, while delivering peer leading production growth.”

"We intend to use the proceeds from asset sales to fund the ongoing development of our core Permian operations, reduce debt, and return cash to shareholders through a significant share repurchase program."

"I want to personally thank all of our employees for their continued commitment to the safe and efficient operation of all of our assets as we work together to accomplish this transition,” continued Stanley.

The Company has posted to its website www.qepres.com a presentation that supplements the information provided in this release. See slide 3 in the February 2018 QEP Investor Presentation for a summary of our announced Strategic Initiatives.

Full Year 2017 Highlights

  • Net Income of $269.3 million, or $1.12 per fully-diluted share
  • Total oil equivalent production of 53.1 MMboe, of which 37% was crude oil
  • Record Permian Basin oil production of 6.1 MMbbl, a 52% increase
  • Natural gas production of 168.9 Bcf, including 72.9 Bcf in the Haynesville
  • Year-end total proved reserves of 684.7 MMboe, including record proved oil reserves of 320.5 MMbbl 
  • Divested Pinedale Anticline natural gas asset for net cash proceeds of $718.2 million, after purchase price adjustments (the Pinedale Divestiture)
  • Acquired approximately 15,100 net acres in the core of the northern Midland Basin (2017 Permian Basin Acquisition)

"Our accomplishments in 2017 were significant, including the divestiture of our Pinedale Anticline natural gas asset and expansion of our tier one acreage position in the Permian Basin. We continued to accelerate our development activity while actively enhancing our drilling and completion designs in the Permian Basin. We also had success with our refrac programs in both the Haynesville and the Williston Basin and we successfully completed our first long-lateral horizontal well utilizing state-of-the-art completion techniques in the Haynesville. As we begin 2018, the Company is undertaking a number of strategic initiatives that will result in QEP becoming a pure-play Permian Basin company,” concluded Stanley.

QEP Fourth Quarter and Full Year 2017 Financial Results

The Company reported net income of $150.3 million for the fourth quarter 2017, or $0.62 per diluted share, compared with a loss of $133.3 million, or $0.56 per diluted share, in the fourth quarter 2016. For the year ended December 31, 2017, QEP reported net income of $269.3 million, or $1.12 per diluted share, compared with a net loss of $1,245.0 million, or $5.62 per diluted share, for the comparable 2016 period. Net income for the fourth quarter and year ended December 31, 2017, was positively impacted by a $307.9 million tax benefit, primarily due to a revaluation of the Company’s net deferred tax liability to reflect the change in the federal corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act signed into law on December 22, 2017 (Tax Reform Act).

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 fourth quarter 2017 Adjusted Net Income (a non-GAAP measure) was $274.0 million, or $1.13 per diluted share, compared with an Adjusted Net Loss of $36.2 million, or $0.15 per diluted share, in the fourth quarter 2016. For the year ended December 31, 2017, the Company’s Adjusted Net Income was $185.2 million, or $0.77 per diluted share, compared with an Adjusted Net Loss of $232.8 million, or $1.05 per diluted share, for 2016.

Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2017 was $195.1 million, compared to $174.5 million in the fourth quarter 2016. For the year ended December 31, 2017, the Company reported Adjusted EBITDA of $736.1 million compared to $628.1 million for full year 2016, a 17% increase, primarily due to a 15% increase in average realized prices, a 15% decrease in transportation and processing costs and a 22% decrease in general and administrative expenses. These changes were partially offset by a 5% decrease in oil equivalent production, a 31% increase in lease operating expense and a 21% increase in production and property taxes. The definitions and reconciliations of Adjusted EBITDA and Adjusted Net Income to Net Income (Loss) are provided within the financial tables of this release.

Production

Oil equivalent production was 12.1 MMboe for the fourth quarter 2017 compared with 13.7 MMboe for the fourth quarter 2016. Oil production increased 7%, while natural gas and NGL production decreased 22% and 23%, respectively. Fourth quarter 2017 equivalent production was impacted by weather-related issues in the Williston and Permian basins, 33.5 Mboe and 52.0 Mboe respectively, and the Pinedale Divestiture in September 2017. The decrease was partially offset by increased production related to ongoing completion activity in the Permian Basin and Haynesville. For the year ended December 31, 2017, oil equivalent production was 53.1 MMboe compared with 55.8 MMboe for the comparable 2016 period, a 5% decrease. Adjusted for the Pinedale Divestiture, production increased 22% in the fourth quarter and 8% for the year ended December 31, 2017.

Operating Expenses

During the fourth quarter 2017, lease operating expense (LOE) was $6.58 per Boe, an increase of 47% compared with the fourth quarter 2016. For the year ended December 31, 2017, LOE was $5.55 per Boe, an increase of 38% compared with the prior year. The increase in LOE during the fourth quarter and year ended December 31, 2017 was driven by an increase in workovers in the Williston and Permian Basins and Haynesville, power and fuel expenses, services and supplies expenses in the Permian Basin and increased water disposal expenses in Haynesville.

During the fourth quarter 2017, transportation and processing costs were $3.54 per Boe, a decrease of 31% compared with the fourth quarter 2016. For the year ended December 31, 2017, transportation and processing costs were $4.61 per Boe, a decrease of 11% compared with the prior year. The decrease in transportation and processing costs during the fourth quarter and year ended December 31, 2017 was primarily attributable to decreases in Pinedale, primarily related to the Pinedale Divestiture and recovery of historical transportation costs, and in Haynesville related to the recovery of fees for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest.

During the fourth quarter 2017, production and property taxes were $2.34 per Boe, an increase of 8% compared with the fourth quarter 2016. For the year ended December 31, 2017, production and property taxes were $2.15 per Boe, an increase of 26% compared with the prior year, primarily a result of increased oil and gas revenues primarily from higher field-level prices partially offset by lower production.

General and administrative expense for the fourth quarter 2017 was $45.2 million, or $3.75 per Boe, an increase of 33% compared with the fourth quarter 2016. The increase in fourth quarter 2017 was primarily due to an increase in share-based compensation expense and an increase in benefits, partially offset by a decrease in legal expenses. For the year ended December 31, 2017, general and administrative expense was $153.5 million, or $2.89 per Boe, a decrease of 18% compared with the prior year. The decrease for the year ended December 31, 2017, was driven primarily by a decrease in legal expenses and loss contingencies and a decrease in share-based compensation expense, partially offset by an increase in labor, benefits and employee expenses.

Capital Investment

Total capital investment was $1,056.3 million (on an accrual basis) for the fourth quarter 2017, compared with $714.6 million for the fourth quarter 2016. Total capital investment for the year ended December 31, 2017 (on an accrual basis), was $2,035.0 million, up $859.7 million compared with the year ended December 31, 2016.

Capital investment, excluding property acquisitions was $372.2 million (on an accrual basis) for the fourth quarter 2017, compared with $145.5 million for the fourth quarter 2016. Capital investment, excluding property acquisitions, for the year ended December 31, 2017 (on an accrual basis), was $1,219.8 million, up $689.7 million compared with the year ended December 31, 2016.

During the year ended December 31, 2017, the Company invested $815.2 million to acquire various oil and gas properties, undeveloped leasehold acreage, producing wells and additional surface acreage, primarily in the Permian Basin.

2017 Permian Basin Acquisition

In October 2017, QEP acquired additional oil and gas properties in the 2017 Permian Basin Acquisition for an aggregate purchase price of $720.7 million, subject to post-closing purchase price adjustments. The 2017 Permian Basin Acquisition assets consist of approximately 15,100 net acres, mainly in Martin County, Texas, an increase of approximately 1,300 net acres compared to the 13,800 net acres originally announced in July 2017. QEP structured the 2017 Permian Basin Acquisition transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the Pinedale Divestiture.

In the fourth quarter 2017, QEP made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. If all offers are accepted, the Company now anticipates that the aggregate purchase price for the additional oil and gas interests will not exceed $50.0 million. These acquisitions are expected to close in the first half of 2018. When combined with the acreage from the 2017 Permian Basin Acquisition, the Company expects the total acquired acreage to be approximately 16,000 net acres.


Asset Divestitures

In addition to the Pinedale Divestiture, as a part of the Company’s ongoing effort to simplify its portfolio, QEP entered into agreements to sell, or closed on the sale of several non-core assets for total proceeds of approximately $18.9 million during the fourth quarter 2017. For the year ended December 31, 2017, the Company received total proceeds from asset divestitures of $806.8 million.


Liquidity

During the fourth quarter 2017, the Company issued $500.0 million of 5.625% Senior Notes due in 2026 and used the proceeds to repay $445.7 million of debt, as follows:

  • Redeemed $134.0 million of its outstanding 6.80% Senior Notes due in 2018;
  • Purchased $84.3 million of its 6.80% Senior Notes due in 2020 pursuant to a tender offer; and
  • Purchased $227.4 million of its 6.875% Senior Notes due in 2021 pursuant to a tender offer.


2018 Guidance

The following guidance excludes the impacts of our announced strategic initiatives.

QEP's quarterly and full year 2018 guidance and related assumptions are shown below. The Company’s guidance assumes an oil price of $55 per barrel and a natural gas price of $3 per MMBtu and the following additional assumptions:

Rig Count

  • Permian (average of five rigs)
  • Williston (average of one-half rig)
  • Haynesville (average of one-half rig)

Wells Put on Production / Refracs:

  • Permian Basin: approximately 95 net operated wells put on production
  • Company: approximately 111 net operated wells put on production
  • Refracs: approximately 35 net, in the Williston Basin and the Haynesville
     
  • No property acquisitions or divestitures
  • Ethane rejection for the entire year where QEP can make such an election

The Company anticipates updating guidance as it completes the contemplated divestitures.

 
2018 Guidance
 
    2018  
   
Oil production (MMbbl) 21.0 - 22.5
Gas production (Bcf) 132.0 - 143.0
NGL production (MMbbl) 4.7 - 5.2
Total oil equivalent production (MMboe) 47.7 - 51.5
   
Lease operating and transportation expense (per Boe) $9.00 - $10.00
Depletion, depreciation and amortization (per Boe) $17.50 - $18.50
Production and property taxes (% of field-level revenue)  8.5%
(in millions)
General and administrative expense(1) $185 - $205
   
Capital investment (excluding property acquisitions)  
Drilling, Completion and Equip(2) $965 - $1,065
Infrastructure $50 
Corporate $10 
Total capital investment (excluding property acquisitions) $1,025 - $1,125

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(1)        General and administrative expense includes approximately $25.0 million of non-cash share-based compensation expense and approximately $20.0 million of estimated retention program expense.
(2)        Approximately 65% of the planned capital investment is focused on projects in the Permian Basin. Drilling, Completion and Equip includes approximately $20.0 million of non-operated well completion costs.

 
2018 Quarterly Production Guidance
 
  1Q 2018 2Q 2018 3Q 2018 4Q 2018 2018
QEP Resources Current Forecast
Oil production (MMbbl) 4.5 - 4.7 4.9 - 5.2 5.7 - 6.3 5.8 - 6.2 21.0 - 22.5
Gas production (Bcf) 31.7 - 33.6 33.9 - 36.8 35.9 - 38.9 30.5 - 33.7 132.0 - 143.0
NGL production (MMbbl) 1.0 - 1.1 1.1 - 1.2 1.3 - 1.4 1.3 - 1.5 4.7 - 5.2
Total oil equivalent production (MMboe) 10.8 - 11.4 11.7 - 12.5 13.0 - 14.2 12.2 - 13.3 47.7 - 51.5
Total wells put on production (net) 20 46 25 20 111
Total refracs put on production (net) 14 13 8 0 35
           
Permian Basin          
Oil production (MMbbl) 2.0 - 2.1 2.6 - 2.7 2.8 - 3.1 3.2 - 3.4 10.6 - 11.3
Gas production (Bcf) 1.6 - 1.8 2.0 - 2.2 2.3 - 2.5 2.4 - 2.6 8.3 - 9.1
NGL production (MMbbl) 0.30 - 0.35 0.40 - 0.45 0.45 - 0.50 0.50 - 0.55 1.65 - 1.85
Permian Basin equivalent production (MMboe) 2.6 - 2.8 3.3 - 3.5 3.6 - 4.0 4.1 - 4.4 13.6 -14.7
Permian Basin wells put on production (net) 18 34 23 20 95
           

Production Outlook

At the midpoint of guidance, the Company expects to deliver year-over-year total oil-equivalent production growth of approximately 15% in 2018, compared with 2017 volumes after adjusting for the impact of the Pinedale Divestiture, and Permian Basin total oil-equivalent Permian Basin production is expected to grow to 13.6 - 14.7 MMboe, an increase of over 70%, compared with 2017 volumes.

The Company expects to deliver year-over-year crude oil production growth of approximately 13% in 2018, compared with 2017 volumes, after adjusting for the impact of the 2017 Pinedale Divestiture, and Permian Basin crude oil volumes are expected to grow to 10.6 - 11.3 MMbbl.

The Company expects to deliver year-over-year natural gas production growth of approximately 18%, at the midpoint, in 2018, compared with 2017 volumes, after adjusting for the 2017 Pinedale Divestiture, primarily from increased drilling and refrac activity in the Haynesville.

Operations Summary

Permian Basin

Permian Basin net production averaged approximately 27.8 Mboed (89% liquids) during the fourth quarter 2017, a Company record for the Permian Basin and a 9% increase compared with the third quarter 2017, and an 87% increase compared with the fourth quarter 2016.

QEP completed and turned to sales 24 gross-operated horizontal wells in the fourth quarter 2017 (average working interest 100%), in two drilling spacing units ("DSU'"), one with eight wells and the other with 16 wells. Five wells in the eight well DSU targeted the Spraberry Shale and were completed with an average lateral length of 7,355 feet and achieved an average peak 24-hour IP rate of 185 Boed per 1,000 feet (86% oil). In the sixteen well DSU, three of the wells targeted the Wolfcamp A and five the Wolfcamp B. The Wolfcamp A wells were completed with an average lateral length of 7,355 feet and achieved an average peak 24-hour IP rate of 164 Boed per 1,000 feet (83% oil). The Wolfcamp B wells were completed with an average lateral length of 7,350 feet and achieved an average peak 24-hour IP rate of 133 Boed per 1,000 feet (82% oil). None of the wells on either of the pads had reached 30-day peak rates at the end of the fourth quarter 2017.

At the end of the fourth quarter 2017, the Company had 36 gross-operated horizontal wells waiting on completion (working interest 100%) and 11 gross-operated horizontal wells being drilled (average working interest 99%) and an additional 18 wells for which surface casing has been set (average working interest 95%) as of December 31, 2017.

Current QEP-operated drilled and completed authorization for expenditure (AFE) well costs for the Permian Basin are detailed on slide 23 of the February 2018 Investor Presentation.

At the end of the fourth quarter 2017, the Company had six operated rigs in the Permian Basin.

Slides 9-15 in the February 2018 Investor Presentation depict QEP's acreage and activity in the Permian Basin.

Williston Basin

Williston Basin net production averaged approximately 48.7 Mboed (86% liquids) during the fourth quarter 2017, a 5% increase compared with the third quarter 2017 and a 9% decrease compared with the fourth quarter 2016.

The Company completed and turned to sales two gross operated wells during the fourth quarter 2017, both of which were on Ft. Berthold (average working interest 90%). The wells were completed with an average lateral length of 9,928 feet and had an average peak 24-hour IP of 230 Boed per 1,000 feet (92% oil) and an average IP 30 rate of 105 Boed per 1,000 feet (92% oil).

The Company also completed nine gross-operated refracs, five on South Antelope (average working interest 100%) and four on Ft. Berthold (average working interest 100%) during the fourth quarter. The five refracs on South Antelope achieved an average per well IP 30 rate increase of 822 Boed/well (74% oil). Pre-refrac, the five wells averaged 77 Boed/well (64% oil), while post-refrac the five wells had an average peak 24-hour IP of 1,460 Boed/well (73% oil) and an average IP 30 of 899 Boed/well (74% oil). The four refracs on Ft. Berthold were still in the early stages of cleanup as of the end of the fourth quarter 2017.

At the end of the fourth quarter 2017, QEP had five gross-operated wells waiting on completion (average working interest 94%) and two wells being drilled (average working interest 100%), all on South Antelope.

Current QEP-operated drilled and completed AFE well costs and refrac costs for the Williston Basin are detailed on slide 23 of the February 2018 Investor Presentation.

At the end of the fourth quarter 2017, the Company had one operated rig in the Williston Basin, operating on South Antelope.

Slides 16-18 in the February 2018 Investor Presentation depict QEP's acreage and activity in the Williston Basin.

Haynesville

Haynesville net production averaged approximately 262.7 MMcfed (43.8 Mboed) (0% liquids) during fourth quarter 2017, a 21% increase compared with the third quarter 2017 and an 83% increase compared with the fourth quarter 2016.

The Company completed and turned to sales two gross operated wells during the fourth quarter 2017 (average working interest 99%). One of the two wells completed reached peak production during the quarter. The first well drilled and completed in the quarter had an IP 24 rate of 21.1 MMcfed and an IP 30 rate of 19.5 MMcfed (100% gas) with a lateral length of 5,102 feet. The second well drilled and completed during the quarter was still in the process of cleaning up at the end of the quarter and had a lateral length of 10,480 feet. During the quarter, the Company also completed five QEP-operated refracs, with an average incremental 24-hour rate increase of 17.4 MMcfed/well (average working interest 99%).

Current QEP-operated drilled and completed AFE well costs and refrac costs for Haynesville are detailed on slide 23 of the February 2018 Investor Presentation.

At the end of the fourth quarter, the Company had one operated rig in Haynesville.

Slides 19-20 in the February 2018 Investor Presentation depict QEP's acreage and activity in Haynesville.

Uinta Basin

Uinta Basin net production averaged approximately 54.4 MMcfed (9.1 Mboed) (23% liquids) during the fourth quarter 2017. This represents a 7% decrease in production compared with the third quarter 2017 and a 14% decrease compared with the fourth quarter 2016.

At the end of the fourth quarter, the Company had one drilling rig in the Uinta Basin.

Estimated Proved Reserves

At December 31, 2017, QEP's estimated proved reserves were approximately 684.7 MMboe, a 6% decrease compared with 2016, primarily due to the sale of reserves in-place associated with the Pinedale Divestiture, which was partially offset by an increase of proved reserves as a result of extensions and discoveries in the Permian Basin and the 2017 Permian Basin Acquisition. Williston Basin proved reserves decreased primarily from under performance of wells in our high density pilot test areas. Other Northern proved reserves decreased primarily due to property divestitures in 2017. Uinta Basin proved reserves decreased primarily due to changing from a vertical well development plan to a horizontal well development plan. Haynesville/Cotton Valley's increase of proved reserves is primarily the result of the successful refracturing program in 2017. Extensions and discoveries were 86.4 MMboe, were primarily in the Permian Basin and related to new well completions and associated new PUD locations. Approximately 56% of total proved reserves at year-end 2017 and 42% of total proved reserves at year-end 2016 were crude oil and NGL. Proved developed reserves were 253.1 MMboe, or 37%, of total estimated proved reserves at year-end 2017.

A reconciliation of reported quantities of estimated proved reserves is summarized in the table below:

                 
    Oil   Gas   NGL   Total
    (MMbbl)   (Bcf)   (MMbbl)   (MMboe)(1)
Balance at December 31, 2016   238.6     2,553.8     67.2     731.4  
Revisions of previous estimates   3.7     12.5     (3.1 )   2.7  
Extensions and discoveries   59.1     101.9     10.4     86.4  
Purchase of reserves in place   46.6     125.5     8.7     76.3  
Sale of reserves in place   (7.9 )   (831.2 )   (12.6 )   (159.0 )
Production   (19.6 )   (168.9 )   (5.4 )   (53.1 )
Balance at December 31, 2017   320.5     1,793.6     65.2     684.7  

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(1)       Natural gas is converted to crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

Details on the reported quantities of estimated year-end 2017 and 2016 proved reserves presented by operating area, proved reserve category and percentage of total estimated proved reserves composed of crude oil and NGL (liquids) are as follows:

                 
    Total (in MMboe)   % of total   PUD %   liquids %
For the year ended December 31, 2017            
Northern Region                
Williston Basin   146.9     21 %   36 %   88 %
Pinedale       %   %   %
Uinta Basin   100.8     15 %   62 %   15 %
Other Northern   4.5     1 %   %   13 %
Southern Region                
Permian Basin   272.7     40 %   77 %   88 %
Haynesville/Cotton Valley   159.8     23 %   %   %
Other Southern       %   %   %
Total proved reserves   684.7     100 %   63 %   56 %
                 
For the year ended December 31, 2016            
Northern Region                
Williston Basin   160.2     22 %   37 %   86 %
Pinedale   160.7     22 %   14 %   13 %
Uinta Basin   106.1     14 %   62 %   15 %
Other Northern   12.3     2 %   %   6 %
Southern Region                
Permian Basin   147.8     20 %   81 %   88 %
Haynesville/Cotton Valley   144.3     20 %   74 %   %
Other Southern       %   %   %
Total proved reserves   731.4     100 %   51 %   42 %


Fourth Quarter and Full Year 2017 Results Conference Call

QEP's management will discuss fourth quarter and full year 2017 results in a conference call on Thursday, March 1, 2018, beginning at 9:00 a.m. EST. 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 March 29, 2018, 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 #13675566. In addition, QEP’s slides for the fourth 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 and Utah) and the Southern Region (primarily Texas and Louisiana). 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: planned strategic and financial initiatives; timing and divestiture of assets; use of proceeds from sale of assets; amount and funding for share repurchase program; simplifying our asset portfolio; streamlining operations; focus on Permian Basin assets; becoming a leading pure-play Permian Basin company; utilization of our tank-style completion methodology and anticipated benefits from this methodology; amount and allocation of planned capital expenditures and related assumptions; achieving cash flow neutrality in 2019; delivering peer leading production growth; the number and location of drilling rigs to be deployed; forecasted production amounts and growth and related assumptions; forecasted lease operating and transportation expense, depletion, depreciation and amortization expense, general and administrative expense, non-cash share based compensation expense, retention program expense, production and property taxes and capital investment for 2018 and related assumptions for such guidance; 2018 quarterly production guidance and assumptions for such guidance; plans to update guidance; impact of Tax Reform Act; plans to reject ethane in 2018; estimated reserves; forecasted number of new wells and the locations of such wells; number of workover wells. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: timing and amount of asset divestitures and share repurchases; changes in oil, gas and NGL 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; market conditions; global geopolitical and macroeconomic factors; the activities of the Organization of Petroleum Exporting Countries (OPEC); general economic conditions, including interest rates; changes in local, regional, national and global demand for natural oil, gas and NGL; impact of new laws and regulations, including the use of hydraulic fracture stimulation; impact of U.S. dollar exchange rates on oil, gas and NGL prices; elimination of federal income tax deductions for oil and gas exploration and development; guidance for implementation of Tax Reform Act; actual proceeds from asset sales; actions of activist shareholders; 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, 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.

Disclosures regarding non-proved reserves

The Securities and Exchange Commission (SEC) requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The SEC permits optional disclosure of probable and possible reserves; however, QEP has made no such disclosures in its filings with the SEC. Estimates of probable and possible reserves are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially more risks of actually being realized. Actual quantities that may be ultimately recovered from QEP’s interests may differ substantially from the reserve estimates contained in this release. Investors are urged to closely consider the disclosures and risk factors about the Company’s reserves in its Annual Report on Form 10-K for the year ended December 31, 2017.

Contact

Contact    
Investors:   Media:
William I. Kent, IRC   Brent Rockwood
Director, Investor Relations   Director, Communications
303-405-6665   303-672-6999


       
       
QEP RESOURCES, INC.      
CONSOLIDATED STATEMENTS OF OPERATIONS      
  Three Months Ended   Year Ended
  December 31,   December 31,
  2017   2016   2017   2016
REVENUES (in millions, except per share amounts)
Oil sales $ 283.7     $ 216     $ 939.4     $ 769.1  
Gas sales 94.6     129.6     494     417.1  
NGL sales 27.9     27.3     111.9     83.5  
Other revenues 4.7     1.9     15.0     6.2  
Purchased oil and gas sales 18.1     24.9     62.6     101.2  
Total Revenues 429.0     399.7     1,622.9     1,377.1  
OPERATING EXPENSES              
Purchased oil and gas expense 18.9     24.7     64.3     105.5  
Lease operating expense 79.4     61.4     294.8     224.7  
Transportation and processing costs 42.7     70.3     245.3     289.2  
Gathering and other expense 2.3     1.2     7.3     5.0  
General and administrative 45.2     38.6     153.5     196.5  
Production and property taxes 28.2     29.5     114.3     94.8  
Depreciation, depletion and amortization 194.3     203.6     754.5     871.1  
Exploration expenses 0.3     0.8     22.0     1.7  
Impairment 50.5     6.1     78.9     1,194.3  
Total Operating Expenses 461.8     436.2     1,734.9     2,982.8  
Net gain (loss) from asset sales 8.3         213.5     5.0  
OPERATING INCOME (LOSS) (24.5 )   (36.5 )   101.5     (1,600.7 )
Realized and unrealized gains (losses) on derivative contracts (138.8 )   (147.9 )   24.5     (233.0 )
Interest and other income (expense) (0.9 )   18.1     1.6     23.7  
Loss from early extinguishment of debt (32.7 )       (32.7 )    
Interest expense (34.7 )   (34.0 )   (137.8 )   (143.2 )
INCOME (LOSS) BEFORE INCOME TAXES (231.6 )   (200.3 )   (42.9 )   (1,953.2 )
Income tax (provision) benefit 381.9     67.0     312.2     708.2  
NET INCOME (LOSS) $ 150.3     $ (133.3 )   $ 269.3     $ (1,245.0 )
               
Earnings (loss) per common share              
Basic $ 0.62     $ (0.56 )   $ 1.12     $ (5.62 )
Diluted $ 0.62     $ (0.56 )   $ 1.12     $ (5.62 )
               
Weighted-average common shares outstanding              
Used in basic calculation 241.0     239.6     240.6     221.7  
Used in diluted calculation 241.0     239.6     240.6     221.7  
Dividends per common share $     $     $     $  
                               


       
QEP RESOURCES, INC.      
CONSOLIDATED BALANCE SHEETS      
       
  December 31,   December 31,
2017 2016
ASSETS (in millions)
Current Assets      
Cash and cash equivalents $     $ 443.8  
Accounts receivable, net 142.1     155.7  
Income tax receivable 4.9     18.6  
Fair value of derivative contracts 3.4      
Hydrocarbon inventories, at lower of average cost or net realizable value 3.6     10.4  
Prepaid expenses 10.7     11.4  
Other current assets 0.7     0.2  
Total Current Assets 165.4     640.1  
Property, Plant and Equipment (successful efforts method for oil and gas properties)    
Proved properties 12,470.9     14,232.5  
Unproved properties 1,095.8     871.5  
Gathering and other 319.7     301.8  
Materials and supplies 37.8     32.7  
Total Property, Plant and Equipment 13,924.2     15,438.5  
Less Accumulated Depreciation, Depletion and Amortization      
Exploration and production 6,642.9     8,797.7  
Gathering and other 124.3     101.8  
Total Accumulated Depreciation, Depletion and Amortization 6,767.2     8,899.5  
Net Property, Plant and Equipment 7,157.0     6,539.0  
Fair value of derivative contracts 0.1      
Other noncurrent assets 72.3     66.3  
TOTAL ASSETS $ 7,394.8     $ 7,245.4  
       
LIABILITIES AND EQUITY      
Current Liabilities      
Checks outstanding in excess of cash balances $ 44.0     $ 12.3  
Accounts payable and accrued expenses 372.1     269.7  
Production and property taxes 31.6     30.1  
Interest payable 26.0     32.9  
Fair value of derivative contracts 103.6     169.8  
Total Current Liabilities 577.3     514.8  
Long-term debt 2,160.8     2,020.9  
Deferred income taxes 518.0     825.9  
Asset retirement obligations 206.6     225.8  
Fair value of derivative contracts 31.8     32.0  
Other long-term liabilities 102.4     123.3  
Commitments and Contingencies      
EQUITY      
Common stock – par value $0.01 per share; 500.0 million shares authorized; 243.0 million and 240.7 million shares issued, respectively 2.4     2.4  
Treasury stock – 2.0 million and 1.1 million shares, respectively (34.2 )   (22.9 )
Additional paid-in capital 1,398.2     1,366.6  
Retained earnings 2,442.6     2,173.3  
Accumulated other comprehensive income (loss) (11.1 )   (16.7 )
Total Common Shareholders' Equity 3,797.9     3,502.7  
TOTAL LIABILITIES AND EQUITY $ 7,394.8     $ 7,245.4  
               


   
QEP RESOURCES, INC.  
CONSOLIDATED CASH FLOWS  
   
  Year Ended December 31,
  2017   2016
OPERATING ACTIVITIES (in millions)
Net income (loss) $ 269.3     $ (1,245.0 )
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:    
Depreciation, depletion and amortization 754.5     871.1  
Deferred income taxes (314.8 )   (651.3 )
Impairment 78.9     1,194.3  
Dry hole exploratory well expense 21.3      
Share-based compensation 22.4     35.6  
Amortization of debt issuance costs and discounts 6.2     6.4  
Bargain purchase gain from acquisitions 0.4     (22.6 )
Net (gain) loss from asset sales (213.5 )   (5.0 )
Loss from early extinguishment of debt 32.7      
Unrealized (gains) losses on marketable securities (2.9 )   (1.4 )
Unrealized (gains) losses on derivative contracts (40.0 )   367.0  
Other non-cash activity (9.4 )    
Changes in operating assets and liabilities (6.7 )   114.6  
Net Cash Provided by (Used in) Operating Activities 598.4     663.7  
INVESTING ACTIVITIES      
Property acquisitions (815.2 )   (639.0 )
Property, plant and equipment, including exploratory well expense (1,159.6 )   (569.1 )
Proceeds from disposition of assets 806.8     29.0  
Net Cash Provided by (Used in) Investing Activities (1,168.0 )   (1,179.1 )
FINANCING ACTIVITIES      
Checks outstanding in excess of cash balances 31.7     (17.5 )
Long-term debt issued 500.0      
Long-term debt issuance costs paid (14.4 )    
Long-term debt extinguishment costs paid (28.1 )    
Long-term debt repaid (445.6 )   (176.8 )
Proceeds from credit facility 492.0      
Repayments of credit facility (403.0 )    
Treasury stock repurchases (6.8 )   (4.1 )
Proceeds from issuance of common stock, net     781.4  
Excess tax (provision) benefit on share-based compensation     0.1  
Net Cash Provided by (Used in) Financing Activities 125.8     583.1  
Change in cash and cash equivalents (443.8 )   67.7  
Beginning cash and cash equivalents 443.8     376.1  
Ending cash and cash equivalents $     $ 443.8  
               


   
  Production by Region
  Three Months Ended December 31,   Year Ended December 31,
  2017   2016   Change   2017   2016   Change
  (in Mboe)
Northern Region                      
Williston Basin 4,479.8     4,948.1     (9 )%   18,140.0     20,370.0     (11 )%
Pinedale 29.3     3,820.9     (99 )%   9,871.7     15,826.0     (38 )%
Uinta Basin 834.8     973.1     (14 )%   3,605.4     4,714.3     (24 )%
Other Northern 136.8     349.3     (61 )%   1,082.4     1,491.7     (27 )%
Total Northern Region 5,480.7     10,091.4     (46 )%   32,699.5     42,402.0     (23 )%
Southern Region                      
Permian Basin 2,554.3     1,371.5     86 %   8,227.2     5,976.7     38 %
Haynesville/Cotton Valley 4,028.5     2,203.0     83 %   12,188.7     7,285.5     67 %
Other Southern 6.4     9.8     (35 )%   29.5     116.0     (75 )%
Total Southern Region 6,589.2     3,584.3     84 %   20,445.4     13,378.2     53 %
Total production 12,069.9     13,675.7     (12 )%   53,144.9     55,780.2     (5 )%


   
  Total Production
  Three Months Ended December 31,   Year Ended December 31,
  2017   2016   Change   2017   2016   Change
Oil (Mbbl) 5,240.6     4,882.8     7 %   19,620.7     20,293.8     (3 )%
Gas (Bcf) 34.1     43.9     (22 )%   168.9     177.0     (5 )%
NGL (Mbbl) 1,140.9     1,476.0     (23 )%   5,367.3     5,978.8     (10 )%
Total equivalent production (Mboe) 12,069.9     13,675.7     (12 )%   53,144.9     55,780.2     (5 )%
Average daily production (Mboe) 131.2     148.6     (12 )%   145.6     152.4     (4 )%


   
  Prices
  Three Months Ended December 31,   Year Ended December 31,
  2017   2016   Change   2017   2016   Change
Oil (per bbl)                      
Average field-level price $ 54.14     $ 44.24         $ 47.88     $ 37.90      
Commodity derivative impact (2.84 )   1.34         0.34     4.25      
Net realized price $ 51.30     $ 45.58     13 %   $ 48.22     $ 42.15     14 %
Gas (per Mcf)                      
Average field-level price $ 2.77     $ 2.95         $ 2.92     $ 2.36      
Commodity derivative impact (0.07 )   (0.14 )       (0.13 )   0.25      
Net realized price $ 2.70     $ 2.81     (4 )%   $ 2.79     $ 2.61     7 %
NGL (per bbl)                      
Average field-level price $ 24.41     $ 18.49         $ 20.85     $ 13.97      
Commodity derivative impact                      
Net realized price $ 24.41     $ 18.49     32 %   $ 20.85     $ 13.97     49 %
Average net equivalent price (per Boe)                      
Average field-level price $ 33.65     $ 27.27         $ 29.08     $ 22.76      
Commodity derivative impact (1.44 )   0.04         (0.29 )   2.35      
Net realized price $ 32.21     $ 27.31     18 %   $ 28.79     $ 25.11     15 %


   
  Operating Expenses
  Three Months Ended December 31,   Year Ended December 31,
  2017   2016   Change   2017   2016   Change
  (per Boe)
Lease operating expense $ 6.58     $ 4.49     47 %   $ 5.55     $ 4.03     38 %
Transportation and processing costs 3.54     5.14     (31 )%   4.61     5.18     (11 )%
Production and property taxes 2.34     2.16     8 %   2.15     1.70     26 %
Total production costs $ 12.46     $ 11.79     6 %   $ 12.31     $ 10.91     13 %
                                           

QEP RESOURCES, INC.
NON-GAAP MEASURES

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, loss from early extinguishment of debt 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 December 31,   Year Ended December 31,
  2017   2016   2017   2016
  (in millions)
Net income (loss) $ 150.3     $ (133.3 )   $ 269.3     $ (1,245.0 )
Interest expense 34.7     34.0     137.8     143.2  
Interest and other (income) expense(1) 0.9     (18.1 )   (1.6 )   (23.7 )
Income tax provision (benefit) (381.9 )   (67.0 )   (312.2 )   (708.2 )
Depreciation, depletion and amortization 194.3     203.6     754.5     871.1  
Unrealized (gains) losses on derivative contracts 121.6     148.4     (40.0 )   367.0  
Exploration expenses 0.3     0.8     22.0     1.7  
Net (gain) loss from asset sales (8.3 )       (213.5 )   (5.0 )
Impairment 50.5     6.1     78.9     1,194.3  
Loss from early extinguishment of debt 32.7         32.7      
Other(2)         8.2     32.7  
Adjusted EBITDA $ 195.1     $ 174.5     $ 736.1     $ 628.1  

 ____________________________
(1)       In the first quarter of 2017, QEP early adopted ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company recast "Interest and other (income) expense" for all prior periods shown. The Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the Pension Plan, SERP and Medical Plan benefits are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations
(2)    Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 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 changes in fair value of derivative contracts, gains and losses from asset sales, impairment, loss on early extinguishment of debt 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 December 31,   Year Ended December 31,
  2017   2016   2017   2016
  (in millions, except earnings per share amounts)
Net income (loss)(3) $ 150.3     $ (133.3 )   $ 269.3     $ (1,245.0 )
Adjustments to net income              
Unrealized losses (gains) on derivative contracts 121.6     148.4     (40.0 )   367.0  
Income taxes on unrealized loss (gain) on derivative contracts (1) (45.1 )   (55.1 )   14.8     (133.2 )
Net gain (loss) from asset sales (8.3 )       (213.5 )   (5.0 )
Income taxes on net gain on asset sales (1) 3.1         79.2     1.8  
Impairment 50.5     6.1     78.9     1,194.3  
Income taxes on impairment (1) (18.7 )   (2.3 )   (29.3 )   (433.5 )
Loss from early extinguishment of debt 32.7         32.7      
Income taxes on loss from early extinguishment of debt (1) (12.1 )       (12.1 )    
Other (2)         8.2     32.7  
Income taxes on other (1)         (3.0 )   (11.9 )
Total after-tax adjustments to net income 123.7     97.1     (84.1 )   1,012.2  
Adjusted Net Income (Loss) $ 274.0     $ (36.2 )   $ 185.2     $ (232.8 )
               
Earnings (Loss) per Common Share              
Diluted earnings per share $ 0.62     $ (0.56 )   $ 1.12     $ (5.62 )
Diluted after-tax adjustments to net income (loss) per share 0.51     0.41     (0.35 )   4.57  
Diluted Adjusted Net Income per share $ 1.13     $ (0.15 )   $ 0.77     $ (1.05 )
               
Weighted-average common shares outstanding              
Diluted 241.0     239.6     240.6     221.7  

________________________
(1)             Income tax impact of adjustments is calculated using QEP’s statutory rate of 37.1% for the three months ended December 31, 2017 and 2016 and 37.1% and 36.3% for the twelve months ended December 31, 2017 and 2016.
(2)             Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 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.
(3)             Net income during the year ended December 31, 2017, was also positively impacted by a $307.9 million tax benefit, primarily due to a revaluation of our net deferred tax liability to reflect the federal rate change resulting from 35% to 21% under the new tax legislation.

Reserves Replacement Ratio and Finding and Development Cost (F&D Cost)

This release refers to Reserve Replacement Ratio and F&D Cost, which are non-GAAP measures. QEP believes these metrics are widely used in its industry, as well as, by analysts and investors. Management believes Reserve Replacement Ratio provides investors with useful insight concerning QEP's ability to maintain and grow proved reserves in spite of depletion and F&D Cost is useful to investors to measure and evaluate the cost of replacing annual production.

Management defines Reserve Replacement Ratio as net proved reserve additions, including purchase of reserves in place, divided by annual production. Management defines F&D Cost as total costs incurred (an unaudited GAAP measure) divided by the sum of revisions of previous reserve estimates, extensions and discoveries and purchases of reserves in place. QEP's definition of these non-GAAP measures may differ from similarly titled measures provided by other companies and, as a result, may not be comparable. There are no directly comparable financial measures presented in accordance with GAAP for Reserve Replacement Ratio and F&D Cost; therefore, reconciliations to GAAP are not practicable.

Reserve Replacement Ratio and F&D Cost for 2017 are calculated as follows:

 

     
    Year Ended
    December 31, 2017
Revisions of previous estimates (MMboe)   2.7  
Extensions and discoveries (MMboe)   86.4  
Purchase of reserves in place (MMboe)   76.3  
Net proved reserve additions (MMboe)   165.4  
     
Proved property acquisitions (in millions)   269.6  
Unproved property acquisitions (in millions)   532.4  
Other acquisitions (in millions)   13.2  
Exploration costs (capitalized and expensed) (in millions)   32.7  
Development costs(1) (in millions)   1,189.3  
Total costs incurred (in millions)   $ 2,037.2  
     
Production (MMboe)   53.1  
     
Reserve Replacement Ratio   311 %
F&D Cost ($/Boe)   $ 12.32  

________________________
(1)       Development costs are net of the change in accrued capital costs of $60.6 million and additions and revisions to asset retirement obligations of $32.0 million during the year ended December 31, 2017.

QEP RESOURCES, INC.
DERIVATIVE POSITIONS

The following tables present QEP's volumes and average prices for its open derivative positions as of February 23, 2018:

 

 
Production Commodity Derivative Swaps
             
Year   Index   Total Volumes   Average Swap Price per Unit
        (in millions)    
Oil sales       (bbls)   ($/bbl)
2018   NYMEX WTI   15.4   $ 52.48
2019   NYMEX WTI   9.1   $ 52.45
Gas sales       (MMBtu)     ($/MMBtu)
2018 (Full Year)   NYMEX HH   91.8   $ 2.99
2018 (July through December)   NYMEX HH   1.8   $ 3.01
2019   NYMEX HH   43.8   $ 2.86


 
Production Commodity Derivative Basis Swaps
                 
Year   Index Less Differential   Index   Total Volumes   Weighted-Average Differential
            (in millions)    
Oil sales           (bbls)     ($/bbl)
2018 (Full Year)   NYMEX WTI   Argus WTI Midland   6.7   $ (1.06)
2018 (July through December)   NYMEX WTI   Argus WTI Midland   0.9   $ (0.71)
2019   NYMEX WTI   Argus WTI Midland   4.7   $ (0.77)
Gas sales           (MMBtu)     ($/MMBtu)
2018   NYMEX HH   IFNPCR   6.1   $ (0.16)
                   

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QEP Resources, Inc.