QEP Resources, Inc.

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QEP Resources Reports Fourth Quarter and Full Year 2016 Financial and Operating Results and Announces 2017 Capital Investment Plan and Guidance

Full Year 2016 Highlights

  • Delivered record oil equivalent production of 55.8 MMboe
  • Delivered record crude oil production of 20.3 MMbbl, including a record 4.0 MMbbl in the Permian Basin
  • Reported record year-end total proved reserves of 731.4 MMboe, a 21% increase compared with year-end 2015, including record proved crude oil reserves of 238.6 MMbbl
  • Acquired approximately 9,600 net acres in the core of the Permian Basin (2016 Permian Basin Acquisition)
  • Maintained strong liquidity, including $443.8 million of cash and cash equivalents at year-end

2017 Capital Investment Plan and Guidance

  • Total forecasted capital investment plan of $950.0 million to $1.0 billion, including approximately $50.0 to $60.0 million for infrastructure, primarily in the Permian Basin
  • Operating plan assumes a seven rig program, with five rigs in the Permian Basin and one each in the Williston Basin and Pinedale
    -  Forecasted crude oil production of 21.0 to 22.0 MMbbl, a 6% increase at the midpoint compared with 2016
    -  Forecasted crude oil production of 6.5 to 7.0 MMbbl in the Permian Basin, a nearly 70% increase at the midpoint compared with 2016

DENVER, Feb. 22, 2017 (GLOBE NEWSWIRE) -- QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported fourth quarter and full year 2016 financial and operating results. The Company reported a net loss of $133.3 million for the fourth quarter 2016, or $0.56 per diluted share, compared with net loss of $38.6 million, or $0.22 per diluted share, in the fourth quarter 2015. For the year ended December 31, 2016, QEP reported a net loss of $1,245.0 million, or $5.62 per diluted share, compared with a net loss of $149.4 million, or $0.85 per diluted share, for the comparable 2015 period.

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 2016 Adjusted Net Loss (a non-GAAP measure) was $36.2 million, or $0.15 per diluted share, compared with an Adjusted Net Loss of $1.8 million, or $0.01 per diluted share, in the fourth quarter 2015. For the year ended December 31, 2016, the Company’s Adjusted Net Loss was $232.8 million, or $1.05 per diluted share, compared with Adjusted Net Income of $1.9 million, or $0.01 per diluted share, for 2015.

Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2016 was $174.1 million, compared with $254.0 million in the fourth quarter 2015. For the year ended December 31, 2016, the Company reported Adjusted EBITDA of $626.2 million compared with $1,029.3 million for the comparable 2015 period, primarily due to a decrease in net average realized prices, partially offset by a 2% increase in oil equivalent production, a 19% decrease in production and property taxes and a 6% decrease in lease operating expense. The definition and reconciliations of Adjusted EBITDA and Adjusted Net Income to net income (loss) are provided within the financial tables of this release.

"QEP is well positioned to capitalize on the improving commodity price environment and to generate superior shareholder returns through the development of our core Permian Basin assets," commented Chuck Stanley, Chairman, President and CEO of QEP. "We have laid out an ambitious 2017 capital investment plan, which will allow us to deliver significant crude oil volume growth in the Permian Basin as we continue to develop our County Line acreage and embark on our concentrated development program at Mustang Springs. As our assets continue to move through their respective life cycles, we plan to allocate a larger percentage of our development capital to assets with significant growth potential."

"The steps we have taken to preserve our balance sheet through the downturn, while at the same time expanding our core acreage position in the Permian Basin, have enabled us to increase crude oil drilling throughout the first half of 2017. As a result, we are positioned to accelerate crude oil production growth in the second half of 2017 and into 2018. We plan to fund our 2017 drilling program with operating cash flows and cash on hand, without incurring any incremental indebtedness. As we remain focused on strategically managing our business, we will continue to optimize our portfolio of premier crude oil and natural gas assets through organic growth, acquisitions and divestitures," concluded Stanley.

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

Fourth Quarter and Full Year Results Summary

  • Oil equivalent production was 13,675.7 Mboe for the fourth quarter 2016 compared with 13,986.5 Mboe for the fourth quarter 2015. Production from the Williston and Permian basins and Haynesville/Cotton Valley increased while Pinedale and the Uinta Basin declined.
  • Crude oil and natural gas production decreased 4% and 5%, respectively, while NGL production increased 16%, in the fourth quarter 2016 compared with the fourth quarter 2015. Fourth quarter 2016 crude oil and natural gas production was negatively impacted by fewer completions in Pinedale and the Permian Basin and offset completion activity and severe weather which constrained production operations in the Williston Basin. NGL production was higher, primarily due to a third-party midstream provider's decision to continue to operate in ethane recovery in the Williston Basin, and in the Permian Basin due to an overall increase in production.
  • Field-level revenues increased 18% in the fourth quarter 2016 compared with the fourth quarter 2015, due to higher crude oil, natural gas and NGL field-level prices partially offset by lower crude oil and natural gas production. Crude oil and NGL production accounted for 65% of field-level revenues in the fourth quarter 2016.
  • Capital investment, excluding property acquisitions, for the fourth quarter 2016 (on an accrual basis), was $145.5 million compared with $218.2 million for the fourth quarter 2015. Capital investment, excluding property acquisitions, for the year ended December 31, 2016 (on an accrual basis), was $530.1 million, down $481.8 million compared with the year ended December 31, 2015.
  • During the year ended December 31, 2016, the Company invested $645.2 million to acquire various oil and gas properties, including the 2016 Permian Basin Acquisition, additional interests in QEP operated wells and other proved undeveloped leasehold acreage in the Permian and Williston basins.
  • Cash and cash equivalents were $443.8 million at the end of the fourth quarter 2016 and the Company had no borrowings under its unsecured revolving credit facility.
  • General and administrative expense for the fourth quarter 2016 was $39.0 million, a decrease of 3% compared with the fourth quarter 2015. For the year ended December 31, 2016, general and administrative expense was $198.4 million, an increase of 10% compared with the prior year driven primarily by an increase in legal expenses and loss contingencies, partially offset by lower labor, benefit and employee expenses, as well as lower professional and outside services.
  • In November 2016, the Company reached an agreement with one of its third-party midstream providers that resolved a dispute and agreed to amend an existing agreement under which associated gas produced from the Company's South Antelope acreage in the Williston Basin is purchased, gathered and processed.

2017 Guidance

Production Outlook

2017 oil equivalent production is expected to be between 57.0 and 60.0 MMboe, an increase of approximately 5%, at the midpoint, compared with 2016. The Company expects to deliver year-over-year crude oil production growth of approximately 6%, at the midpoint, in 2017, with Permian Basin crude oil volumes expected to grow to between 6.5 to 7.0 MMbbl an increase of nearly 70%, at the midpoint, compared with 2016. Gas production is expected to be 185.0 Bcf, at the midpoint, an increase of approximately 5% compared with 2016.

Capital Investment Plan

The Board of Directors approved a capital investment plan for 2017 of $950.0 million to $1.0 billion, with the majority of the funds directed towards drilling and completion activity. Nearly 60% of the planned capital investment is focused on high rate of return projects in the Permian Basin. Included in the budget is approximately $50.0 to $60.0 million of investment for infrastructure, primarily in the Permian Basin.

Operating Plan

The Company plans to operate an average of seven rigs in 2017, with five rigs in the Permian Basin, one rig in the Williston Basin and one rig in Pinedale. With the exception of Pinedale, all rigs will be drilling horizontal wells. The Company expects to complete approximately 115 to 130 gross operated wells (98 to 110 net) during the year, with approximately 75 to 80 gross (75 to 80 net) in the Permian Basin, 20 to 25 gross (15 to 20 net) in the Williston Basin and 20 to 25 gross (8 to 10 net) in Pinedale. Further, the Company expects to workover approximately 20 to 24 wells in Haynesville/Cotton Valley

QEP's initial full year 2017 guidance and related assumptions are shown below. The Company’s guidance assumes no property acquisitions or divestitures, and that QEP will elect to reject ethane from its produced gas for the entire year where QEP has the right to make such an election.

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 $890 - $930
Infrastructure $50 - $60
Corporate $ 10  
Total capital investment $950 - $1,000

____________________________
(1)  Forecasted general and administrative expense includes approximately $31.5 million of expenses primarily related to share-based compensation.

2018 Production Outlook

At 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 Company expects crude oil production will continue to increase at an accelerated rate through the second half of 2017, which will lead to an increase in 2018 forecasted crude oil production of approximately 15% to 20% compared with the midpoint of the 2017 forecast. The increase in 2018 forecasted crude oil production will be primarily driven by the Permian Basin, where crude oil production is expected to increase by approximately 60% to 80% in 2018 compared with the midpoint of 2017 Permian Basin crude oil production.

"The impact of our concentrated development program in the Permian Basin will be most pronounced as we exit 2017 and enter 2018. We expect to bring on-line a total of approximately 30 to 40 Permian wells in the third and fourth quarters of 2017 and approximately 100 Permian wells in 2018. Our ability to grow crude oil production through the work we accomplish in 2017 will drive significant cash flow and allow us to substantially increase crude oil volumes through 2020 and beyond," commented Stanley.

Estimated Proved Reserves

QEP's estimated proved reserves totaled 731.4 MMboe at December 31, 2016, up 21% compared with 2015, primarily due to the addition of increased density wells in areas that have been previously developed on lower density spacing, the success of the Company's workover program in Haynesville/Cotton Valley and the purchase of reserves in place primarily related to the Company's 2016 Permian Basin Acquisition. Extensions and discoveries were 42.6 MMboe, driven primarily by the Company's development activities in the Permian and Uinta basins. Approximately 42% of total proved reserves at year-end 2016 and 2015 were crude oil and NGL. Proved developed reserves were 357.2 MMboe, or 49%, of total estimated proved reserves at year-end 2016.

Lower 12-month average crude oil and natural gas prices used for estimating proved reserves resulted in negative revisions of 18.5 MMboe. Our Reserve Replacement Ratio (a non-GAAP measure) was approximately 331% of 2016 production at an all-in finding and development cost (F&D Cost) (a non-GAAP measure) of $6.30 per Boe and resulted in a year-end 2016 reserve life of 13.1 years. The definitions of Reserve Replacement Ratio and F&D Cost and calculations of such metrics for 2016 are provided within the financial tables of this release.

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, 2015   193.1     2,108.9     58.8     603.4  
Revisions of previous estimates   (9.7 )   412.8     (0.3 )   58.8  
Extensions and discoveries   13.0     158.1     3.3     42.6  
Purchase of reserves in place   62.7     54.6     11.5     83.3  
Sale of reserves in place   (0.2 )   (3.6 )   (0.1 )   (0.9 )
Production   (20.3 )   (177.0 )   (6.0 )   (55.8 )
Balance at December 31, 2016   238.6     2,553.8     67.2     731.4  

____________________________
(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 2016 and 2015 proved reserves presented by operating area, proved reserve category and percentage of total estimated proved reserves comprised of crude oil and NGL (liquids) are as follows:

    Total (in MMboe)   % of total   PUD %   liquids %
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 %
                 
For the year ended December 31, 2015                  
Northern Region                
Williston Basin   181.0     30 %   39 %   86 %
Pinedale   187.5     31 %   27 %   13 %
Uinta Basin   93.1     16 %   55 %   18 %
Other Northern   12.4     2 %   %   8 %
Southern Region                
Permian Basin   62.4     10 %   66 %   87 %
Haynesville/Cotton Valley   66.1     11 %   57 %   %
Other Southern   0.9     %   %   32 %
Total proved reserves   603.4     100 %   42 %   42 %

Operations Summary

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

  Operated Completions   Non-operated Completions
  Three Months Ended
December 31, 2016
  Year Ended
December 31, 2016
  Three Months Ended
December 31, 2016
  Year Ended
December 31, 2016
  Gross   Net   Gross   Net   Gross   Net   Gross   Net
Northern Region                              
Williston Basin 14     11.9     41     37.5     6     1.0     29     2.0  
Pinedale 6     2.6     44     24.4                  
Uinta Basin         8     8.0     1     0.0     3     0.0  
Other Northern 3     3.0     3     3.0                  
                               
Southern Region                              
Permian Basin 2     1.8     20     19.5                  
Haynesville/Cotton Valley                 6     0.8     15     2.6  
Other Southern                              

Permian Basin

Permian Basin net production averaged approximately 14.9 Mboed (89% liquids) during the fourth quarter 2016, a 9% decrease compared with the third quarter 2016, and an 8% increase compared with the fourth quarter 2015. Permian Basin production was negatively impacted during the quarter by fewer than expected completions due to higher than anticipated drilling activity on its County Line acreage as the Company increased rig count in anticipation of closing the Mustang Springs transaction, which delayed offset completion activity.

QEP completed and turned to sales two gross-operated horizontal wells in the fourth quarter 2016 (average working interest 90%), both in the Spraberry Shale. These wells were drilled in a spacing unit that had been previously developed at a density of six wells per mile and were designed to evaluate the potential density of up to 12 wells per mile. The Company believes these wells will provide valuable data on mechanical interference and will assist in determining the ultimate development design on its County Line and Mustang Springs acreage (Slides 24-27).

The Company continues to evaluate increased density well spacing in different target horizons in the Permian Basin. During the fourth quarter 2016 the Company continued to evaluate an equivalent density of 16 wells per one-mile spacing unit on its County Line acreage targeting the Spraberry Shale. QEP also initiated a test to evaluate an equivalent density of nine wells per one-mile spacing unit on its County Line acreage targeting the Middle Spraberry. In addition, to further evaluate the potential of the Leonard Shale across its County Line acreage, an additional parent well was drilled in this interval during the quarter.

At the end of the fourth quarter 2016, the Company had 13 gross-operated horizontal wells waiting on completion (working interest 100%) and three gross-operated horizontal wells being drilled (working interest 100%) in the Permian Basin.

Current average gross QEP-operated drilled and completed authorization for expenditure (AFE) well costs are $5.0 million for 7,500 foot Spraberry wells, with costs associated with facilities and artificial lift adding approximately $0.7 million per well. At the end of the fourth quarter 2016, the Company had three operated rigs in the Permian Basin, one on its County Line acreage and two at Mustang Springs, all drilling horizontal wells. The Company expects to add two additional operated rigs in the first quarter 2017 to its Permian Basin program and plans to operate five rigs for the duration of 2017.

Slides 5-11 depict QEP's acreage and activity in the Permian Basin.

Williston Basin

Williston Basin net production averaged approximately 53.8 Mboed (88% liquids) during the fourth quarter 2016, a 6% decrease compared with the third quarter 2016 and a 4% increase over the fourth quarter 2015. Production was negatively impacted during the fourth quarter 2016 by offset completion activity, which resulted in shut-ins and curtailments of existing wells, and by severe winter weather, which constrained production operations across the field during much of December.

The Company completed and turned to sales 14 gross operated wells during the fourth quarter 2016 (average working interest 85%), all on South Antelope. These wells are performing as expected, with peak 24-hour production rates averaging 2,589 Boed (68% oil). The Company also participated in six gross outside-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 17%).

As high-density infill development continues on South Antelope, the Company expects future well performance to be similar to historical well performance. However, reduced reservoir energy, a result of existing production on the acreage, may cause lower than historic flowing initial production rates on high-density infill wells. To mitigate the impact, the Company has accelerated installation of artificial lift on new high-density wells, resulting in infill well performance similar to direct offset wells.

In November 2016, the Company resolved a dispute with one of its third-party midstream providers under which the associated gas produced from some of the Company's South Antelope acreage is purchased, gathered and processed by amending its existing agreement to extend the term, revise the fee structure and increase capacity.

At the end of the fourth quarter 2016, QEP had 15 gross operated wells waiting on completion (nine on South Antelope and six at Ft. Berthold, average working interest 85%) in the Williston Basin and three wells being drilled at Ft. Berthold (average working interest 100%). In addition, the Company had interest in 14 gross non-operated wells waiting on completion (average working interest 3%) at the end of the fourth quarter.

Current average gross QEP-operated drilled and completed AFE well costs, assuming "plug-and-perf" completion design, are $5.6 million on South Antelope and $6.2 million at Ft. Berthold, with costs associated with facilities and artificial lift adding approximately $0.8 million per well on South Antelope and $1.3 million per well at Ft. Berthold. At the end of the fourth quarter 2016, the Company had one operated rig working in the Williston Basin at Ft. Berthold. The Company expects to operate one rig in the Williston Basin for the duration of 2017.

Slides 12-16 depict QEP's acreage and activity in the Williston Basin.

Haynesville/Cotton Valley

Haynesville/Cotton Valley net production averaged approximately 23.9 Mboed (0% liquids) during fourth quarter 2016, an 8% increase compared with the third quarter 2016 and a 29% increase compared with the fourth quarter 2015. The increase is primarily due to recent well workovers, changes in working interest as a result of the resolution of certain title issues, non-operated well completions and other production related adjustments. During the quarter, the Company completed four QEP operated workovers (average working interest 100%). The Company also participated in six gross outside-operated wells that were completed and turned to sales during the quarter (average working interest 13%).

The Company had interests in nine gross non-operated wells waiting on completion (average working interest 10%) and three gross non-operated wells being drilled (average working interest 17%) at the end of the fourth quarter.

Current average gross QEP operated workover costs are approximately $4.0 million. The Company expects to workover approximately 20 to 24 wells during 2017. At the end of the fourth quarter 2016, the Company had no rigs operating in the Haynesville/Cotton Valley.

Slides 17-19 depict QEP's acreage and activity in Haynesville/Cotton Valley.

Pinedale

Pinedale net production averaged approximately 41.5 Mboed (14% liquids) during the fourth quarter 2016, a 5% decrease compared with the third quarter 2016 and an 18% decrease compared with the fourth quarter 2015. There were six operated wells completed and turned to sales during the fourth quarter 2016 (average working interest 43%).

At the end of the fourth quarter 2016, the Company had eight gross-operated Pinedale wells waiting on completion (average working interest 56%) and six wells being drilled (average working interest 40%).

Current average gross QEP-operated drilled and completed AFE well costs are $2.7 million in Pinedale, with costs associated with facilities and artificial lift adding approximately $0.2 million per well. At the end of the fourth quarter 2016, the Company had one operated rig running in Pinedale. The Company expects to operate one rig in Pinedale for the duration of 2017.

Slides 20-22 depict QEP's acreage and activity at Pinedale.

Uinta Basin

Uinta Basin net production averaged approximately 10.6 Mboed (23% liquids), during the fourth quarter 2016, of which 5.6 Mboed (9% liquids) was from the Lower Mesaverde play. This represents a 19% decrease in production compared with the third quarter 2016 and an 11% decrease compared with the fourth quarter 2015.

The Company did not complete any operated wells during the quarter, but did participate in one gross outside-operated well that was completed and turned to sales during the quarter (working interest less than 1%).

At the end of the fourth quarter 2016, the Company had no rigs operating in the Uinta Basin.

Slides 34-35 depict QEP's acreage and activity in the Uinta Basin.

Fourth Quarter and Full Year 2016 Results Conference Call

QEP Resources' management will discuss fourth quarter and full year 2016 results in a conference call on Thursday, February 23, 2017, 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 at www.qepres.com immediately after the call through March 23, 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 #13653560. In addition, QEP’s slides for the fourth quarter 2016, with updated maps showing QEP’s leasehold and current activity for key operating areas discussed in this release, can be found on the Company’s website at www.qepres.com.

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 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: amount and allocation of planned capital expenditures; the number and location of drilling rigs to be deployed and the timing of deployment; well performance, initial production rates and actions to improve well performance for wells in the Williston Basin; forecasted production amounts and growth and related assumptions; forecasted lease operating and transportation expense, depletion, depreciation and amortization expense, general and administrative expense, production and property taxes and capital investment for 2017 and related assumptions for such guidance; plans to reject ethane in 2017; estimated reserves; forecasted number of new wells and the locations of such wells; number of workover wells; increase in cash flows; valuable data from testing increased density well spacing; funding for our drilling program; optimizing our portfolio of assets; and legal expenses, loss contingencies and pension curtailment expense. 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 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; 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; 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. 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, 2016.


QEP RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
 
  Three Months Ended   Year Ended
  December 31,   December 31,
  2016   2015   2016   2015
REVENUES (in millions, except per share amounts)
Oil sales $ 216.0     $ 193.3     $ 769.1     $ 834.2  
Gas sales 129.6     105.2     417.1     468.5  
NGL sales 27.3     18.3     83.5     80.0  
Other revenues 1.9     2.7     6.2     15.1  
Purchased oil and gas sales 24.9     148.8     101.2     620.8  
Total Revenues 399.7     468.3     1,377.1     2,018.6  
OPERATING EXPENSES              
Purchased oil and gas expense 24.7     151.7     105.5     626.8  
Lease operating expense 61.4     63.2     224.7     238.8  
Oil, gas and NGL transportation and other handling costs 70.3     75.1     289.2     291.3  
Gathering and other expense 1.2     1.4     5.0     5.8  
General and administrative 39.0     40.4     198.4     181.1  
Production and property taxes 29.5     26.9     94.8     117.6  
Depreciation, depletion and amortization 203.6     231.8     871.1     881.1  
Exploration expenses 0.8         1.7     2.7  
Impairment 6.1     20.1     1,194.3     55.6  
Total Operating Expenses 436.6     610.6     2,984.7     2,400.8  
Net gain (loss) from asset sales     (2.3 )   5.0     4.6  
OPERATING INCOME (LOSS) (36.9 )   (144.6 )   (1,602.6 )   (377.6 )
Realized and unrealized gains (losses) on derivative contracts (147.9 )   108.7     (233.0 )   277.2  
Interest and other income 18.5     1.5     25.6     3.0  
Interest expense (34.0 )   (36.2 )   (143.2 )   (145.6 )
INCOME (LOSS) BEFORE INCOME TAXES (200.3 )   (70.6 )   (1,953.2 )   (243.0 )
Income tax (provision) benefit 67.0     32.0     708.2     93.6  
NET INCOME (LOSS) $ (133.3 )   $ (38.6 )   $ (1,245.0 )   $ (149.4 )
               
Earnings (loss) per common share              
Basic $ (0.56 )   $ (0.22 )   $ (5.62 )   $ (0.85 )
Diluted $ (0.56 )   $ (0.22 )   $ (5.62 )   $ (0.85 )
               
Weighted-average common shares outstanding              
Used in basic calculation 239.6     176.7     221.7     176.6  
Used in diluted calculation 239.6     176.7     221.7     176.6  
Dividends per common share $     $ 0.02     $     $ 0.08  
                               


QEP RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
 
  December 31,
 2016
  December 31,
 2015
ASSETS (in millions)
Current Assets      
Cash and cash equivalents $ 443.8     $ 376.1  
Accounts receivable, net 155.7     278.2  
Income tax receivable 18.6     87.3  
Fair value of derivative contracts     146.8  
Oil, gas and NGL inventories, at lower of average cost or market 10.4     13.3  
Prepaid expenses and other 11.6     30.1  
Total Current Assets 640.1     931.8  
Property, Plant and Equipment (successful efforts method for oil and gas properties)    
Proved properties 14,232.5     13,314.9  
Unproved properties 871.5     691.0  
Marketing and other 301.8     297.9  
Materials and supplies 32.7     38.5  
Total Property, Plant and Equipment 15,438.5     14,342.3  
Less Accumulated Depreciation, Depletion and Amortization      
Exploration and production 8,797.7     6,870.2  
Marketing and other 101.8     87.5  
Total Accumulated Depreciation, Depletion and Amortization 8,899.5     6,957.7  
Net Property, Plant and Equipment 6,539.0     7,384.6  
Fair value of derivative contracts     23.2  
Other noncurrent assets 66.3     58.6  
TOTAL ASSETS $ 7,245.4     $ 8,398.2  
LIABILITIES AND EQUITY      
Current Liabilities      
Checks outstanding in excess of cash balances $ 12.3     $ 29.8  
Accounts payable and accrued expenses 269.7     351.7  
Production and property taxes 30.1     46.1  
Interest payable 32.9     36.4  
Fair value of derivative contracts 169.8     0.8  
Current portion of long-term debt     176.8  
Total Current Liabilities 514.8     641.6  
Long-term debt 2,020.9     2,014.7  
Deferred income taxes 825.9     1,479.8  
Asset retirement obligations 225.8     204.9  
Fair value of derivative contracts 32.0     4.0  
Other long-term liabilities 123.3     105.3  
Commitments and Contingencies      
EQUITY      
Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.7 million and 177.3 million shares issued, respectively 2.4     1.8  
Treasury stock – 1.1 million and 0.5 million shares, respectively (22.9 )   (14.6 )
Additional paid-in capital 1,366.6     554.8  
Retained earnings 2,173.3     3,418.3  
Accumulated other comprehensive income (loss) (16.7 )   (12.4 )
Total Common Shareholders' Equity 3,502.7     3,947.9  
TOTAL LIABILITIES AND EQUITY $ 7,245.4     $ 8,398.2  
               


QEP RESOURCES, INC.
CONSOLIDATED CASH FLOWS
 
  Year Ended December 31,
  2016   2015
  (in millions)
OPERATING ACTIVITIES      
Net income (loss) $ (1,245.0 )   $ (149.4 )
Adjustments to reconcile net income to net cash provided by operating activities:          
Depreciation, depletion and amortization 871.1     881.1  
Deferred income taxes (651.3 )   25.3  
Impairment 1,194.3     55.6  
Bargain purchase gain from acquisitions (22.6 )    
Share-based compensation 35.6     34.7  
Pension curtailment loss     11.2  
Amortization of debt issuance costs and discounts 6.4     6.2  
Net (gain) loss from asset sales (5.0 )   (4.6 )
Unrealized (gains) losses on marketable securities (1.4 )   0.2  
Unrealized (gains) losses on derivative contracts 367.0     183.7  
Changes in operating assets and liabilities 114.6     (562.7 )
Net Cash Provided by (Used in) Operating Activities 663.7     481.3  
INVESTING ACTIVITIES      
Property acquisitions (639.0 )   (98.3 )
Property, plant and equipment, including dry hole exploratory well expense (569.1 )   (1,141.1 )
Proceeds from disposition of assets 29.0     21.8  
Net Cash Provided by (Used in) Investing Activities (1,179.1 )   (1,217.6 )
FINANCING ACTIVITIES      
Checks outstanding in excess of cash balances (17.5 )   (24.9 )
Long-term debt issuance costs paid     (2.6 )
Long-term debt repaid (176.8 )    
Treasury stock repurchases (4.1 )   (2.7 )
Other capital contributions     (0.2 )
Dividends paid     (14.1 )
Proceeds from issuance of common stock, net 781.4      
Excess tax (provision) benefit on share-based compensation 0.1     (3.2 )
Net Cash Provided by (Used in) Financing Activities 583.1     (47.7 )
Change in cash and cash equivalents 67.7     (784.0 )
Beginning cash and cash equivalents 376.1     1,160.1  
Ending cash and cash equivalents $ 443.8     $ 376.1  
               


  Production by Region
  Three Months Ended December 31,   Year Ended December 31,
  2016   2015   Change   2016   2015   Change
  (in Mboe)
Northern Region                      
Williston Basin 4,948.1     4,744.8     4 %   20,370.0     18,709.6     9 %
Pinedale 3,820.9     4,667.1     (18 )%   15,826.0     16,829.6     (6 )%
Uinta Basin 973.1     1,092.0     (11 )%   4,714.3     4,924.0     (4 )%
Other Northern 349.3     466.4     (25 )%   1,491.7     1,764.1     (15 )%
Total Northern Region 10,091.4     10,970.3     (8 )%   42,402.0     42,227.3     %
Southern Region                      
Permian Basin 1,371.5     1,259.7     9 %   5,976.7     4,332.5     38 %
Haynesville/Cotton Valley 2,203.0     1,712.0     29 %   7,285.5     7,268.0     %
Other Southern 9.8     44.5     (78 )%   116.0     634.3     (82 )%
Total Southern Region 3,584.3     3,016.2     19 %   13,378.2     12,234.8     9 %
Total production 13,675.7     13,986.5     (2 )%   55,780.2     54,462.1     2 %


  Total Production
  Three Months Ended December 31,   Year Ended December 31,
  2016   2015   Change   2016   2015   Change
Oil (Mbbl) 4,882.8     5,062.9     (4 )%   20,293.8     19,582.3     4 %
Gas (Bcf) 43.9     46.0     (5 )%   177.0     181.1     (2 )%
NGL (Mbbl) 1,476.0     1,272.0     16 %   5,978.8     4,704.3     27 %
Total equivalent production (Mboe) 13,675.7     13,986.5     (2 )%   55,780.2     54,462.1     2 %
Average daily production (Mboe) 148.6     152.0     (2 )%   152.4     149.2     2 %


  Prices
  Three Months Ended December 31,   Year Ended December 31,
  2016   2015   Change   2016   2015   Change
Oil (per bbl)                      
Average field-level price $ 44.24     $ 38.16         $ 37.90     $ 42.59      
Commodity derivative impact 1.34     21.41         4.25     18.06      
Net realized price $ 45.58     $ 59.57     (23 )%   $ 42.15     $ 60.65     (31 )%
Gas (per Mcf)                      
Average field-level price $ 2.95     $ 2.29         $ 2.36     $ 2.59      
Commodity derivative impact (0.14 )   0.75         0.25     0.57      
Net realized price $ 2.81     $ 3.04     (8 )%   $ 2.61     $ 3.16     (17 )%
NGL (per bbl)                      
Average field-level price $ 18.49     $ 14.41         $ 13.97     $ 16.98      
Commodity derivative impact                      
Net realized price $ 18.49     $ 14.41     28 %   $ 13.97     $ 16.98     (18 )%
Average net equivalent price (per Boe)                      
Average field-level price $ 27.27     $ 22.65         $ 22.76     $ 25.38      
Commodity derivative impact 0.04     10.20         2.35     8.39      
Net realized price $ 27.31     $ 32.85     (17 )%   $ 25.11     $ 33.77     (26 )%


  Production Costs
  Three Months Ended December 31,   Year Ended December 31,
  2016   2015   Change   2016   2015   Change
  (per Boe)
Lease operating expense $ 4.49     $ 4.52     (1 )%   $ 4.03     $ 4.38     (8 )%
Oil, gas and NGL transportation and other handling costs 5.14     5.37     (4 )%   5.18     5.35     (3 )%
Production and property taxes 2.16     1.92     13 %   1.70     2.16     (21 )%
Total production costs $ 11.79     $ 11.81     %   $ 10.91     $ 11.89     (8 )%

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 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, noncash 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,
  2016   2015   2016   2015
  (in millions)
Net income (loss) $ (133.3 )   $ (38.6 )   $ (1,245.0 )   $ (149.4 )
Interest expense 34.0     36.2     143.2     145.6  
Interest and other (income) expense (18.5 )   (1.5 )   (25.6 )   (3.0 )
Income tax provision (benefit) (67.0 )   (32.0 )   (708.2 )   (93.6 )
Depreciation, depletion and amortization 203.6     231.8     871.1     881.1  
Unrealized (gains) losses on derivative contracts 148.4     35.7     367.0     183.7  
Exploration expenses 0.8         1.7     2.7  
Net (gain) loss from asset sales     2.3     (5.0 )   (4.6 )
Impairment 6.1     20.1     1,194.3     55.6  
Other (1)         32.7     11.2  
Adjusted EBITDA $ 174.1     $ 254.0     $ 626.2     $ 1,029.3  

 ____________________________
(1)  Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2016, and a non-cash pension curtailment loss incurred during the year ended December 31, 2015. 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 the 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, noncash 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,
  2016   2015   2016   2015
  (in millions, except earnings per share amounts)
Net income (loss) $ (133.3 )   $ (38.6 )   $ (1,245.0 )   $ (149.4 )
Adjustments to net income              
Unrealized losses (gains) on derivative contracts 148.4     35.7     367.0     183.7  
Income taxes on unrealized loss (gain) on derivative contracts (1) (55.1 )   (13.1 )   (133.2 )   (70.7 )
Net gain (loss) from asset sales     2.3     (5.0 )   (4.6 )
Income taxes on net gain on asset sales (1)     (0.8 )   1.8     1.8  
Impairment 6.1     20.1     1,194.3     55.6  
Income taxes on impairment (1) (2.3 )   (7.4 )   (433.5 )   (21.4 )
Other (2)         32.7     11.2  
Income taxes on other (1)         (11.9 )   (4.3 )
Total after-tax adjustments to net income 97.1     36.8     1,012.2     151.3  
Adjusted Net Income (Loss) $ (36.2 )   $ (1.8 )   $ (232.8 )   $ 1.9  
               
Earnings (Loss) per Common Share              
Diluted earnings per share $ (0.56 )   $ (0.22 )   $ (5.62 )   $ (0.85 )
Diluted after-tax adjustments to net income (loss) per share 0.41     0.21     4.57     0.86  
Diluted Adjusted Net Income per share $ (0.15 )   $ (0.01 )   $ (1.05 )   $ 0.01  
               
Weighted-average common shares outstanding              
Diluted 239.6     176.7     221.7     176.6  

________________________
(1)  Income tax impact of adjustments is calculated using QEP’s statutory rate of 37.1% and 36.6% for the three months ended December 31, 2016 and 2015, respectively, and QEP’s effective tax rate of 36.3% and 38.5% for the years ended December 31, 2016 and 2015, respectively.
(2)  Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2016, and a non-cash pension curtailment loss incurred during the year ended December 31, 2015. 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 the amounts from the calculation of Adjusted Net Income.

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 2016 are calculated as follows:

    Year Ended
    December 31, 2016
Revisions of previous estimates (MMboe)   58.8  
Extensions and discoveries (MMboe)   42.6  
Purchase of reserves in place (MMboe)   83.3  
Net proved reserve additions (MMboe)   184.7  
     
Proved property acquisitions (in millions)   $ 431.6  
Unproved property acquisitions (in millions)   208.7  
Exploration (capitalized and expensed) (in millions)   13.4  
Development(1) (in millions)   509.2  
Total costs incurred (in millions)   $ 1,162.9  
     
Production (MMboe)   55.8  
     
Reserve Replacement Ratio   331 %
F&D Cost ($/Boe)   $ 6.30  

________________________
(1)  Development costs are net of the change in accrued capital costs of $34.6 million and additions and revisions to asset retirement obligations of $23.5 million during the year ended December 31, 2016.

QEP RESOURCES, INC.
DERIVATIVE POSITIONS

The following tables present QEP's volumes and average prices for its open derivative positions as of February 17, 2017:

Production Commodity Derivative Swap Positions
 
Year   Index   Total Volumes   Average Swap Price
per Unit
        (in millions)    
Oil sales       (bbls)     ($/bbl)  
2017   NYMEX WTI   12.4     $ 51.39  
2018   NYMEX WTI   8.4     $ 53.71  
Gas sales       (MMBtu)     ($/MMBtu)  
2017   NYMEX HH   79.6     $ 2.86  
2017   IFNPCR   27.5     $ 2.51  
2018   NYMEX HH   76.7     $ 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   9.2     $ 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   3.5     $ (0.64 )
2018   NYMEX WTI   Argus WTI Midland   2.6     $ (0.96 )
Gas sales           (MMBtu)     ($/MMBtu)  
2017   NYMEX HH   IFNPCR   42.8     $ (0.18 )
2018   NYMEX HH   IFNPCR   7.3     $ (0.16 )


Gas Storage Commodity Derivative Positions
 
Year   Type of Contract   Index   Total Volumes   Average Swap Price
per Unit
            (in millions)    
Gas sales           (MMBtu)     ($/MMBtu)  
2017   SWAP   IFNPCR   2.7     $ 2.77  


Contact

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

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

Primary Logo

QEP Resources, Inc.