UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
The Securities Exchange Act of 1934
Date of Report - October 28, 2015
(Date of earliest event reported)
QEP RESOURCES, INC.
(Exact name of registrant as specified in its charter)
STATE OF DELAWARE | 001-34778 | 87-0287750 |
(State or other jurisdiction of incorporation) | (Commission File No.) | (I.R.S. Employer Identification No.) |
1050 17th Street, Suite 800, Denver, Colorado 80265
(Address of principal executive offices)
Registrant's telephone number, including area code 303-672-6900
Not Applicable
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act
(17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act
(17 CFR 240.13e-4(c))
Section 2 - Financial Information
Item 2.02 Results of Operations and Financial Condition
On October 28, 2015, QEP Resources, Inc. (the “Registrant”) issued a press release to report the results of operations for the period ended September 30, 2015, and to provide an update to 2015 guidance. A copy of the Registrant's release is attached hereto as Exhibit 99.1, and the information contained therein is incorporated herein by reference.
The Registrant's press release announcing its financial results for the period ended September 30, 2015, includes non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company's financial and operating performance that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with United States generally accepted accounting principles, or GAAP. Pursuant to the requirements of Regulation G, the Registrant has provided quantitative reconciliations within the press release of the non-GAAP financial measures to the most directly comparable GAAP financial measures.
The information contained in Item 2.02 to this Form 8-K, including the exhibit, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and the information shall not be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing.
Section 9 - Financial Statements and Exhibits
Item 9.01 Financial Statements and Exhibits.
(d) Exhibits.
Exhibit No. | Exhibit | |
99.1 | Press release issued October 28, 2015, by QEP Resources, Inc. | |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
QEP Resources, Inc. | ||
(Registrant) | ||
October 28, 2015 | ||
/s/ Richard J. Doleshek | ||
Richard J. Doleshek | ||
Executive Vice President and Chief Financial Officer | ||
List of Exhibits: | ||
Exhibit No. | Exhibit | |
99.1 | Press release issued October 28, 2015, by QEP Resources, Inc. | |
QEP RESOURCES REPORTS THIRD QUARTER 2015 FINANCIAL AND OPERATING RESULTS
▪ | Achieved record quarterly production |
▪ | Maintained strong liquidity |
▪ | Reported Adjusted EBITDA in excess of capital expenditures |
▪ | Continued successful results from Williston Basin high-density infill program |
▪ | Raised full-year production guidance and reduced expense guidance |
DENVER — October 28, 2015 — QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported third quarter 2015 financial and operating results. The Company reported net income from continuing operations of $21.1 million, or $0.12 per diluted share, for the third quarter 2015 compared with net income from continuing operations of $153.7 million, or $0.84 per diluted share, in the third quarter 2014.
Net income includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, and impairment charges. Excluding these items, the Company’s third quarter 2015 Adjusted Net Income (a non-GAAP measure) was $1.0 million, or $0.01 per diluted share, compared with Adjusted Net Income from continuing operations of $58.1 million, or $0.31 per diluted share, for the comparable 2014 period. The decrease in Adjusted Net Income was due primarily to significantly lower average field-level prices for crude oil, natural gas and NGL, partially offset by higher crude oil and natural gas volumes, lower production taxes and increased proceeds from settled commodity derivatives.
Adjusted EBITDA (a non-GAAP measure) for the third quarter 2015 was $273.1 million, compared with $370.9 million on a continuing operations basis in the third quarter 2014, a 26% decrease. The definitions and reconciliations of Adjusted EBITDA and Adjusted Net Income to net income are provided within the financial tables of this release.
“Our third quarter performance reflects our continuing operational and financial success in our core plays. For the second consecutive quarter our Adjusted EBITDA exceeded capital expenditures, while our oil production also grew meaningfully compared with the second quarter 2015,” commented Chuck Stanley, Chairman, President and CEO of QEP Resources. “We continue to see the positive impact of our relentless focus on increasing operational efficiencies, capturing lower service and supply costs, and aggressively managing the business factors within our control. We delivered strong oil production growth in the quarter, up 6% sequentially from the second quarter 2015, driven by better completed well performance in the Williston and Permian basins, and achieved record quarterly natural gas-equivalent production, propelled by record natural gas production from our Pinedale and Uinta Basin assets.
“We are committed as an organization to successfully navigate the current commodity price environment by making prudent capital allocation decisions to position QEP to take advantage of opportunities as commodity markets ultimately recover. We believe the quality of our E&P asset portfolio, our solid balance sheet, our unsecured credit facility and our substantial cash balance will enable QEP to deliver long-term growth and profitability,” concluded Stanley.
Slides for the third quarter 2015 with maps and other supporting materials referred to in this release are posted on the Company’s website at www.qepres.com.
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QEP Financial Results Summary
Adjusted EBITDA by Operating Segment(1) | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
(in millions except percentages) | |||||||||||||||||||||
QEP Energy | $ | 271.0 | $ | 368.9 | (27 | )% | $ | 773.0 | $ | 1,064.0 | (27 | )% | |||||||||
QEP Marketing and Other | 2.1 | 2.0 | 5 | % | 2.3 | 8.2 | (72 | )% | |||||||||||||
Adjusted EBITDA from continuing operations | 273.1 | 370.9 | (26 | )% | 775.3 | 1,072.2 | (28 | )% | |||||||||||||
Adjusted EBITDA from discontinued operations | — | 38.4 | — | 124.2 | |||||||||||||||||
Adjusted EBITDA | $ | 273.1 | $ | 409.3 | (33 | )% | $ | 775.3 | $ | 1,196.4 | (35 | )% | |||||||||
(1) See attached financial tables of this release for a reconciliation of Adjusted EBITDA to net income. | |||||||||||||||||||||
QEP Energy
▪ | Adjusted EBITDA for the third quarter 2015 was $271.0 million, a decrease of 4% from the second quarter 2015, primarily due to decreased average field-level prices for crude oil and NGL, partially offset by increases in natural gas, crude oil and NGL production and higher average field-level prices for natural gas. |
▪ | QEP Energy's capital expenditures (on an accrual basis) for the third quarter 2015 were $257.5 million, down $17.1 million from the second quarter 2015. For the first nine months of 2015, QEP Energy's capital investment (on an accrual basis) was $812.3 million, down $471.8 million, excluding the Permian Basin acquisition, from the first nine months of 2014. |
▪ | Crude oil, natural gas, and NGL production increased 6%, 8% and 7%, respectively, in the third quarter 2015 compared with the second quarter 2015. |
▪ | Net natural gas equivalent production was 86.7 Bcfe, an increase of 7%, in the third quarter 2015 compared with 80.9 Bcfe in the second quarter 2015. The increase was due primarily to increased production in Pinedale and the Williston and Uinta basins. |
▪ | Crude oil and NGL revenues decreased 17% compared with the second quarter 2015, and represented approximately 64% of field-level production revenues during the third quarter 2015. |
▪ | During the quarter, QEP Energy realized $119.9 million in commodity derivative gains compared with $92.6 million in derivative gains in the second quarter 2015. |
QEP Marketing & Other
▪ | QEP Resources ended the third quarter 2015 with cash and cash equivalents of $495.8 million and no borrowings under its $1.8 billion, unsecured revolving credit facility. The facility is not a reserve based loan and therefore is not subject to semi-annual borrowing base redeterminations. |
▪ | During the third quarter 2015, the Company continued to enter into commodity derivative contracts for 2015, 2016 and 2017 to help manage commodity price risk. See tables provided in this release for further details. |
▪ | During the third quarter 2015 the Company received a $56.2 million cash federal tax refund associated with its 2014 tax return. |
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QEP 2015 Guidance
QEP Resources' full-year 2015 guidance and related assumptions are shown below. The Company’s updated guidance assumes no acquisitions or divestitures and that, where contractually permitted, QEP will not recover ethane from its natural gas production for the entire year:
Guidance and Assumptions | ||
2015 | 2015 | |
Previous Forecast | Current Forecast | |
Oil production (MMbbl) | 18.0 - 19.0 | 19.2 - 19.6 |
NGL production (MMbbl) | 4.0 - 4.3 | 4.3 - 4.6 |
Natural gas production (Bcf) | 165.0 - 175.0 | 177.5 - 182.5 |
Total equivalent production (Bcfe) | 297 - 315 | 319 - 328 |
Lease operating and transportation expense (per Mcfe) | $1.65 - $1.80 | $1.60 - $1.70 |
QEP Energy depletion, depreciation and amortization (per Mcfe) | $2.60 - $2.90 | $2.55 - $2.75 |
Production and property taxes, % of field-level revenue | 8.5% - 9.0% | 8.2% - 8.5% |
Figures below in millions | ||
QEP Resources general and administrative expense(1) | $170 - $185 | $170 - $180 |
QEP Energy capital investment | $900 - $1,050 | $975 - $1,050 |
(1)Excludes pension curtailment.
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Operations Summary
Operated Completions | Non-operated Completions | ||||||||||||||||||||||
Three Months Ended | Nine Months Ended | Three Months Ended | Nine Months Ended | ||||||||||||||||||||
September 30, 2015 | September 30, 2015 | September 30, 2015 | September 30, 2015 | ||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||
Northern Region | |||||||||||||||||||||||
Pinedale | 28 | 17.9 | 83 | 53.7 | — | — | — | — | |||||||||||||||
Williston Basin | 24 | 20.0 | 60 | 47.2 | 35 | 1.5 | 68 | 4.2 | |||||||||||||||
Uinta Basin | 2 | 2.0 | 11 | 11.0 | 2 | 0.1 | 19 | 0.2 | |||||||||||||||
Other Northern | 3 | 3.0 | 4 | 4.0 | — | — | — | — | |||||||||||||||
Southern Region | |||||||||||||||||||||||
Haynesville/Cotton Valley | — | — | — | — | 7 | 1.4 | 20 | 2.9 | |||||||||||||||
Permian Basin | 7 | 6.4 | 31 | 26.9 | — | — | 1 | 0.3 | |||||||||||||||
Midcontinent | — | — | — | — | — | — | 4 | 0.1 | |||||||||||||||
Williston Basin
Williston Basin net production averaged approximately 54.0 MBoed (91% liquids) during the third quarter 2015, a 3% increase over the second quarter 2015, and a 17% increase over the third quarter 2014. QEP completed and turned to sales 24 gross-operated wells during the quarter (average working interest 83%) all in South Antelope. The Company also participated in 35 gross outside-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 4%).
During the third quarter 2015, the Company continued work on its pilot program evaluating high-density infill development drilling on its South Antelope acreage. The Company continued to monitor the progress of five pilot wells spaced at 400- and 600-foot intervals in the Middle Bakken and the Three Forks formations, which were completed and turned to sales in the second quarter 2015. QEP also continued to conduct tests on the second bench of the Three Forks formation, with four wells targeting this zone recently turned to sales to date. The second bench well with the greatest time on production has recovered over 200 MBoe during the first 180 days of production, while the three other wells targeting the second bench are exhibiting a similar production profile in early time performance. Additional second bench and the initial third bench Three Forks tests are in progress with results expected in the fourth quarter 2015.
As the Company continues infill development, well pod size is expected to increase from a current average of four wells to as many as nine wells per pod. Larger well pods will result in increased latency between drilling and completion operations and greater downtime for offset fracture stimulations, which QEP expects will lead to more variability in production volumes from the Company's Williston Basin assets in the future.
At the end of the third quarter, QEP had 19 gross operated wells waiting on completion (average working interest 82%) in the Williston Basin and two operated rigs running on South Antelope. In addition, the Company had interests in 24 gross outside-operated wells waiting on completion (average working interest 3%) at the end of the third quarter.
QEP expects gross drilled and completed well costs to average $6.2 million on South Antelope for the remainder of 2015. Additional gross costs per well for facilities and artificial lift should average approximately $1.1 million.
Slides 6-12 depict QEP's acreage and activity in the Williston Basin.
4
Permian Basin
Permian Basin net production during the third quarter 2015 averaged approximately 13.2 MBoed (82% liquids), a 16% increase over the second quarter 2015, and a 47% increase over the third quarter 2014. QEP completed and turned to sales seven horizontal gross-operated wells in the third quarter 2015 (average working interest 91%). The seven wells included four Spraberry Shale, two Middle Spraberry, and the Company’s first Leonard Shale completions. Of the seven horizontal wells completed during the quarter, the University 7-1726 H1 SS, targeting the Spraberry Shale, reached peak production during the quarter, achieving a peak 24-hour IP rate of 1,523 Boed. At quarter-end the remaining six wells were still cleaning up after completion and had not reached peak rate, but are exhibiting strong initial performance.
At the end of the third quarter, the Company had two gross-operated horizontal Middle Spraberry wells waiting on completion (average working interest 90%) and two operated rigs in the Permian Basin drilling horizontal targets in the Spraberry Shale and Middle Spraberry.
QEP expects gross drilled and completed well costs to average below $6.2 million for Spraberry wells in the Permian Basin for the remainder of 2015. Additional gross costs per well for facilities and artificial lift should average approximately $0.8 million.
Slides 13-15 depict QEP's acreage and activity in the Permian Basin.
Pinedale Anticline
During the third quarter 2015, QEP's Pinedale net production averaged 286 MMcfed (12% liquids), a 4% increase in production over the second quarter 2015, driven by a new natural gas production record. The Company completed and turned to sales 28 gross Pinedale wells in the quarter.
All Pinedale wells turned to sales during the third quarter were completed utilizing a new fracture stimulation design that was first tested in late 2014. The enhanced completion design, which does not increase completed well costs, continues to yield positive results with an average increase in 270-day average cumulative production of approximately 171 MMcfe compared with the previous completion design.
At the end of the third quarter, the Company had 27 gross Pinedale wells with QEP working interests waiting on completion (average working interest 60%) and three operated rigs running in Pinedale. The Company currently expects to complete approximately 20-25 gross wells during the remainder of 2015.
QEP expects gross drilled and completed well costs to average $3.2 million in the Pinedale for the remainder of 2015. Additional gross costs per well for facilities and plunger lift should average approximately $0.2 million.
Slides 16-17 depict QEP's acreage and activity in Pinedale.
Uinta Basin
During the third quarter 2015, Uinta Basin net production averaged 96 MMcfed (21% liquids) of which 56 MMcfed (11% liquids) was from the Red Wash Lower Mesaverde play. QEP completed and turned to sales two horizontal wells in the third quarter 2015 (average working interest 100%). These wells were still in the early stages of cleanup as of quarter end.
QEP’s continued focus on drilling and completion optimization is yielding encouraging results in the Lower Mesaverde play. The Company's most recent pad of eight directionally drilled vertical wells targeting the Lower Mesaverde, which was in the early stages of clean up as of the end of the second quarter 2015, has achieved over 2.4 Bcfe gross cumulative production after 150 days online (post-processing, assumes refrigeration processing). The Company believes it has an extensive inventory of potential well locations in the Lower Mesaverde play and that the
5
strong recent results continue to further de-risk this multi-Tcfe resource while providing better insight as to the appropriate ultimate development plan.
During the quarter, QEP closed on an asset swap transaction acquiring approximately 15,400 net acres, the South Red Wash Unit, and three wells in exchange for a 6.25% overriding royalty in 640 acres and 21.5% overriding royalty in eight wells.
At the end of the third quarter, QEP had one rig active in the Uinta Basin drilling an eight well pad of directionally drilled vertical wells targeting the Lower Mesaverde play.
Slides 18-19 depict QEP's acreage and activity in the Red Wash Lower Mesaverde play in the Uinta Basin.
Third Quarter 2015 Results Conference Call
QEP Resources’ management will discuss third quarter 2015 results in a conference call on Thursday, October 29, 2015, beginning at 9:00 a.m. EDT. The conference call can be accessed at www.qepres.com. You may also participate in the conference call by dialing (877) 869-3847 in the U.S. or Canada and (201) 689-8261 for international calls. A replay of the teleconference will be available on the website immediately after the call through November 29, 2015, or by dialing (877) 660-6853 in the U.S. or Canada and (201) 612-7415 for international calls, and then entering the conference ID # 13621377. In addition, QEP’s slides for the third quarter 2015, with updated maps showing QEP’s leasehold and current activity for key operating areas discussed in this release, can be found on the Company’s website.
About QEP Resources, Inc.
QEP Resources, Inc. (NYSE:QEP) is a leading independent natural gas and crude oil exploration and production company focused in two major regions: the Northern Region (primarily the Rockies and the Williston Basin) and the Southern Region (primarily Texas and Louisiana) of the United States. For more information, visit QEP Resources' website at: www.qepres.com.
6
Forward-Looking Statements
This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,” “expects,” “should,” “will” or other similar expressions. Such statements are based on management’s current expectations, estimates and projections, which are subject to a wide range of uncertainties and business risks. These forward-looking statements include statements regarding: our strategy to navigate the current commodity price environment; our plans to increase operational efficiencies and reduce costs; the quality of our assets; our long-term growth and profitability and factors contributing to such growth and profitability; our financial position; enhanced completion designs and inventory of future development locations; expected gross completed well costs and additional costs for facilities and artificial lift; refinement of development plans; timing of test results from Three Forks wells; increase in well pod size in the Williston and Permian Basins; variability in production volumes from the Williston and Permian Basins and factors contributing to such variability; number of wells to be completed in our areas of operation; de-risking of our Uinta Basin assets; forecasted production, lease operating and transportation expense, depletion, depreciation and amortization expense, general and administrative expense, production and property taxes and capital investment for 2015 and related assumptions for such guidance; plans to reject ethane in 2015; drilling and completion optimization; impact of pension curtailment and the importance of non-GAAP financial measures. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: changes in natural gas, NGL and oil prices; the availability of capital; global geopolitical and macroeconomic factors; general economic conditions, including interest rates; changes in local, regional, national and global demand for natural gas, oil and NGL; impact of new laws and regulations, including regulations regarding the flaring of natural gas, the use of hydraulic fracture stimulation and the implementation of the Dodd-Frank Act; impact of U.S. dollar exchange rates on oil, NGL and natural gas prices; elimination of federal income tax deductions for oil and gas exploration and development; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; transportation constraints; weather conditions; changes in maintenance, 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/A for the year ended December 31, 2014, and the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 . 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.
Contact
Investors: Media:
William I. Kent Brent Rockwood
Director, Investor Relations Director, Communications
303-405-6665 303-672-6999
7
QEP RESOURCES, INC. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) | |||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||
September 30, | September 30, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
REVENUES | (in millions except per share data) | ||||||||||||||
Gas sales | $ | 129.4 | $ | 171.6 | $ | 363.3 | $ | 609.2 | |||||||
Oil sales | 211.7 | 393.5 | 640.9 | 1,041.0 | |||||||||||
NGL sales | 16.5 | 51.1 | 61.7 | 179.3 | |||||||||||
Other revenue | 2.8 | 3.4 | 12.4 | 5.1 | |||||||||||
Purchased gas and oil sales | 176.3 | 290.4 | 558.6 | 780.1 | |||||||||||
Total Revenues | 536.7 | 910.0 | 1,636.9 | 2,614.7 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Purchased gas and oil expense | 175.1 | 288.4 | 561.7 | 775.5 | |||||||||||
Lease operating expense | 56.7 | 61.1 | 175.6 | 177.0 | |||||||||||
Gas, oil and NGL transportation and other handling costs | 78.1 | 71.1 | 216.2 | 198.5 | |||||||||||
Gathering and other expense | 1.3 | 1.4 | 4.4 | 4.8 | |||||||||||
General and administrative | 42.0 | 49.4 | 140.7 | 147.0 | |||||||||||
Production and property taxes | 30.2 | 59.4 | 90.7 | 160.8 | |||||||||||
Depreciation, depletion and amortization | 238.1 | 251.4 | 649.3 | 712.5 | |||||||||||
Exploration expenses | 0.8 | 0.8 | 2.7 | 4.7 | |||||||||||
Impairment | 15.0 | 0.1 | 35.5 | 3.6 | |||||||||||
Total Operating Expenses | 637.3 | 783.1 | 1,876.8 | 2,184.4 | |||||||||||
Net gain (loss) from asset sales | 12.9 | (11.8 | ) | 6.9 | (210.3 | ) | |||||||||
OPERATING INCOME (LOSS) | (87.7 | ) | 115.1 | (233.0 | ) | 220.0 | |||||||||
Realized and unrealized gains (losses) on derivative contracts | 153.6 | 155.7 | 168.5 | (13.2 | ) | ||||||||||
Interest and other income | 0.3 | 4.2 | 1.5 | 7.8 | |||||||||||
Income from unconsolidated affiliates | — | 0.1 | — | 0.2 | |||||||||||
Interest expense | (36.4 | ) | (41.5 | ) | (109.4 | ) | (128.4 | ) | |||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 29.8 | 233.6 | (172.4 | ) | 86.4 | ||||||||||
Income tax (provision) benefit | (8.7 | ) | (79.9 | ) | 61.6 | (26.1 | ) | ||||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | 21.1 | 153.7 | (110.8 | ) | 60.3 | ||||||||||
Net income from discontinued operations, net of income tax | — | 17.4 | — | 58.2 | |||||||||||
NET INCOME (LOSS) | $ | 21.1 | $ | 171.1 | $ | (110.8 | ) | $ | 118.5 | ||||||
Earnings (Loss) Per Common Share | |||||||||||||||
Basic from continuing operations | $ | 0.12 | $ | 0.85 | $ | (0.63 | ) | $ | 0.34 | ||||||
Basic from discontinued operations | — | 0.10 | — | 0.32 | |||||||||||
Basic total | $ | 0.12 | $ | 0.95 | $ | (0.63 | ) | $ | 0.66 | ||||||
Diluted from continuing operations | $ | 0.12 | $ | 0.84 | $ | (0.63 | ) | $ | 0.34 | ||||||
Diluted from discontinued operations | — | 0.10 | — | 0.32 | |||||||||||
Diluted total | $ | 0.12 | $ | 0.94 | $ | (0.63 | ) | $ | 0.66 | ||||||
Weighted-average common shares outstanding | |||||||||||||||
Used in basic calculation | 176.7 | 180.1 | 176.5 | 180.0 | |||||||||||
Used in diluted calculation | 176.7 | 180.6 | 176.5 | 180.4 | |||||||||||
Dividends per common share | $ | 0.02 | $ | 0.02 | $ | 0.06 | $ | 0.06 | |||||||
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QEP RESOURCES, INC. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) | |||||||
September 30, 2015 | December 31, 2014 | ||||||
ASSETS | (in millions) | ||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 495.8 | $ | 1,160.1 | |||
Accounts receivable, net | 316.2 | 441.9 | |||||
Fair value of derivative contracts | 183.9 | 339.0 | |||||
Gas, oil and NGL inventories, at lower of average cost or market | 12.2 | 13.7 | |||||
Prepaid expenses and other | 32.4 | 46.8 | |||||
Total Current Assets | 1,040.5 | 2,001.5 | |||||
Property, Plant and Equipment (successful efforts method for oil and gas properties) | |||||||
Proved properties | 12,911.5 | 12,278.7 | |||||
Unproved properties | 839.5 | 825.2 | |||||
Marketing and other | 298.0 | 293.8 | |||||
Material and supplies | 35.9 | 54.3 | |||||
Total Property, Plant and Equipment | 14,084.9 | 13,452.0 | |||||
Less Accumulated Depreciation, Depletion and Amortization | |||||||
Exploration and production | 6,653.7 | 6,153.0 | |||||
Marketing and other | 82.7 | 67.8 | |||||
Total Accumulated Depreciation, Depletion and Amortization | 6,736.4 | 6,220.8 | |||||
Net Property, Plant and Equipment | 7,348.5 | 7,231.2 | |||||
Fair value of derivative contracts | 17.0 | 9.9 | |||||
Other noncurrent assets | 50.1 | 44.2 | |||||
TOTAL ASSETS | $ | 8,456.1 | $ | 9,286.8 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Checks outstanding in excess of cash balances | $ | 12.8 | $ | 54.7 | |||
Accounts payable and accrued expenses | 409.2 | 575.4 | |||||
Income taxes payable | — | 532.1 | |||||
Production and property taxes | 58.8 | 61.7 | |||||
Interest payable | 33.7 | 36.4 | |||||
Deferred income taxes | 47.4 | 84.5 | |||||
Current portion of long-term debt | 176.7 | — | |||||
Total Current Liabilities | 738.6 | 1,344.8 | |||||
Long-term debt | 2,041.8 | 2,218.1 | |||||
Deferred income taxes | 1,423.2 | 1,362.7 | |||||
Asset retirement obligations | 187.7 | 193.8 | |||||
Other long-term liabilities | 92.7 | 92.1 | |||||
Commitments and contingencies | |||||||
EQUITY | |||||||
Common stock - par value $0.01 per share; 500.0 million shares authorized; 177.1 million and 176.2 million shares issued, respectively | 1.8 | 1.8 | |||||
Treasury stock - 0.4 million and 0.8 million shares, respectively | (10.0 | ) | (25.4 | ) | |||
Additional paid-in capital | 544.1 | 535.3 | |||||
Retained earnings | 3,459.3 | 3,587.9 | |||||
Accumulated other comprehensive income (loss) | (23.1 | ) | (24.3 | ) | |||
Total Common Shareholders' Equity | 3,972.1 | 4,075.3 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 8,456.1 | $ | 9,286.8 | |||
9
QEP RESOURCES, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) | |||||||
Nine Months Ended | |||||||
September 30, | |||||||
2015 | 2014 | ||||||
(in millions) | |||||||
OPERATING ACTIVITIES | |||||||
Net income (loss) | $ | (110.8 | ) | $ | 118.5 | ||
Net income attributable to noncontrolling interests | — | 17.6 | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 649.3 | 755.8 | |||||
Deferred income taxes | 22.7 | 91.5 | |||||
Impairment | 35.5 | 3.6 | |||||
Share-based compensation | 23.3 | 23.7 | |||||
Pension curtailment loss | 11.2 | — | |||||
Amortization of debt issuance costs and discounts | 4.7 | 5.1 | |||||
Net (gain) loss from asset sales | (6.9 | ) | 210.3 | ||||
Income from unconsolidated affiliates | — | (4.6 | ) | ||||
Distributions from unconsolidated affiliates and other | — | 5.1 | |||||
Unrealized (gains) losses on derivative contracts | 148.0 | (65.9 | ) | ||||
Changes in operating assets and liabilities | (503.1 | ) | 59.0 | ||||
Net Cash Provided by Operating Activities | 273.9 | 1,219.7 | |||||
INVESTING ACTIVITIES | |||||||
Property acquisitions | (23.5 | ) | (949.7 | ) | |||
Property, plant and equipment, including dry exploratory well expense | (862.6 | ) | (1,270.4 | ) | |||
Proceeds from disposition of assets | 5.2 | 706.2 | |||||
Acquisition deposit held in escrow | — | 50.0 | |||||
Other investing activities | — | 3.2 | |||||
Net Cash Used in Investing Activities | (880.9 | ) | (1,460.7 | ) | |||
FINANCING ACTIVITIES | |||||||
Checks outstanding in excess of cash balances | (41.9 | ) | (81.1 | ) | |||
Long-term debt issued | — | 300.0 | |||||
Long-term debt issuance costs paid | — | (1.1 | ) | ||||
Proceeds from credit facility | — | 4,509.0 | |||||
Repayments of credit facility | — | (4,461.5 | ) | ||||
Treasury stock repurchases | (2.3 | ) | (6.6 | ) | |||
Other capital contributions | (0.1 | ) | 5.1 | ||||
Dividends paid | (10.6 | ) | (10.8 | ) | |||
Excess tax (provision) benefit on share-based compensation | (2.4 | ) | (0.6 | ) | |||
Distribution to noncontrolling interest | — | (23.3 | ) | ||||
Net Cash (Used in) Provided by Financing Activities | (57.3 | ) | 229.1 | ||||
Change in cash and cash equivalents | (664.3 | ) | (11.9 | ) | |||
Beginning cash and cash equivalents | 1,160.1 | 11.9 | |||||
Ending cash and cash equivalents | $ | 495.8 | $ | — | |||
10
QEP Energy - Production by Region | |||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||
September 30, | September 30, | ||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
(in Bcfe) | (in Bcfe) | ||||||||||||||||
Northern Region | |||||||||||||||||
Pinedale | 26.3 | 26.4 | (0.4 | )% | 73.0 | 72.6 | 1 | % | |||||||||
Williston Basin | 29.8 | 25.4 | 17 | % | 83.8 | 61.6 | 36 | % | |||||||||
Uinta Basin | 8.8 | 6.8 | 29 | % | 23.0 | 19.8 | 16 | % | |||||||||
Other Northern | 2.7 | 1.9 | 42 | % | 7.8 | 7.9 | (1 | )% | |||||||||
Total Northern Region | 67.6 | 60.5 | 12 | % | 187.6 | 161.9 | 16 | % | |||||||||
Southern Region | |||||||||||||||||
Haynesville/Cotton Valley | 11.2 | 11.4 | (2 | )% | 33.3 | 38.9 | (14 | )% | |||||||||
Permian Basin | 7.3 | 5.0 | 46 | % | 18.4 | 10.4 | 77 | % | |||||||||
Midcontinent | 0.6 | 2.3 | (74 | )% | 3.5 | 25.6 | (86 | )% | |||||||||
Total Southern Region | 19.1 | 18.7 | 2 | % | 55.2 | 74.9 | (26 | )% | |||||||||
Total production | 86.7 | 79.2 | 9 | % | 242.8 | 236.8 | 3 | % | |||||||||
QEP Energy - Total Production | |||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||
September 30, | September 30, | ||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
QEP Energy Production Volumes | |||||||||||||||||
Gas (Bcf) | 48.0 | 41.8 | 15 | % | 135.1 | 134.9 | 0.1 | % | |||||||||
Oil (Mbbl) | 5,162.1 | 4,672.4 | 10 | % | 14,519.4 | 11,965.0 | 21 | % | |||||||||
NGL (Mbbl) | 1,286.9 | 1,563.5 | (18 | )% | 3,432.3 | 5,017.8 | (32 | )% | |||||||||
Total production (Bcfe) | 86.7 | 79.2 | 9 | % | 242.8 | 236.8 | 3 | % | |||||||||
Average daily production (MMcfe) | 942.4 | 860.9 | 9 | % | 889.4 | 867.4 | 3 | % | |||||||||
11
QEP Energy - Prices | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
Gas (per Mcf) | |||||||||||||||||||||
Average field-level price | $ | 2.69 | $ | 4.10 | $ | 2.69 | $ | 4.52 | |||||||||||||
Commodity derivative impact | 0.48 | 0.13 | 0.51 | (0.18 | ) | ||||||||||||||||
Net realized price | $ | 3.17 | $ | 4.23 | (25 | )% | $ | 3.20 | $ | 4.34 | (26 | )% | |||||||||
Oil (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 41.01 | $ | 84.21 | $ | 44.13 | $ | 86.98 | |||||||||||||
Commodity derivative impact | 18.75 | (2.60 | ) | 16.90 | (4.20 | ) | |||||||||||||||
Net realized price | $ | 59.76 | $ | 81.61 | (27 | )% | $ | 61.03 | $ | 82.78 | (26 | )% | |||||||||
NGL (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 12.85 | $ | 32.68 | $ | 17.93 | $ | 35.68 | |||||||||||||
Commodity derivative impact | — | — | — | — | |||||||||||||||||
Net realized price | $ | 12.85 | $ | 32.68 | (61 | )% | $ | 17.93 | $ | 35.68 | (50 | )% | |||||||||
Average net equivalent price (per Mcfe) | |||||||||||||||||||||
Average field-level price | $ | 4.12 | $ | 7.77 | $ | 4.39 | $ | 7.72 | |||||||||||||
Commodity derivative impact | 1.38 | (0.08 | ) | 1.29 | (0.31 | ) | |||||||||||||||
Net realized price | $ | 5.50 | $ | 7.69 | (28 | )% | $ | 5.68 | $ | 7.41 | (23 | )% | |||||||||
QEP Energy - Operating Expenses | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
(per Mcfe) | |||||||||||||||||||||
Depreciation, depletion and amortization | $ | 2.72 | $ | 3.14 | (13 | )% | $ | 2.64 | $ | 2.98 | (11 | )% | |||||||||
Lease operating expense | 0.65 | 0.77 | (16 | )% | 0.72 | 0.75 | (4 | )% | |||||||||||||
Gas, oil and NGL transport & other handling costs | 0.92 | 0.95 | (3 | )% | 0.92 | 0.89 | 3 | % | |||||||||||||
Production and property taxes | 0.34 | 0.75 | (55 | )% | 0.36 | 0.67 | (46 | )% | |||||||||||||
Total Operating Expenses | $ | 4.63 | $ | 5.61 | (17 | )% | $ | 4.64 | $ | 5.29 | (12 | )% | |||||||||
12
QEP RESOURCES, INC.
NON-GAAP MEASURES
(Unaudited)
Adjusted EBITDA
This release contains references to the non-GAAP measure of Adjusted EBITDA. Management believes Adjusted EBITDA is an important measure of the Company’s financial and operating performance that allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA) adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items. The following table reconciles net income, the most comparable GAAP financial measure, to Adjusted EBITDA:
QEP Energy | QEP Marketing & Other (1) | Continuing Operations | Discontinued Operations | QEP Consolidated | |||||||||||||||
Three Months Ended September 30, 2015 | (in millions) | ||||||||||||||||||
Net income (loss) | $ | 10.8 | $ | 10.3 | $ | 21.1 | $ | — | $ | 21.1 | |||||||||
Unrealized (gains) losses on derivative contracts | (32.4 | ) | (1.4 | ) | (33.8 | ) | — | (33.8 | ) | ||||||||||
Net (gain) loss from asset sales | (13.2 | ) | 0.3 | (12.9 | ) | — | (12.9 | ) | |||||||||||
Interest and other (income) expense | (0.9 | ) | 0.6 | (0.3 | ) | — | (0.3 | ) | |||||||||||
Income tax provision (benefit) | 2.8 | 5.9 | 8.7 | — | 8.7 | ||||||||||||||
Interest expense (income) | 52.4 | (16.0 | ) | 36.4 | — | 36.4 | |||||||||||||
Depreciation, depletion and amortization | 235.7 | 2.4 | 238.1 | — | 238.1 | ||||||||||||||
Impairment | 15.0 | — | 15.0 | — | 15.0 | ||||||||||||||
Exploration expenses | 0.8 | — | 0.8 | — | 0.8 | ||||||||||||||
Adjusted EBITDA | $ | 271.0 | $ | 2.1 | $ | 273.1 | $ | — | $ | 273.1 | |||||||||
Three Months Ended September 30, 2014 | |||||||||||||||||||
Net income (loss) | $ | 145.7 | $ | 8.0 | $ | 153.7 | $ | 17.4 | $ | 171.1 | |||||||||
Unrealized (gains) losses on derivative contracts | (160.8 | ) | (3.3 | ) | (164.1 | ) | — | (164.1 | ) | ||||||||||
Net (gain) loss from asset sales | 11.9 | (0.1 | ) | 11.8 | — | 11.8 | |||||||||||||
Interest and other (income) expense | (3.9 | ) | (0.3 | ) | (4.2 | ) | — | (4.2 | ) | ||||||||||
Income tax provision (benefit) | 69.1 | 10.8 | 79.9 | 9.9 | 89.8 | ||||||||||||||
Interest expense (income) (2) | 57.0 | (15.5 | ) | 41.5 | 0.8 | 42.3 | |||||||||||||
Depreciation, depletion and amortization (3) | 249.0 | 2.4 | 251.4 | 10.3 | 261.7 | ||||||||||||||
Impairment | 0.1 | — | 0.1 | — | 0.1 | ||||||||||||||
Exploration expenses | 0.8 | — | 0.8 | — | 0.8 | ||||||||||||||
Adjusted EBITDA | $ | 368.9 | $ | 2.0 | $ | 370.9 | $ | 38.4 | $ | 409.3 | |||||||||
_________________________
(1) | Includes intercompany eliminations. |
(2) | Excludes noncontrolling interest's share of $0.7 million during the three months ended September 30, 2014, of interest expense attributable to QEP Midstream Partners, LP (QEP Midstream). |
(3) | Excludes noncontrolling interest's share of $4.0 million during the three months ended September 30, 2014, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream. |
13
QEP Energy | QEP Marketing & Other (1) | Continuing Operations | Discontinued Operations | QEP Consolidated | |||||||||||||||
Nine Months Ended September 30, 2015 | (in millions) | ||||||||||||||||||
Net income (loss) | $ | (131.9 | ) | $ | 21.1 | $ | (110.8 | ) | $ | — | $ | (110.8 | ) | ||||||
Unrealized (gains) losses on derivative contracts | 147.5 | 0.5 | 148.0 | — | 148.0 | ||||||||||||||
Net (gain) loss from asset sales | (11.9 | ) | 5.0 | (6.9 | ) | — | (6.9 | ) | |||||||||||
Interest and other (income) expense | (0.5 | ) | (1.0 | ) | (1.5 | ) | — | (1.5 | ) | ||||||||||
Income tax provision (benefit) | (73.2 | ) | 11.6 | (61.6 | ) | — | (61.6 | ) | |||||||||||
Interest expense (income) | 152.2 | (42.8 | ) | 109.4 | — | 109.4 | |||||||||||||
Pension curtailment loss (2) | 11.0 | 0.2 | 11.2 | — | 11.2 | ||||||||||||||
Depreciation, depletion and amortization | 641.6 | 7.7 | 649.3 | — | 649.3 | ||||||||||||||
Impairment | 35.5 | — | 35.5 | — | 35.5 | ||||||||||||||
Exploration expenses | 2.7 | — | 2.7 | — | 2.7 | ||||||||||||||
Adjusted EBITDA | $ | 773.0 | $ | 2.3 | $ | 775.3 | $ | — | $ | 775.3 | |||||||||
Nine Months Ended September 30, 2014 | |||||||||||||||||||
Net income (loss) | $ | 40.4 | $ | 19.9 | $ | 60.3 | 58.2 | $ | 118.5 | ||||||||||
Unrealized (gains) losses on derivative contracts | (63.8 | ) | (2.1 | ) | (65.9 | ) | — | (65.9 | ) | ||||||||||
Net (gain) loss from asset sales | 210.3 | — | 210.3 | 0.1 | 210.4 | ||||||||||||||
Interest and other (income) expense | (7.4 | ) | (0.4 | ) | (7.8 | ) | — | (7.8 | ) | ||||||||||
Income tax provision (benefit) | 9.0 | 17.1 | 26.1 | 32.8 | 58.9 | ||||||||||||||
Interest expense (income) (3) | 162.5 | (34.1 | ) | 128.4 | 1.7 | 130.1 | |||||||||||||
Depreciation, depletion and amortization (4) | 704.7 | 7.8 | 712.5 | 31.4 | 743.9 | ||||||||||||||
Impairment | 3.6 | — | 3.6 | — | 3.6 | ||||||||||||||
Exploration expenses | 4.7 | — | 4.7 | — | 4.7 | ||||||||||||||
Adjusted EBITDA | $ | 1,064.0 | $ | 8.2 | $ | 1,072.2 | $ | 124.2 | $ | 1,196.4 | |||||||||
_________________________
(1) | Includes intercompany eliminations. |
(2) | The pension curtailment loss is a non-cash loss that was incurred during the nine months ended September 30, 2015, due to changes in the Company's pension plan. The Company believes that the pension curtailment loss does not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded the loss from the calculation of Adjusted EBITDA. |
(3) | Excludes noncontrolling interest's share of $1.1 million during the nine months ended September 30, 2014, of interest expense attributable to QEP Midstream. |
(4) | Excludes noncontrolling interest's share of $11.7 million during the nine months September 30, 2014, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream. |
14
Adjusted Net Income
This release also contains references to the non-GAAP measure of Adjusted Net Income. Management defines Adjusted Net Income as earnings excluding gains and losses from asset sales, unrealized gains and losses on derivative contracts, asset impairments, and certain other non-cash and/or non-recurring items. Management believes Adjusted Net Income is an important measure of the Company’s operational performance relative to other gas and oil producing companies.
The following table reconciles net income to Adjusted Net Income:
Three Months Ended | Nine Months Ended | ||||||||||||||
September 30, | September 30, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
(in millions, except earnings per share) | |||||||||||||||
Net income (loss) | $ | 21.1 | $ | 171.1 | $ | (110.8 | ) | $ | 118.5 | ||||||
Adjustments to net income | |||||||||||||||
Net (gain) loss from asset sales from continuing operations | (12.9 | ) | 11.8 | (6.9 | ) | 210.3 | |||||||||
Income taxes on net (gain) loss from asset sales from continuing operations | 4.7 | (4.4 | ) | 2.5 | (78.2 | ) | |||||||||
Unrealized (gains) losses on derivative contracts from continuing operations | (33.8 | ) | (164.1 | ) | 148.0 | (65.9 | ) | ||||||||
Income taxes on unrealized (gains) losses on derivative contracts from continuing operations | 12.4 | 61.0 | (54.2 | ) | 24.5 | ||||||||||
Pension curtailment loss | — | — | 11.2 | — | |||||||||||
Income taxes on pension curtailment loss | — | — | (4.1 | ) | — | ||||||||||
Impairment charges from continuing operations | 15.0 | 0.1 | 35.5 | 3.6 | |||||||||||
Income taxes impairment charges from continuing operations | (5.5 | ) | — | (13.0 | ) | (1.3 | ) | ||||||||
Total after-tax adjustments to net income | (20.1 | ) | (95.6 | ) | 119.0 | 93.0 | |||||||||
Adjusted net income | 1.0 | 75.5 | 8.2 | 211.5 | |||||||||||
Net income from discontinued operations, net of income tax | — | (17.4 | ) | — | (58.2 | ) | |||||||||
Adjusted net income (loss) from continuing operations | $ | 1.0 | $ | 58.1 | $ | 8.2 | $ | 153.3 | |||||||
Earnings (Loss) per Common Share | |||||||||||||||
Diluted earnings per share | $ | 0.12 | $ | 0.94 | $ | (0.63 | ) | $ | 0.66 | ||||||
Diluted after-tax adjustments to net income per share | (0.11 | ) | (0.53 | ) | 0.67 | 0.52 | |||||||||
Diluted adjusted net income (loss) per share | 0.01 | 0.41 | 0.04 | 1.18 | |||||||||||
Diluted from discontinued operations | — | (0.10 | ) | — | (0.32 | ) | |||||||||
Diluted adjusted net income (loss) from continuing operations per share | $ | 0.01 | $ | 0.31 | $ | 0.04 | $ | 0.86 | |||||||
Weighted-average common shares outstanding | |||||||||||||||
Diluted | 176.7 | 180.6 | 176.5 | 180.4 | |||||||||||
15
The following tables present open 2015 derivative positions as of October 23, 2015:
QEP Energy Commodity Derivative Swap Positions
Year | Index | Total Volumes | Average Swap Price Per Unit | ||||||
(in millions) | |||||||||
Gas sales | (MMBtu) | ||||||||
2015 | NYMEX HH | 11.6 | $ | 3.48 | |||||
2015 | IFNPCR | 7.9 | $ | 3.55 | |||||
2016 | NYMEX HH | 22.0 | $ | 3.19 | |||||
2016 | IFNPCR | 32.9 | $ | 2.92 | |||||
2017 | NYMEX HH | 7.3 | $ | 3.21 | |||||
Oil Sales | (bbls) | ||||||||
2015 | NYMEX WTI | 2.6 | $ | 82.09 | |||||
2015 | ICE Brent | 0.1 | $ | 104.95 | |||||
2016 | NYMEX WTI | 4.8 | $ | 61.40 | |||||
2017 | NYMEX WTI | 1.5 | $ | 54.61 | |||||
QEP Energy Gas Collars
Year | Index | Total Volume | Average Price Floor | Average Price Ceiling | |||||||||
(in millions) | |||||||||||||
(MMBtu) | ($/MMBtu) | ($/MMBtu) | |||||||||||
2016 | NYMEX HH | 7.3 | $ | 2.75 | $ | 3.89 | |||||||
QEP Energy Gas Basis Swaps
Year | Index Less Differential | Index | Total Volumes | Weighted Average Differential | |||||||
(in millions) | |||||||||||
(MMBtu) | ($/MMBtu) | ||||||||||
2015 | NYMEX HH | IFNPCR | 7.3 | $ | (0.28 | ) | |||||
2016 | NYMEX HH | IFNPCR | 7.3 | $ | (0.20 | ) | |||||
QEP Marketing Commodity Derivative Positions
Year | Type of Contract | Index | Total Volumes | Average Swap price per MMBtu | |||||||
(in millions) | |||||||||||
Gas sales | (MMBtu) | ||||||||||
2015 | SWAP | IFNPCR | 2.4 | $ | 3.28 | ||||||
2016 | SWAP | IFNPCR | 3.7 | $ | 2.97 | ||||||
Gas purchases | (MMBtu) | ||||||||||
2015 | SWAP | IFNPCR | 1.8 | $ | 2.51 | ||||||
16