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 - August 3, 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 August 3, 2015, QEP Resources, Inc. (the “Registrant”) issued a press release to report the results of operations for the period ended June 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 June 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 August 3, 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) | ||
August 4, 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 August 3, 2015, by QEP Resources, Inc. | |
QEP RESOURCES REPORTS SECOND QUARTER 2015 FINANCIAL AND OPERATING RESULTS
▪ | Reported Adjusted EBITDA in excess of capital expenditures |
▪ | Delivered strong performance from Williston Basin high-density infill wells |
▪ | Achieved significant capital and operating efficiencies |
▪ | Maintained strong balance sheet |
▪ | Raised full-year crude oil production forecast |
DENVER — August 3, 2015 — QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported second quarter 2015 financial and operating results. The Company reported a net loss from continuing operations of $76.3 million, or $0.43 per diluted share, for the second quarter 2015 compared with a net loss from continuing operations of $106.1 million, or $0.59 per diluted share, in the second quarter 2014.
Net income or loss includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, a non-cash pension curtailment expense and impairment charges. Excluding these items, the Company’s second quarter 2015 Adjusted Net Income (a non-GAAP measure) was $16.0 million, or $0.09 per diluted share, compared with Adjusted Net Income from continuing operations of $54.1 million, or $0.30 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 volumes, lower production taxes and higher proceeds from realized commodity derivatives.
Adjusted EBITDA (a non-GAAP measure) for the second quarter 2015 was $279.4 million, compared with $368.2 million on a continuing operations basis in the second quarter 2014, a 24% 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 second quarter operational performance demonstrates our ability to quickly adjust to the challenging and volatile commodity price environment. By increasing operating efficiencies and capturing lower service and supply costs, we have significantly reduced well costs in our core plays and under-spent Adjusted EBITDA in the quarter,” commented Chuck Stanley, Chairman, President and CEO of QEP Resources. “We delivered strong oil production growth in the quarter, up 9% sequentially from the first quarter 2015, primarily from better completed well performance in the Williston and Permian basins.
“We are excited by the early performance of our first set of high-density infill development wells at South Antelope in the Williston Basin. The high-density infill wells are exceeding the performance of the original parent wells drilled on the acreage. With these encouraging results, we believe we have in excess of 400 future development locations in the Middle Bakken and Three Forks formations at South Antelope. We continue to evaluate enhanced completions and infill potential across our remaining Williston Basin acreage.
“We have a proven track-record of increasing operating efficiency, reducing well costs and improving well productivity, as exemplified by our second quarter results. We are well positioned in the current market, with our superior E&P asset portfolio, solid balance sheet, unsecured credit facility and substantial cash balance, to deliver long-term growth and profitability,” concluded Stanley.
Slides for the second 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 | Six Months Ended | ||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
(in millions except percentages) | |||||||||||||||||||||
QEP Energy | $ | 280.9 | $ | 366.5 | (23 | )% | $ | 502.0 | $ | 695.1 | (28 | )% | |||||||||
QEP Marketing and Other | (1.5 | ) | 1.7 | (188 | )% | 0.2 | 6.2 | (97 | )% | ||||||||||||
Adjusted EBITDA from continuing operations | 279.4 | 368.2 | (24 | )% | 502.2 | 701.3 | (28 | )% | |||||||||||||
Adjusted EBITDA from discontinued operations | — | 32.6 | (100 | )% | — | 85.8 | (100 | )% | |||||||||||||
Adjusted EBITDA | $ | 279.4 | $ | 400.8 | (30 | )% | $ | 502.2 | $ | 787.1 | (36 | )% | |||||||||
(1) See attached financial tables of this release for a reconciliation of Adjusted EBITDA to net income. | |||||||||||||||||||||
QEP Energy
▪ | Adjusted EBITDA for the second quarter 2015 was $279.4 million an increase of 25% from the first quarter 2015, driven by increases in gas, crude oil and NGL production and an increase in average field level prices for crude oil and NGL. |
▪ | QEP Energy's capital expenditures (on an accrual basis) for the second quarter 2015 were $274.6 million, down $5.6 million from the first quarter 2015. For the first six months of 2015, QEP Energy's capital investment (on an accrual basis) was $554.8 million, down $213.9 million, excluding the Permian Basin acquisition, from the first six months of 2014. |
▪ | Crude oil production increased 9%, natural gas production increased 4% and NGL production increased 26% in the second quarter 2015 compared with the first quarter 2015. |
▪ | Net natural gas equivalent production increased by 8% to 80.9 Bcfe in the second quarter 2015 compared with 75.2 Bcfe in the first quarter 2015. The increase was due primarily to increased production in the Williston and Permian basins, partially offset by decreased Haynesville production. |
▪ | Crude oil and NGL revenues increased 40% compared with the first quarter 2015, and represented approximately 71% of field-level production revenues. |
▪ | During the quarter QEP Energy realized $92.6 million in commodity derivative gains compared with $101.9 million in derivative gains in the first quarter 2015. |
QEP Marketing & Other
▪ | QEP Resources ended the second quarter 2015 with $445.6 million of cash and cash equivalents and no borrowings under its $1.8 billion unsecured revolving credit facility. The Company also had $2.2 billion of senior notes outstanding as of the end of the second quarter 2015 with earliest maturity of $176.8 million in the third quarter 2016. |
▪ | The Company continued to layer on derivative instruments for 2015 and 2016 forecasted production in the second quarter 2015. At June 30, 2015, the Company had approximately 60% of its remaining 2015 forecasted production covered by derivative instruments. |
▪ | On July 30, 2015, QEP Resources announced the closing of its regional office in Tulsa, Oklahoma, which represents approximately 10% of the Company's workforce. The Company believes managing its entire asset portfolio and locating all of the Company’s technical and commercial teams at its Denver, Colorado headquarters will maximize organizational flexibility and efficiency and decrease general and administrative costs. Restructuring costs associated with the closure are estimated to be approximately $6.0 million to $10.0 million, the majority of which are expected to be incurred during the year ended December 31, 2015. The Company expects to close its Tulsa office by the fall of 2015. |
2
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 QEP will not recover ethane from its produced gas for the entire year:
Guidance and Assumptions | ||
2015 | 2015 | |
Previous Forecast | Current Forecast | |
QEP Energy oil production (MMbbl) | 17.0 - 18.5 | 18.0 - 19.0 |
QEP Energy NGL production (MMbbl) | 4.0 - 4.3 | 4.0 - 4.3 |
QEP Energy natural gas production (Bcf) | 165 - 175 | 165 - 175 |
QEP Energy total equivalent production (Bcfe) | 291 - 312 | 297 - 315 |
Lease operating and transportation expense (per Mcfe) | $1.70 - $1.85 | $1.65 - $1.80 |
QEP Energy depletion, depreciation and amortization (per Mcfe) | $2.70 - $3.00 | $2.60 - $2.90 |
Production and property taxes, % of field-level revenue | 8.5% - 9.0% | 8.5% - 9.0% |
Figures below in millions | ||
QEP Resources general and administrative expense(1) | $170 - $185 | $170 - $185 |
QEP Resources capital investment | $900 - $1,050 | $900 - $1,050 |
(1)Excludes pension curtailment and employee-related severance costs.
▪ | The Company expects capital investment in the second-half 2015 to decline from the first six months of 2015, as improved operational efficiencies are realized and lower service and supply costs are fully captured. |
3
Operations Summary
Operated Completions | Non-operated Completions | ||||||||||||||||||||||
Three Months Ended | Six Months Ended | Three Months Ended | Six Months Ended | ||||||||||||||||||||
June 30, 2015 | June 30, 2015 | June 30, 2015 | June 30, 2015 | ||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||
Northern Region | |||||||||||||||||||||||
Pinedale | 35 | 21.3 | 55 | 35.8 | — | — | — | — | |||||||||||||||
Williston Basin | 20 | 14.4 | 36 | 27.2 | 11 | 1.0 | 33 | 2.7 | |||||||||||||||
Uinta Basin | 8 | 8.0 | 9 | 9.0 | 4 | — | 17 | 0.1 | |||||||||||||||
Other Northern | — | — | 1 | 1.0 | — | — | — | — | |||||||||||||||
Southern Region | |||||||||||||||||||||||
Haynesville/Cotton Valley | — | — | — | — | 4 | 1.1 | 13 | 1.5 | |||||||||||||||
Permian Basin | 13 | 10.4 | 24 | 20.5 | — | — | 1 | 0.3 | |||||||||||||||
Midcontinent | — | — | — | — | 1 | — | 4 | 0.1 | |||||||||||||||
Williston Basin
Williston Basin net production averaged approximately 52.4 MBoed (89% liquids) during the second quarter 2015, an 11% increase over the first quarter 2015, and a 48% increase over the second quarter 2014. QEP completed and turned to sales 20 gross-operated wells during the quarter (average working interest 72%), 15 of which were in South Antelope. The Company also participated in 11 gross outside-operated Bakken/Three Forks wells that were completed and turned to sales during the quarter (average working interest 9%).
QEP expects gross drilled and completed well costs to average $6.2 million on South Antelope and $6.7 million on the Fort Berthold Indian Reservation for the remainder of 2015. Additional costs per well for facilities and artificial lift should average approximately $1.1 million.
During the quarter the Company continued work on a pilot program to evaluate high-density infill development drilling on its South Antelope acreage. During the second quarter 2015, the Company completed and turned to sales a total of five pilot wells spaced at 400- and 600-foot intervals, between existing producing wells, in the Middle Bakken and the Three Forks formations. The recently completed high-density infill wells are significantly outperforming the original wells drilled in the 1280-acre spacing unit, with each well having recovered, on average, 100 MBoe during the first 90 days of production. QEP continues to conduct tests on the second bench of the Three Forks, with the first well targeting this zone recovering over 98 MBoe during the first 90 days of production. Additional second and third bench Three Forks tests are in progress with more results expected in the second half of 2015.
At the end of the second quarter, QEP had 34 gross operated wells waiting on completion (average working interest 86%) in the Williston Basin and two operated rigs running, both on South Antelope. In addition, the Company had interests in 44 gross outside-operated wells waiting on completion (average working interest 4%) at the end of the second quarter.
Slides 5-10 depict QEP's acreage and activity in the Williston Basin.
4
Permian Basin
Permian Basin daily production during the second quarter 2015 averaged 11.4 MBoed (81% liquids), a 25% increase over the first quarter 2015, and a 48% increase over the second quarter 2014. QEP completed and turned to sales one vertical and 12 horizontal gross-operated wells in the second quarter 2015 (average working interest 80%). The operated horizontal wells that have reached their peak initial rate, composed of four Wolfcamp B, three Wolfcamp D, and three Spraberry Shale, had an average maximum daily production rate of 1,138 Boed. Seven wells with longer production history, composed of four Wolfcamp B, two Wolfcamp D and one Spraberry Shale wells, had an average maximum average 30-day production rate of 832 Boed, with the Spraberry Shale well having an average maximum 30-day production rate of 1,316 Boed.
The Company continues to refine its development plan in the Permian Basin and moved to pad drilling in the second quarter 2015. QEP expects gross drilled and completed well costs to average $6.2 million for Spraberry wells and $8.0 million for Wolfcamp wells in the Permian Basin for the remainder of 2015. Additional costs per well for facilities and artificial lift should average approximately $0.8 million.
At the end of the second quarter, the Company had two operated rigs in the Permian Basin drilling horizontal targets in the Spraberry Shale and Middle Spraberry. The Company had one gross-operated horizontal Spraberry well waiting on completion (working interest 90%) and one outside-operated horizontal Spraberry well waiting on completion (working interest 57%) at end of the second quarter.
Slides 11-13 depict QEP's acreage and activity in the Permian Basin.
Pinedale Anticline
During the second quarter 2015, QEP's Pinedale net production averaged 274 MMcfed (14% liquids). QEP recovered ethane for all of 2014 and began rejecting ethane at Pinedale in the first quarter 2015. While ethane rejection resulted in 7-8% less natural gas-equivalent sales volumes during the quarter, it had a negligible impact on revenues as ethane is still being sold as part of the natural gas stream.
At the end of the second quarter, the Company had three operated rigs running in Pinedale. The Company completed and turned to sales 35 gross Pinedale wells in the quarter, including seven QEP operated wells, but in which QEP owns only a small overriding royalty interest. At the end of the second quarter, the Company had 34 gross Pinedale wells with QEP working interests waiting on completion (average working interest 63%).
All Pinedale wells turned to sales during the second 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 180-day average cumulative production of approximately 141 MMcfe compared with the previous completion design. QEP expects gross drilled and completed well costs to average $3.2 million in the Pinedale for the remainder of 2015. Additional costs per well for facilities and plunger lift should average approximately $0.2 million.
The Company currently expects to complete approximately 35 gross wells during the remainder of 2015.
Slides 14-15 depict QEP's acreage and activity in Pinedale.
Uinta Basin
During the second quarter 2015, Uinta Basin net production averaged 80 MMcfed (22% liquids) of which 45 MMcfed (12% liquids) was from the Red Wash Lower Mesaverde play. QEP recovered ethane from Uinta Basin gas production throughout 2014 and began rejecting ethane in the first quarter 2015. QEP completed and turned to sales eight vertical wells in the second quarter 2015 (average working interest 100%). These wells were still in the early stages of cleanup as of quarter end.
5
QEP’s continued focus on drilling and completion optimization is yielding encouraging results in the Lower Mesaverde play. The Company's most recent horizontal well, which was completed in the first quarter 2015, has produced greater than 1.8 Bcfe gross after 165 days online (post-processing, assuming ethane rejection). The Company has a deep inventory of potential well locations in the Lower Mesaverde play and the strong recent results serve to further de-risk this multi-Tcfe resource while providing clarity as to the appropriate ultimate development plan.
At the end of the second quarter, QEP had one rig active in the Uinta Basin drilling a horizontal well in the Lower Mesaverde play. The Company had one gross operated, Lower Mesaverde horizontal well drilling (working interest 100%) at the end of the second quarter.
Slides 16-17 depict QEP's acreage and activity in the Red Wash Lower Mesaverde play in the Uinta Basin.
Second Quarter 2015 Results Conference Call
QEP Resources’ management will discuss second quarter 2015 results in a conference call on Tuesday, August 4, 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 September 2, 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 # 13613525. In addition, QEP’s slides for the second 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: enhanced completion designs and inventory of future development locations; superior asset portfolio; our liquidity and future profitability; our financial position; expected gross completed well costs; additional costs for facilities and artificial lift; refinement of development plan; wells to be completed in the Pinedale Anticline; forecasted production, lease operating and transportation expense, DD&A 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; pension losses; timing and anticipated benefits from the closure of our Tulsa, Oklahoma, office; 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. 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 | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
REVENUES | (in millions except per share data) | ||||||||||||||
Gas sales | $ | 111.9 | $ | 215.1 | $ | 233.9 | $ | 437.6 | |||||||
Oil sales | 250.4 | 358.8 | 429.2 | 647.5 | |||||||||||
NGL sales | 26.1 | 65.0 | 45.2 | 128.2 | |||||||||||
Other revenue | 5.2 | (0.8 | ) | 9.6 | 1.7 | ||||||||||
Purchased gas and oil sales | 215.0 | 249.1 | 382.3 | 489.7 | |||||||||||
Total Revenues | 608.6 | 887.2 | 1,100.2 | 1,704.7 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Purchased gas and oil expense | 217.2 | 249.2 | 386.6 | 487.1 | |||||||||||
Lease operating expense | 57.1 | 59.5 | 118.9 | 115.9 | |||||||||||
Gas, oil and NGL transportation and other handling costs | 73.0 | 67.5 | 138.1 | 127.4 | |||||||||||
Gathering and other expense | 1.4 | 1.8 | 3.1 | 3.4 | |||||||||||
General and administrative | 51.3 | 52.3 | 98.7 | 97.6 | |||||||||||
Production and property taxes | 32.7 | 53.5 | 60.5 | 101.4 | |||||||||||
Depreciation, depletion and amortization | 215.8 | 235.2 | 411.2 | 461.1 | |||||||||||
Exploration expenses | 0.8 | 1.7 | 1.9 | 3.9 | |||||||||||
Impairment | 0.5 | 1.5 | 20.5 | 3.5 | |||||||||||
Total Operating Expenses | 649.8 | 722.2 | 1,239.5 | 1,401.3 | |||||||||||
Net gain (loss) from asset sales | 24.5 | (200.9 | ) | (6.0 | ) | (198.5 | ) | ||||||||
OPERATING INCOME (LOSS) | (16.7 | ) | (35.9 | ) | (145.3 | ) | 104.9 | ||||||||
Realized and unrealized gains (losses) on derivative contracts | (66.0 | ) | (88.0 | ) | 14.9 | (168.9 | ) | ||||||||
Interest and other income | 3.8 | 0.8 | 1.2 | 3.7 | |||||||||||
Income from unconsolidated affiliates | — | 0.1 | — | 0.1 | |||||||||||
Interest expense | (36.2 | ) | (45.0 | ) | (73.0 | ) | (86.9 | ) | |||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (115.1 | ) | (168.0 | ) | (202.2 | ) | (147.1 | ) | |||||||
Income tax (provision) benefit | 38.8 | 61.9 | 70.3 | 53.7 | |||||||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (76.3 | ) | (106.1 | ) | (131.9 | ) | (93.4 | ) | |||||||
Net income from discontinued operations, net of income tax | — | 13.8 | — | 40.8 | |||||||||||
NET INCOME (LOSS) | $ | (76.3 | ) | $ | (92.3 | ) | $ | (131.9 | ) | $ | (52.6 | ) | |||
Earnings (Loss) Per Common Share | |||||||||||||||
Basic from continuing operations | $ | (0.43 | ) | $ | (0.59 | ) | $ | (0.75 | ) | $ | (0.52 | ) | |||
Basic from discontinued operations | — | 0.08 | — | 0.23 | |||||||||||
Basic total | $ | (0.43 | ) | $ | (0.51 | ) | $ | (0.75 | ) | $ | (0.29 | ) | |||
Diluted from continuing operations | $ | (0.43 | ) | $ | (0.59 | ) | $ | (0.75 | ) | $ | (0.52 | ) | |||
Diluted from discontinued operations | — | 0.08 | — | 0.23 | |||||||||||
Diluted total | $ | (0.43 | ) | $ | (0.51 | ) | $ | (0.75 | ) | $ | (0.29 | ) | |||
Weighted-average common shares outstanding | |||||||||||||||
Used in basic calculation | 176.7 | 180.1 | 176.4 | 179.9 | |||||||||||
Used in diluted calculation | 176.7 | 180.1 | 176.4 | 179.9 | |||||||||||
Dividends per common share | $ | 0.02 | $ | 0.02 | $ | 0.04 | $ | 0.04 | |||||||
8
QEP RESOURCES, INC. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) | |||||||
June 30, 2015 | December 31, 2014 | ||||||
ASSETS | (in millions) | ||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 445.6 | $ | 1,160.1 | |||
Accounts receivable, net | 330.8 | 441.9 | |||||
Income taxes receivable | 55.7 | — | |||||
Fair value of derivative contracts | 163.6 | 339.0 | |||||
Gas, oil and NGL inventories, at lower of average cost or market | 10.4 | 13.7 | |||||
Prepaid expenses and other | 38.0 | 46.8 | |||||
Total Current Assets | 1,044.1 | 2,001.5 | |||||
Property, Plant and Equipment (successful efforts method for oil and gas properties) | |||||||
Proved properties | 12,686.4 | 12,278.7 | |||||
Unproved properties | 814.1 | 825.2 | |||||
Marketing and other | 298.1 | 293.8 | |||||
Material and supplies | 41.6 | 54.3 | |||||
Total Property, Plant and Equipment | 13,840.2 | 13,452.0 | |||||
Less Accumulated Depreciation, Depletion and Amortization | |||||||
Exploration and production | 6,415.1 | 6,153.0 | |||||
Marketing and other | 77.7 | 67.8 | |||||
Total Accumulated Depreciation, Depletion and Amortization | 6,492.8 | 6,220.8 | |||||
Net Property, Plant and Equipment | 7,347.4 | 7,231.2 | |||||
Fair value of derivative contracts | 6.1 | 9.9 | |||||
Other noncurrent assets | 35.5 | 44.2 | |||||
TOTAL ASSETS | $ | 8,433.1 | $ | 9,286.8 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Checks outstanding in excess of cash balances | $ | 7.4 | $ | 54.7 | |||
Accounts payable and accrued expenses | 463.3 | 575.4 | |||||
Income taxes payable | — | 532.1 | |||||
Production and property taxes | 59.3 | 61.7 | |||||
Interest payable | 36.4 | 36.4 | |||||
Fair value of derivative contracts | 1.0 | — | |||||
Deferred income taxes | 36.9 | 84.5 | |||||
Total Current Liabilities | 604.3 | 1,344.8 | |||||
Long-term debt | 2,218.5 | 2,218.1 | |||||
Deferred income taxes | 1,381.4 | 1,362.7 | |||||
Asset retirement obligations | 184.9 | 193.8 | |||||
Fair value of derivative contracts | 1.6 | — | |||||
Other long-term liabilities | 94.7 | 92.1 | |||||
Commitments and contingencies | |||||||
EQUITY | |||||||
Common stock - par value $0.01 per share; 500.0 million shares authorized; 177.0 million and 176.2 million shares issued, respectively | 1.8 | 1.8 | |||||
Treasury stock - 0.4 million and 0.8 million shares, respectively | (11.5 | ) | (25.4 | ) | |||
Additional paid-in capital | 538.1 | 535.3 | |||||
Retained earnings | 3,442.8 | 3,587.9 | |||||
Accumulated other comprehensive income (loss) | (23.5 | ) | (24.3 | ) | |||
Total Common Shareholders' Equity | 3,947.7 | 4,075.3 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 8,433.1 | $ | 9,286.8 | |||
9
QEP RESOURCES, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) | |||||||
Six Months Ended | |||||||
June 30, | |||||||
2015 | 2014 | ||||||
(in millions) | |||||||
OPERATING ACTIVITIES | |||||||
Net income (loss) | $ | (131.9 | ) | $ | (52.6 | ) | |
Net income attributable to noncontrolling interests | — | 10.8 | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 411.2 | 489.9 | |||||
Deferred income taxes | (29.4 | ) | 15.8 | ||||
Impairment | 20.5 | 3.5 | |||||
Share-based compensation | 15.6 | 14.6 | |||||
Pension curtailment loss | 11.2 | — | |||||
Amortization of debt issuance costs and discounts | 3.3 | 3.4 | |||||
Net (gain) loss from asset sales | 6.0 | 198.6 | |||||
Income from unconsolidated affiliates | — | (3.4 | ) | ||||
Distributions from unconsolidated affiliates and other | — | 6.3 | |||||
Unrealized (gains) losses on derivative contracts | 181.8 | 98.2 | |||||
Changes in operating assets and liabilities | (490.9 | ) | 75.2 | ||||
Net Cash (Used in) Provided by Operating Activities | (2.6 | ) | 860.3 | ||||
INVESTING ACTIVITIES | |||||||
Property acquisitions | — | (949.4 | ) | ||||
Property, plant and equipment, including dry exploratory well expense | (651.3 | ) | (779.0 | ) | |||
Proceeds from (payments for) disposition of assets | (2.4 | ) | 706.3 | ||||
Acquisition deposit held in escrow | — | 50.0 | |||||
Net Cash Used in Investing Activities | (653.7 | ) | (972.1 | ) | |||
FINANCING ACTIVITIES | |||||||
Checks outstanding in excess of cash balances | (47.3 | ) | (85.2 | ) | |||
Long-term debt issued | — | 300.0 | |||||
Long-term debt issuance costs paid | — | (1.1 | ) | ||||
Proceeds from credit facility | — | 3,151.0 | |||||
Repayments of credit facility | — | (2,538.0 | ) | ||||
Treasury stock repurchases | (1.9 | ) | (5.5 | ) | |||
Other capital contributions | (0.1 | ) | 4.1 | ||||
Dividends paid | (7.1 | ) | (7.3 | ) | |||
Excess tax (provision) benefit on share-based compensation | (1.8 | ) | (0.6 | ) | |||
Distribution to noncontrolling interest | — | (15.2 | ) | ||||
Net Cash (Used in) Provided by Financing Activities | (58.2 | ) | 802.2 | ||||
Change in cash and cash equivalents | (714.5 | ) | 690.4 | ||||
Beginning cash and cash equivalents | 1,160.1 | 11.9 | |||||
Ending cash and cash equivalents | $ | 445.6 | $ | 702.3 | |||
10
QEP Energy - Production by Region | |||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||
June 30, | June 30, | ||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
(in Bcfe) | (in Bcfe) | ||||||||||||||||
Northern Region | |||||||||||||||||
Pinedale | 24.9 | 25.3 | (2 | )% | 46.7 | 46.2 | 1 | % | |||||||||
Williston Basin | 28.6 | 19.4 | 47 | % | 54.0 | 36.2 | 49 | % | |||||||||
Uinta Basin | 7.3 | 6.8 | 7 | % | 14.2 | 13.0 | 9 | % | |||||||||
Other Northern | 2.4 | 3.5 | (31 | )% | 5.1 | 6.0 | (15 | )% | |||||||||
Total Northern Region | 63.2 | 55.0 | 15 | % | 120.0 | 101.4 | 18 | % | |||||||||
Southern Region | |||||||||||||||||
Haynesville/Cotton Valley | 10.4 | 13.1 | (21 | )% | 22.1 | 27.5 | (20 | )% | |||||||||
Permian Basin | 6.2 | 4.2 | 48 | % | 11.1 | 5.4 | 106 | % | |||||||||
Midcontinent | 1.1 | 11.6 | (91 | )% | 2.9 | 23.3 | (88 | )% | |||||||||
Total Southern Region | 17.7 | 28.9 | (39 | )% | 36.1 | 56.2 | (36 | )% | |||||||||
Total production | 80.9 | 83.9 | (4 | )% | 156.1 | 157.6 | (1 | )% | |||||||||
QEP Energy - Total Production | |||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||
June 30, | June 30, | ||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
QEP Energy Production Volumes | |||||||||||||||||
Gas (Bcf) | 44.5 | 48.6 | (8 | )% | 87.1 | 93.1 | (6 | )% | |||||||||
Oil (Mbbl) | 4,875.9 | 3,980.6 | 22 | % | 9,357.3 | 7,292.6 | 28 | % | |||||||||
NGL (Mbbl) | 1,198.0 | 1,886.0 | (36 | )% | 2,145.4 | 3,454.3 | (38 | )% | |||||||||
Total production (Bcfe) | 80.9 | 83.9 | (4 | )% | 156.1 | 157.6 | (1 | )% | |||||||||
Average daily production (MMcfe) | 889.0 | 922.0 | (4 | )% | 862.4 | 870.7 | (1 | )% | |||||||||
11
QEP Energy - Prices | |||||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
Gas (per Mcf) | |||||||||||||||||||||
Average field-level price | $ | 2.52 | $ | 4.42 | $ | 2.69 | $ | 4.70 | |||||||||||||
Commodity derivative impact | 0.63 | (0.17 | ) | 0.53 | (0.31 | ) | |||||||||||||||
Net realized price | $ | 3.15 | $ | 4.25 | (26 | )% | $ | 3.22 | $ | 4.39 | (27 | )% | |||||||||
Oil (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 51.34 | $ | 90.06 | $ | 45.86 | $ | 88.74 | |||||||||||||
Commodity derivative impact | 13.24 | (6.29 | ) | 15.88 | (5.21 | ) | |||||||||||||||
Net realized price | $ | 64.58 | $ | 83.77 | (23 | )% | $ | 61.74 | $ | 83.53 | (26 | )% | |||||||||
NGL (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 21.68 | $ | 34.34 | $ | 20.98 | $ | 37.03 | |||||||||||||
Commodity derivative impact | — | — | — | — | |||||||||||||||||
Net realized price | $ | 21.68 | $ | 34.34 | (37 | )% | $ | 20.98 | $ | 37.03 | (43 | )% | |||||||||
Average net equivalent price (per Mcfe) | |||||||||||||||||||||
Average field-level price | $ | 4.80 | $ | 7.62 | $ | 4.54 | $ | 7.70 | |||||||||||||
Commodity derivative impact | 1.14 | (0.40 | ) | 1.25 | (0.42 | ) | |||||||||||||||
Net realized price | $ | 5.94 | $ | 7.22 | (18 | )% | $ | 5.79 | $ | 7.28 | (20 | )% | |||||||||
QEP Energy - Operating Expenses | |||||||||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||||||||
June 30, | June 30, | ||||||||||||||||||||
2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
(per Mcfe) | |||||||||||||||||||||
Depreciation, depletion and amortization | $ | 2.64 | $ | 2.77 | (5 | )% | $ | 2.60 | $ | 2.89 | (10 | )% | |||||||||
Lease operating expense | 0.71 | 0.71 | — | % | 0.76 | 0.74 | 3 | % | |||||||||||||
Gas, oil and NGL transport & other handling costs | 0.93 | 0.86 | 8 | % | 0.91 | 0.87 | 5 | % | |||||||||||||
Production and property taxes | 0.38 | 0.63 | (40 | )% | 0.38 | 0.64 | (41 | )% | |||||||||||||
Total Operating Expenses | $ | 4.66 | $ | 4.97 | (6 | )% | $ | 4.65 | $ | 5.14 | (10 | )% | |||||||||
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 June 30, 2015 | (in millions) | ||||||||||||||||||
Net income (loss) | $ | (83.4 | ) | $ | 7.1 | $ | (76.3 | ) | $ | — | $ | (76.3 | ) | ||||||
Unrealized (gains) losses on derivative contracts | 158.2 | 0.1 | 158.3 | — | 158.3 | ||||||||||||||
Net (gain) loss from asset sales | (26.5 | ) | 2.0 | (24.5 | ) | — | (24.5 | ) | |||||||||||
Interest and other (income) expense | (3.1 | ) | (0.7 | ) | (3.8 | ) | — | (3.8 | ) | ||||||||||
Income tax provision (benefit) | (42.4 | ) | 3.6 | (38.8 | ) | — | (38.8 | ) | |||||||||||
Interest expense (income) | 52.6 | (16.4 | ) | 36.2 | — | 36.2 | |||||||||||||
Pension curtailment loss (2) | 11.0 | 0.2 | 11.2 | — | 11.2 | ||||||||||||||
Depreciation, depletion and amortization | 213.2 | 2.6 | 215.8 | — | 215.8 | ||||||||||||||
Impairment | 0.5 | — | 0.5 | — | 0.5 | ||||||||||||||
Exploration expenses | 0.8 | — | 0.8 | — | 0.8 | ||||||||||||||
Adjusted EBITDA | $ | 280.9 | $ | (1.5 | ) | $ | 279.4 | $ | — | $ | 279.4 | ||||||||
Three Months Ended June 30, 2014 | |||||||||||||||||||
Net income (loss) | $ | (110.4 | ) | $ | 4.3 | $ | (106.1 | ) | $ | 13.8 | $ | (92.3 | ) | ||||||
Unrealized (gains) losses on derivative contracts | 51.8 | 0.9 | 52.7 | — | 52.7 | ||||||||||||||
Net (gain) loss from asset sales | 200.8 | 0.1 | 200.9 | 0.1 | 201.0 | ||||||||||||||
Interest and other (income) expense | (0.6 | ) | (0.2 | ) | (0.8 | ) | — | (0.8 | ) | ||||||||||
Income tax provision (benefit) | (67.2 | ) | 5.3 | (61.9 | ) | 7.7 | (54.2 | ) | |||||||||||
Interest expense (income) (3) | 56.6 | (11.6 | ) | 45.0 | 0.5 | 45.5 | |||||||||||||
Depreciation, depletion and amortization (4) | 232.3 | 2.9 | 235.2 | 10.5 | 245.7 | ||||||||||||||
Impairment | 1.5 | — | 1.5 | — | 1.5 | ||||||||||||||
Exploration expenses | 1.7 | — | 1.7 | — | 1.7 | ||||||||||||||
Adjusted EBITDA | $ | 366.5 | $ | 1.7 | $ | 368.2 | $ | 32.6 | $ | 400.8 | |||||||||
_________________________
(1) | Includes intercompany eliminations. |
(2) | The pension curtailment loss is a non-cash loss that was incurred during the three months ended June 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 $0.2 million during the three months ended June 30, 2014, of interest expense attributable to QEP Midstream Partners, LP (QEP Midstream). |
(4) | Excludes noncontrolling interest's share of $4.0 million during the three months ended June 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 | |||||||||||||||
Six Months Ended June 30, 2015 | (in millions) | ||||||||||||||||||
Net income (loss) | $ | (142.7 | ) | $ | 10.8 | $ | (131.9 | ) | $ | — | $ | (131.9 | ) | ||||||
Unrealized (gains) losses on derivative contracts | 179.9 | 1.9 | 181.8 | — | 181.8 | ||||||||||||||
Net loss from asset sales | 1.3 | 4.7 | 6.0 | — | 6.0 | ||||||||||||||
Interest and other (income) expense | 0.4 | (1.6 | ) | (1.2 | ) | — | (1.2 | ) | |||||||||||
Income tax provision (benefit) | (76.0 | ) | 5.7 | (70.3 | ) | — | (70.3 | ) | |||||||||||
Interest expense (income) | 99.8 | (26.8 | ) | 73.0 | — | 73.0 | |||||||||||||
Pension curtailment loss (2) | 11.0 | 0.2 | 11.2 | — | 11.2 | ||||||||||||||
Depreciation, depletion and amortization | 405.9 | 5.3 | 411.2 | — | 411.2 | ||||||||||||||
Impairment | 20.5 | — | 20.5 | — | 20.5 | ||||||||||||||
Exploration expenses | 1.9 | — | 1.9 | — | 1.9 | ||||||||||||||
Adjusted EBITDA | $ | 502.0 | $ | 0.2 | $ | 502.2 | $ | — | $ | 502.2 | |||||||||
Six Months Ended June 30, 2014 | |||||||||||||||||||
Net income (loss) | $ | (105.3 | ) | $ | 11.9 | $ | (93.4 | ) | 40.8 | $ | (52.6 | ) | |||||||
Unrealized (gains) losses on derivative contracts | 97.0 | 1.2 | 98.2 | — | 98.2 | ||||||||||||||
Net (gain) loss from asset sales | 198.4 | 0.1 | 198.5 | 0.1 | 198.6 | ||||||||||||||
Interest and other (income) expense | (3.5 | ) | (0.2 | ) | (3.7 | ) | — | (3.7 | ) | ||||||||||
Income tax provision (benefit) | (60.1 | ) | 6.4 | (53.7 | ) | 22.9 | (30.8 | ) | |||||||||||
Interest expense (income) (3) | 105.5 | (18.6 | ) | 86.9 | 0.9 | 87.8 | |||||||||||||
Depreciation, depletion and amortization (4) | 455.7 | 5.4 | 461.1 | 21.1 | 482.2 | ||||||||||||||
Impairment | 3.5 | — | 3.5 | — | 3.5 | ||||||||||||||
Exploration expenses | 3.9 | — | 3.9 | — | 3.9 | ||||||||||||||
Adjusted EBITDA | $ | 695.1 | $ | 6.2 | $ | 701.3 | $ | 85.8 | $ | 787.1 | |||||||||
_________________________
(1) | Includes intercompany eliminations. |
(2) | The pension curtailment loss is a non-cash loss that was incurred during the three months ended June 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 $0.4 million during the six months ended June 30, 2014, of interest expense attributable to QEP Midstream. |
(4) | Excludes noncontrolling interest's share of $7.7 million during the three months June 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 | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||
(in millions, except earnings per share) | |||||||||||||||
Net income (loss) | $ | (76.3 | ) | $ | (92.3 | ) | $ | (131.9 | ) | $ | (52.6 | ) | |||
Adjustments to net income | |||||||||||||||
Net (gain) loss from asset sales from continuing operations | (24.5 | ) | 200.9 | 6.0 | 198.5 | ||||||||||
Income taxes on net (gain) loss from asset sales from continuing operations | 9.0 | (74.7 | ) | (2.2 | ) | (73.8 | ) | ||||||||
Unrealized (gains) losses on derivative contracts from continuing operations | 158.3 | 52.7 | 181.8 | 98.2 | |||||||||||
Income taxes on unrealized (gains) losses on derivative contracts from continuing operations | (57.9 | ) | (19.6 | ) | (66.5 | ) | (36.5 | ) | |||||||
Pension curtailment loss | 11.2 | — | 11.2 | — | |||||||||||
Income taxes on pension curtailment loss | (4.1 | ) | — | (4.1 | ) | — | |||||||||
Impairment charges from continuing operations | 0.5 | 1.5 | 20.5 | 3.5 | |||||||||||
Income taxes impairment charges from continuing operations | (0.2 | ) | (0.6 | ) | (7.5 | ) | (1.3 | ) | |||||||
Total after-tax adjustments to net income | 92.3 | 160.2 | 139.2 | 188.6 | |||||||||||
Adjusted net income | 16.0 | 67.9 | 7.3 | 136.0 | |||||||||||
Net income from discontinued operations, net of income tax | — | (13.8 | ) | — | (40.8 | ) | |||||||||
Adjusted net income (loss) from continuing operations | $ | 16.0 | $ | 54.1 | $ | 7.3 | $ | 95.2 | |||||||
Earnings (Loss) per Common Share | |||||||||||||||
Diluted earnings per share | $ | (0.43 | ) | $ | (0.51 | ) | $ | (0.75 | ) | $ | (0.29 | ) | |||
Diluted after-tax adjustments to net income per share | 0.52 | 0.89 | 0.79 | 1.05 | |||||||||||
Diluted adjusted net income (loss) per share | 0.09 | 0.38 | 0.04 | 0.76 | |||||||||||
Diluted from discontinued operations | — | (0.08 | ) | — | (0.23 | ) | |||||||||
Diluted adjusted net income (loss) from continuing operations per share | $ | 0.09 | $ | 0.30 | $ | 0.04 | $ | 0.53 | |||||||
Weighted-average common shares outstanding | |||||||||||||||
Diluted | 176.7 | 180.5 | 176.4 | 180.2 | |||||||||||
Non-GAAP reconciliation of weighted-average common shares outstanding diluted (1) | |||||||||||||||
Weighted-average common shares outstanding used in GAAP calculation | 180.1 | 179.9 | |||||||||||||
Potential number of shares issuable upon exercise of in-the-money stock options under the long-term stock incentive plan | 0.4 | 0.3 | |||||||||||||
Weighted-average diluted common shares outstanding used in Non-GAAP calculation | 180.5 | 180.2 | |||||||||||||
(1) | The three and six months ended June 30, 2014, diluted common shares outstanding for purposes of calculating Diluted Adjusted Net Income per share include potential increases in shares that could result from the exercise of in-the-money stock options. These potential shares are excluded for the three and six months ended June 30, 2014, in calculating earnings-per-share for GAAP purposes, because the effect is antidilutive due to the Company's net loss for GAAP purposes. |
15
The following tables present open 2015 derivative positions as of July 29, 2015:
QEP Energy Commodity Derivative Swap Positions
Year | Index | Total Volumes | Average Swap Price Per Unit | ||||||
(in millions) | |||||||||
Gas sales | (MMBtu) | ||||||||
2015 | NYMEX HH | 35.0 | $ | 3.48 | |||||
2015 | IFNPCR | 23.9 | $ | 3.55 | |||||
2016 | NYMEX HH | 18.3 | $ | 3.24 | |||||
2016 | IFNPCR | 32.9 | $ | 2.92 | |||||
Oil Sales | (bbls) | ||||||||
2015 | NYMEX WTI | 5.2 | $ | 82.09 | |||||
2015 | ICE Brent | 0.2 | $ | 104.95 | |||||
2016 | NYMEX WTI | 3.3 | $ | 65.43 | |||||
QEP Energy Crude 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 | Index Less Differential | Total Volumes | Weighted Average Differential | |||||||
(in millions) | |||||||||||
(MMBtu) | ($/MMBtu) | ||||||||||
2015 | NYMEX HH | IFNPCR | 22.1 | $ | (0.28 | ) | |||||
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 | $ | 3.25 | ||||||
2016 | SWAP | IFNPCR | 2.0 | $ | 3.17 | ||||||
Gas purchases | (MMBtu) | ||||||||||
2015 | SWAP | IFNPCR | 1.1 | $ | 2.77 | ||||||
16