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 30, 2012
(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 500, 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 30, 2012, QEP Resources, Inc. (the “Registrant”) issued a press release to report the results of operations for the period ended September 30, 2012, and to provide an update of 2012 year to date operations and remaining 2012 and 2013 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, 2012, includes non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company's performance, financial position, or cash flows 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 30, 2012, 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 31, 2012
/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 30, 2012, by QEP Resources, Inc.
Exhibit 99.1
News ReleaseInvestors: Greg Bensen
Director, Investor Relations
303-405-6665
Media: Noel Ryan
Director, Corporate Communications
303-405-6655
QEP RESOURCES REPORTS THIRD QUARTER 2012 FINANCIAL AND OPERATIONAL RESULTS
DENVER — October 30, 2012// QEP Resources, Inc. (NYSE: QEP), reported Adjusted EBITDA (a non-GAAP measure) for the third quarter 2012 of $328.7 million, compared to $353.7 million in the third quarter 2011, a 7% decrease. QEP Resources reported a net loss during the third quarter 2012 of $3.1 million, or $0.02 per diluted share, compared to net income of $101.5 million, or $0.57 per diluted share, in the third quarter 2011. 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, costs associated with the early extinguishment of debt and non-cash price-related impairment charges. Excluding these items, the Company’s Adjusted Net Income (a non-GAAP measure) was $32.7 million, or $0.19 per diluted share, in the third quarter 2012 compared to $83.6 million, or $0.47 per diluted share, in the third quarter 2011. The lower Adjusted Net Income is primarily due to lower natural gas and NGL prices in the third quarter 2012 compared to 2011. A reconciliation of Adjusted EBITDA and Adjusted Net Income to net income is provided within the financial tables of this release.
Third Quarter 2012 Highlights
▪ | On September 27, 2012, QEP Energy completed the previously announced acquisition of approximately 27,600 net acres and 72 gross producing wells in the Williston Basin for an aggregate adjusted purchase price of approximately $1.4 billion, subject to post closing adjustments. |
▪ | QEP Energy reported record net production of 81.5 Bcfe in the third quarter 2012, an increase of 15% when compared to the prior-year period. The growth was driven primarily by increased crude oil and NGL production. |
▪ | QEP Energy delivered a 56% increase in crude oil production and a 55% increase in NGL production in the third quarter 2012, when compared to the prior-year period. |
▪ | QEP Field Services’ (Field Services) NGL sales volumes increased by 3%, gathering volumes by 2% and total fee-based processing volumes by 2% in the third quarter 2012 compared to 2011. |
“QEP achieved a number of significant accomplishments in the third quarter of 2012,” said Chuck Stanley, Chairman, President and CEO of QEP Resources. “QEP Energy's third quarter production increased to a new record, up 15% compared to last year. The record production was driven by an increase in crude oil and NGL volumes that were both up over 50% from a year ago. Crude oil and NGL represented 21% of QEP Energy's total production volumes in the third quarter, up from 15% a year ago."
Crude oil and NGL revenues increased to 48% of field-level revenues in the third quarter of 2012 from 32% in the third quarter of 2011.
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"With the successful completion of our previously-announced Bakken/Three Forks property acquisition in North Dakota's Williston Basin, combined with an aggressive capital allocation focus on higher-return crude oil and liquids-rich gas plays, we now have a solid platform to drive continued growth of crude oil production next year and beyond," continued Stanley. "At QEP Field Services, processing, gathering and NGL sales volumes all increased, but financial performance was adversely impacted by lower NGL sales prices that compressed keep-whole gas processing margins. As we described in our August conference call announcing the North Dakota property acquisition, we continue to examine various deleveraging options and are pleased with our progress toward determining a course of action.”
QEP Financial Results Summary
Adjusted EBITDA by Subsidiary | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||
(in millions) | |||||||||||||||||||||
QEP Energy | $ | 262.8 | $ | 267.3 | (2 | )% | $ | 789.3 | $ | 757.0 | 4 | % | |||||||||
QEP Field Services | 68.0 | 84.8 | (20 | )% | 223.8 | 233.1 | (4 | )% | |||||||||||||
QEP Marketing and other | (2.1 | ) | 1.6 | (231 | )% | (0.2 | ) | 6.0 | (103 | )% | |||||||||||
Adjusted EBITDA(1) | $ | 328.7 | $ | 353.7 | (7 | )% | $ | 1,012.9 | $ | 996.1 | 2 | % | |||||||||
(1) See attached schedule for a reconciliation of Adjusted EBITDA to net income. | |||||||||||||||||||||
QEP Energy
▪ | Natural gas, crude oil and NGL net production increased to 81.5 Bcfe in the third quarter 2012 compared to 70.7 Bcfe in 2011. Crude oil production increased 56%, NGL production increased 55%, and natural gas production increased 8% in the third quarter 2012 compared to 2011. |
▪ | Adjusted EBITDA decreased 2% compared to the third quarter 2011, driven by a 16% decrease in the net realized price for natural gas and 23% decrease in the net realized price for NGL, mostly offset by a 15% increase in production. |
▪ | Crude oil and NGL revenues increased 39% compared to the third quarter 2011 and represented approximately 48% of field-level production revenues. |
▪ | Capital investment (on an accrual basis) in the first nine months of 2012 was $2.4 billion. Investments included $990.7 million in drilling, completion and other expenditures (including $0.1 million of dry hole exploration expense) and $1.4 billion in property acquisitions. |
▪ | The slides for the third quarter 2012 with maps and other supporting materials referred to in this release are posted on the Company’s website www.qepres.com. |
QEP Field Services
▪ | QEP Field Services’ Adjusted EBITDA decreased 20% in the third quarter 2012 compared to the prior-year period, primarily due to a 32% decrease in net realized NGL prices, and a 52% decrease in other gathering revenue related to the elimination of a third-party interruptible processing agreement for certain gas volumes in the Northern Region, partially offset by a 3% increase in NGL sale volumes. |
▪ | Capital investment (on an accrual basis) for the first nine months of 2012 totaled $141.2 million. |
QEP Resources
▪ | The Company issued $650 million of 5.25% Senior Notes due May 2023. The proceeds from the Senior Notes were used to fund a portion of the third quarter property acquisition in North Dakota. |
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QEP 2012 & 2013 Guidance
QEP Resources has revised its full-year 2012 guidance for commodity prices and provided initial 2013 guidance. The Company’s guidance incorporates commodity price derivative positions in place on the date of this release and other assumptions summarized in the table below:
Guidance and Assumptions | |||||
2012 | 2013 | ||||
Current Forecast | Previous Forecast | Current Forecast | |||
(in millions) | |||||
QEP Resources Adjusted EBITDA(1) | $1,400 - $1,425 | $1,400 - $1,450 | $1,525 - $1,675 | ||
QEP Energy capital investment(2) | $1,320 - $1,370 | $1,320 - $1,370 | $1,480 - $1,630 | ||
QEP Field Services capital investment | $170 | $170 | $120 | ||
QEP Marketing capital investment | $1 | $1 | $0 | ||
Corporate capital investment | $9 | $9 | $25 | ||
Total QEP Resources capital investment(2) | $1,500 - $1,550 | $1,500 - $1,550 | $1,625 - $1,775 | ||
QEP Energy production - Bcfe | 315 - 320 | 310 - 315 | 325 - 330 | ||
NYMEX gas price per MMBtu(3) | $3.50 - $4.00 | $2.25 - $3.25 | $3.50 - $4.50 | ||
NYMEX crude oil price per bbl(3) | $85.00 - $95.00 | $85.00 - $95.00 | $85.00 - $95.00 | ||
NYMEX /Rockies basis differential per MMBtu(3) | $0.15 - $0.10 | $0.20 - $0.15 | $0.15 - $0.10 | ||
NYMEX/Midcontinent basis differential per MMBtu(3) | $0.20 - $0.15 | $0.15 - $0.10 | $0.20 - $0.15 | ||
(1) Due to the forward-looking nature of this non-GAAP financial measure for future periods, information to reconcile it to the most directly comparable GAAP financial measure is not available at this time as management is unable to project special items or mark-to-market adjustments for future periods. | |||||
(2) Excludes $1.4 billion cost of the 2012 North Dakota property acquisition. | |||||
(3) For remaining 2012 and 2013 forecasted volumes that are not protected by commodity price derivative contracts. See attached schedule at the end of this release for summary of Commodity Derivative Positions in place on the date of this release. | |||||
“Following the completion of our North Dakota property acquisition, we expect 2013 will be a year of dramatic change in QEP's production mix,” continued Stanley. “With over half of our 2013 capital investment going toward developing the Bakken and Three Forks formations, we expect our crude oil and NGL production to increase approximately 70% and 33%, respectively, over 2012 levels and represent approximately 31% of total 2013 forecast production. Even with this significant increase in liquids production, we expect modest overall production growth in 2013. Our discipline in capital allocation will lead to a minimal level of spending in the Haynesville causing production in that area to decline approximately 30% year-over-year in 2013, negatively impacting both QEP Energy and QEP Field Services. While the increase in natural gas prices seen in the futures curve is expected to be a positive development for QEP Energy, the associated increased shrink cost will have a negative impact on Field Services' profitability. Despite the expected startup of the Iron Horse II plant and the expansion of the fractionator at Blacks Fork, we anticipate Field Services operating income will decline in 2013. While we expect modest overall production growth and market headwinds in Field Services, higher margin oil growth is expected to propel mid-teens growth in Adjusted EBITDA for QEP Resources in 2013; furthermore, we expect this trend to continue into 2014, and at current forward prices for natural gas, oil and NGL's, we anticipate EBITDA could grow approximately 20% in 2014 from the midpoint of 2013 guidance on production growth of approximately 10%. We estimate 2014 oil and NGL production will represent approximately 41% of total 2014 forecast production, almost double the 2012 percentage.”
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Operations Summary
QEP Energy
Williston Basin: Continued growth in crude oil production on 117,000 acre Bakken/Three Forks leasehold
On September 27, 2012, QEP closed on the previously announced acquisition of 27,600 net acres of producing leasehold in McKenzie and Williams Counties, North Dakota. Going forward, this area will be referred to as South Antelope. Including the recently acquired property, at the end of the third quarter the Company operated 73 producing wells, including 36 Bakken wells, 36 Three Forks Formation wells and 1 dual lateral producing from both the Bakken and Three Forks Formations. In addition, the Company has a working interest in 177 producing outside-operated wells. During the quarter, the company completed and turned to sales five operated wells in which QEP owned an average working interest of 99%.
During the third quarter 2012, and excluding the acquired property, QEP's Bakken/Three Forks net production averaged 6,748 Boe/day. The net production from the acquired properties averaged an additional approximate 8,600 Boe/day at the time of closing.
At the end of the third quarter, QEP had 12 operated wells being drilled (including seven wells at intermediate casing) and 9 QEP-operated wells that had been drilled to total depth, cased and were waiting on completion. QEP has an average 83% working interest in these operated wells that were drilling or waiting on completion. Completion activities for all wells drilled from a pad (or a well-pod on a pad) are delayed until all wells have been drilled and cased. At the end of the third quarter, the Company also had interests in 15 outside-operated wells being drilled and 17 outside-operated wells that were drilled and cased and waiting on completion. The Company's working interest in these outside-operated wells averages approximately 4%.
The Company currently has five rigs operating in the Bakken/Three Forks play (two in the South Antelope Area and three within the Fort Berthold Reservation). QEP currently estimates that completed well costs for a typical QEP-operated long-lateral Bakken or Three Forks well will average approximately $11 million for the balance of 2012.
Slides 5-7 depict QEP's acreage and activity in the Bakken/Three Forks play.
Pinedale Anticline: Approximately 100 new well completions expected for the full-year 2012
During the third quarter 2012, the Company's net production at Pinedale averaged 304 MMcfed, of which 22% was oil and NGL.
Drilling and completion efficiencies have allowed QEP to maintain industry-leading average gross completed well costs of approximately $4.1 million per well at Pinedale. Average drill time from spud to total depth during the first nine months of 2012 was 13.2 days. A new QEP drill time record of 8.6 days was set during the third quarter 2012, beating the previous record by more than a day.
QEP suspends Pinedale completion operations during the coldest months of the winter, generally from December to mid-March. In 2012, completion operations resumed in early March, and through the end of the third quarter QEP had completed and turned to sales 86 new wells (average working interest of 73%) and there were 44 wells that have been drilled and cased awaiting completion. The Company now expects to complete a total of approximately 100 wells during 2012.
Please refer to slide 8 for additional details on the Company's Pinedale operations.
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Uinta Basin: Continued development drilling in the liquids-rich Lower Mesaverde Play
During the third quarter 2012, Uinta Basin production averaged 70 MMcfed of which 25 MMcfed was from the Lower Mesaverde play. QEP has two operated rigs drilling vertical wells targeting liquids-rich gas in stacked discontinuous sands in the Lower Mesaverde Formation.
QEP is continuing construction of two “Pinedale-style” multi-well pads in the play and plans to initially drill 20-acre density development wells from an average of two pads per square mile. The pads and wellbore geometries will be designed to allow for future 10-acre density development wells. Average measured depth for a typical Lower Mesaverde well in the play is approximately 11,000 feet.
At the end of the third quarter, the Company had 49 producing wells in the play, 29 of which were completed during 2012. QEP intends to complete approximately 40 wells in the play during 2012. QEP has a 100% working interest in the prospective acreage within the Red Wash Unit.
QEP is also operating a third rig in the Uinta Basin that is drilling horizontal and vertical wells targeting multiple oil-bearing limestone and sandstone reservoirs within the lower Green River Formation, at an average drill depth of 5,500 feet. At the end of the third quarter, QEP had completed six (three vertical and three horizontal) of the 11 Company-operated oil wells planned for 2012 within the Uinta Basin. QEP will have an average working interest of 73% in the 2012 oil wells.
Slides 9 and 10 depict QEP's acreage and additional details of the Lower Mesaverde play.
Powder River Basin: QEP completes second and third operated Sussex Formation crude oil wells; additional well waiting on completion
In the Powder River Basin of Wyoming, QEP completed and turned to sales two Company-operated horizontal Sussex Formation oil wells during the third quarter. At the end of the third quarter, there was one Company-operated horizontal Sussex Formation well waiting on completion. In addition to the recent QEP-operated activity, the Company also has an average 22% working interest in two outside-operated horizontal Sussex Formation wells that have been on production for more than one year.
QEP currently estimates average gross completed well costs of approximately $6.5 to $7.0 million with estimated ultimate recoverable reserves of 450 to 525 Mboe for a typical horizontal Sussex well. QEP has approximately 40,000 net leasehold acres in the Spearhead Ranch area of the Powder River Basin and intends to drill additional wells targeting the Sussex Formation, as well as other zones, including the Shannon, Niobrara and Frontier formations.
Slide 11 shows QEP's acreage and activity in the Powder River Basin oil play.
Woodford “Cana”: Currently drilling 80-acre density development wells in the liquids-rich core of the play
During the third quarter 2012, QEP's net production from the Woodford “Cana” play averaged 45 MMcfed. At the end of the third quarter, QEP operated 29 producing horizontal Cana wells and had working interests in an additional 238 producing Cana wells that are operated by others.
During the third quarter, the Company participated in 17 additional horizontal Woodford “Cana” Shale completed wells operated by others in which QEP has working interests ranging from less than 1% to 51%.
QEP has two operated rigs currently drilling 80-acre horizontal development wells in which the Company has a 75% working interest. Also, there are eight wells in which QEP has a 100% working interest that have been drilled to total depth and cased and are scheduled for completion by the end of the fourth quarter.
Slide 12 depicts QEP's acreage and additional details on the Cana play.
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Granite Wash, Marmaton and Tonkawa: Horizontal development in the Texas Panhandle and Western Oklahoma
During the third quarter 2012, net production from the Texas Panhandle Granite Wash play (vertical and horizontal wells) averaged 41 MMcfed. As of the end of the third quarter, QEP had a working interest in a total of 89 producing horizontal Granite Wash/Atoka Wash wells.
During the third quarter, the Company completed one QEP-operated Missourian Kansas City Formation horizontal well in Wheeler County, Texas and participated in seven outside-operated Granite Wash wells in the Texas Panhandle. QEP will take over as Operator for production of three Kansas City “B” wells (51% working interest) from the company that drilled and completed the wells, referred to on slide 13 as well numbers 5, 6 and 7, which were completed in mid-September with an average peak 24-hour rate of 4,300 Boepd. One QEP-operated well in Wheeler County, Texas was drilling at the end of the third quarter.
During the third quarter, QEP completed four Marmaton oil wells with an average peak 24-hour rate of approximately 300 Boe/day. The Company has an average 91% working interest in the new wells. The Company also has an average 17% working interest in two outside-operated Tonkawa wells that were completed during the quarter with an average peak 24-hour rate of 422 Boe/day and an average 9% working interest in two outside-operated Tonkawa wells that were drilling.
See slide 13 for details on the Granite Wash play.
Haynesville: No operated drilling activity in the Haynesville Shale play of NW Louisiana
During the third quarter 2012, the Company's Haynesville net production averaged 261 MMcfed and Cotton Valley/Hosston net production averaged 42 MMcfed. In response to current natural gas prices, QEP released its last operated drilling rig in the Haynesville Shale play in early July of this year and has not completed any additional Company-operated Haynesville wells since April 2012. QEP has five operated wells drilled and cased (48% working interest) and currently plans to defer completion of these wells until 2013. The Company operates 123 producing wells in the play and has a working interest in 124 producing wells that are operated by others. The Company participated with a 1.5% working interest in one outside-operated Haynesville well that was being completed at the end of the third quarter. The Company also participated with an 11% working interest in a horizontal Lower Cotton Valley well that came on line in the third quarter at an initial 24-hour rate of 17 MMcfed.
Refer to slide 14 for additional information on QEP's Haynesville activities.
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QEP Field Services
Field Services’ third quarter 2012 gathering volumes were up 2%, NGL sales volumes were up 3%, and fee-based processing volumes were up 2% compared to the prior-year quarter.
Processing margin (total processing plant revenues less plant shrink, transportation, fractionation and operating expenses) was $34.7 million in the third quarter 2012 compared to $43.1 million in the third quarter 2011, a 19% decrease, primarily due to a decrease in the keep-whole margin received (NGL sales revenues less shrink, transportation and fractionation expenses) of 46% between the two periods.
Gathering margin (total gathering revenues less gathering related operating expenses) was $42.9 million in the third quarter 2012 compared to $47.4 million in the third quarter 2011, a 9% decrease, primarily due to a decrease in other gathering revenue related to the elimination of a third-party interruptible processing agreement for certain gas volumes in the Northern Region. The short-term processing arrangement was in effect until the Blacks Fork II processing plant was put into service during the third quarter 2011.
Approximately 80% of Field Services’ third quarter 2012 net operating revenue was derived from fee-based gathering and processing activities compared to 72% in the third quarter 2011.
Construction on Iron Horse II, a 150 MMcfed cryogenic gas processing plant in the Uinta Basin, is proceeding as planned. The plant should be operational by early 2013. Fifty percent of the processing capacity in this new facility is contracted to a third-party customer under a fee based processing agreement with the remaining capacity available to QEP Energy and other third-party customers.
During the third quarter, construction continued on Field Services' 10,000 Bbl per day NGL fractionator expansion at QEP’s Blacks Fork plant in southwestern Wyoming. When complete in mid-2013, NGL fractionation capacity at Blacks Fork will total 15,000 barrels per day. To support this expansion, QEP is doubling existing railcar loading capacity at Blacks Fork to facilitate access to what are often higher-value local, regional, and national NGL markets.
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Third Quarter 2012 Results Conference Call
QEP Resources’ management will discuss third quarter 2012 results in a conference call on Wednesday, October 31, 2012, beginning at 11:00 a.m. EDT. The conference call can be accessed at www.qepres.com. You may also participate in the conference call by dialing (877) 257-5561 in the U.S. or Canada and (706) 902-0993 for international calls, and then entering the conference ID # 37424430. A replay of the teleconference will be available on the website immediately after the call through November 30, 2012, or by dialing (855) 859-2056 in the U.S. or Canada and (404) 537-3406 for international calls, and then entering the conference ID # 37424430. In addition, QEP’s slides for the third quarter 2012, 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 in the Rockies and the Williston Basin) and the Southern Region (primarily Oklahoma, Louisiana, and the Texas Panhandle) of the United States. QEP Resources also gathers, compresses, treats, processes and stores natural gas. For more information, visit QEP Resources’ website at: www.qepres.com.
Forward-Looking Statements
This release includes forward-looking statements within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,” “expects,” “should,” “will” or other similar expressions. Such statements are based on management’s current expectations, estimates and projections, which are subject to a wide range of uncertainties and business risks. These forward-looking statements include statements regarding: forecasted Adjusted EBITDA, operating income, production and capital investment for 2012 and related assumptions for such guidance; higher natural gas prices and their impact on QEP; plans to drill and complete wells; estimated average gross completed well costs; average estimated ultimate recoveries per well; completion dates and capacity for new projects of QEP Field Services; operatorship of certain wells; and remaining locations to drill wells. Actual results may differ materially from those included in the forward-looking statements due to a number of factors, including, but not limited to: 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; natural gas, NGL and oil prices; impact of new laws and regulations; including regulations regarding the use of hydraulic fracture stimulation and the implementation of the Dodd-Frank Act; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; weather conditions; changes in maintenance and construction costs and possible inflationary pressures; permitting delays; the availability and cost of credit; outcome of contingencies such as legal proceedings; and the other risks discussed in the Company’s periodic filings with the Securities and Exchange Commission, including the Risk Factors section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2011. 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.
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Disclosures regarding Estimated Ultimate Recovery (EUR)
The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The SEC permits optional disclosure of probable and possible reserves, however QEP has made no such disclosures in its filings with the SEC. QEP uses certain terms in its periodic news releases and other presentation materials such as “estimated ultimate recovery” or “EUR”, “resource potential”, and “net resource potential”. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially more risks of actually being realized. The SEC guidelines strictly prohibit us from including such estimates in filings with the SEC. Investors are urged to closely consider the disclosures about the Company’s reserves in its Annual Report on Form 10-K for the year ended December 31, 2011, and in other reports on file with the SEC.
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QEP RESOURCES, INC. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) | |||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||
September 30, | September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
REVENUES | (in millions, except per share amounts) | ||||||||||||||
Natural gas sales | $ | 170.3 | $ | 309.8 | $ | 470.4 | $ | 921.1 | |||||||
Oil sales | 117.7 | 76.9 | 335.7 | 220.6 | |||||||||||
NGL sales | 67.5 | 79.3 | 247.0 | 191.0 | |||||||||||
Gathering, processing and other | 46.3 | 57.1 | 141.9 | 162.6 | |||||||||||
Purchased gas, oil and NGL sales | 140.6 | 356.8 | 449.9 | 810.6 | |||||||||||
Total Revenues | 542.4 | 879.9 | 1,644.9 | 2,305.9 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Purchased gas, oil and NGL expense | 142.6 | 352.7 | 455.9 | 803.3 | |||||||||||
Lease operating expense | 42.2 | 37.0 | 122.8 | 104.1 | |||||||||||
Natural gas, oil and NGL transport & other handling costs(1) | 36.3 | 27.5 | 111.5 | 73.2 | |||||||||||
Gathering, processing and other | 22.1 | 27.0 | 66.4 | 79.4 | |||||||||||
General and administrative | 41.7 | 28.7 | 114.5 | 89.1 | |||||||||||
Production and property taxes | 24.3 | 27.7 | 68.4 | 78.5 | |||||||||||
Depreciation, depletion and amortization | 234.1 | 189.0 | 647.4 | 566.4 | |||||||||||
Exploration expenses | 2.2 | 2.4 | 6.3 | 7.5 | |||||||||||
Abandonment and impairment | 9.5 | 5.7 | 71.8 | 16.4 | |||||||||||
Total Operating Expenses | 555.0 | 697.7 | 1,665.0 | 1,817.9 | |||||||||||
Net gain from asset sales | — | 1.2 | 1.5 | 1.4 | |||||||||||
OPERATING (LOSS) INCOME | (12.6 | ) | 183.4 | (18.6 | ) | 489.4 | |||||||||
Realized and unrealized gains on derivative contracts(2) | 36.1 | — | 334.7 | — | |||||||||||
Interest and other (loss) income | (0.2 | ) | (0.7 | ) | 2.4 | (0.5 | ) | ||||||||
Income from unconsolidated affiliates | 2.3 | 2.3 | 5.6 | 4.5 | |||||||||||
Loss from early extinguishment of debt | — | (0.7 | ) | (0.6 | ) | (0.7 | ) | ||||||||
Interest expense | (30.0 | ) | (22.8 | ) | (82.9 | ) | (67.0 | ) | |||||||
(LOSS) INCOME BEFORE INCOME TAXES | (4.4 | ) | 161.5 | 240.6 | 425.7 | ||||||||||
Income taxes | 2.3 | (59.1 | ) | (86.5 | ) | (156.0 | ) | ||||||||
NET (LOSS) INCOME | (2.1 | ) | 102.4 | 154.1 | 269.7 | ||||||||||
Net income attributable to noncontrolling interest | (1.0 | ) | (0.9 | ) | (2.7 | ) | (2.2 | ) | |||||||
NET (LOSS) INCOME ATTRIBUTABLE TO QEP | $ | (3.1 | ) | $ | 101.5 | $ | 151.4 | $ | 267.5 | ||||||
Earnings Per Common Share Attributable to QEP | |||||||||||||||
Basic total | $ | (0.02 | ) | $ | 0.58 | $ | 0.85 | $ | 1.52 | ||||||
Diluted total | $ | (0.02 | ) | $ | 0.57 | $ | 0.85 | $ | 1.50 | ||||||
Weighted-average common shares outstanding | |||||||||||||||
Used in basic calculation | 177.9 | 176.6 | 177.6 | 176.5 | |||||||||||
Used in diluted calculation | 177.9 | 178.5 | 178.6 | 178.5 | |||||||||||
(1) During the fourth quarter 2011, QEP revised its reporting of transportation and handling costs. Transportation and handling costs, previously netted against revenues, have been recast on the Condensed Consolidated Statements of Operations from revenues to “Natural gas, oil and NGL transport & other handling costs” for the 2011 periods presented herein. | |||||||||||||||
(2) On January 1, 2012, QEP discontinued hedge accounting. During the first three quarters of 2012, commodity derivative realized gains and losses from derivative contract settlements were included in "Realized and unrealized gains on derivative contracts" whereas during the first three quarters of 2011, commodity derivative gains and losses from derivative contract settlements were included in each of the respective revenue categories. | |||||||||||||||
10
QEP RESOUCES, INC. CONDENSED CONSOLIDATED BALANCE SHEETS | |||||||
(Unaudited) | September 30, 2012 | December 31, 2011 | |||||
ASSETS | (in millions) | ||||||
Current Assets | |||||||
Cash and cash equivalents | $ | — | $ | — | |||
Accounts receivable, net | 274.3 | 397.4 | |||||
Fair value of derivative contracts | 187.2 | 273.7 | |||||
Inventories, at lower of average cost or market | |||||||
Gas, oil and NGL | 14.0 | 16.2 | |||||
Materials and supplies | 94.9 | 87.6 | |||||
Prepaid expenses and other | 49.4 | 43.7 | |||||
Total Current Assets | 619.8 | 818.6 | |||||
Property, Plant and Equipment (successful efforts method for gas and oil properties) | |||||||
Proved properties | 9,882.4 | 8,172.4 | |||||
Unproved properties | 983.4 | 326.8 | |||||
Midstream field services | 1,605.2 | 1,463.6 | |||||
Marketing and other | 56.3 | 49.8 | |||||
Total Property, Plant and Equipment | 12,527.3 | 10,012.6 | |||||
Less Accumulated Depreciation, Depletion and Amortization | |||||||
Exploration and production | 3,977.6 | 3,339.2 | |||||
Midstream field services | 342.9 | 297.5 | |||||
Marketing and other | 16.9 | 14.6 | |||||
Total Accumulated Depreciation, Depletion and Amortization | 4,337.4 | 3,651.3 | |||||
Net Property, Plant and Equipment | 8,189.9 | 6,361.3 | |||||
Investment in unconsolidated affiliates | 41.7 | 42.2 | |||||
Goodwill | 59.5 | 59.5 | |||||
Fair value of derivative contracts | 35.2 | 123.5 | |||||
Other noncurrent assets | 50.0 | 37.6 | |||||
TOTAL ASSETS | $ | 8,996.1 | $ | 7,442.7 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Checks outstanding in excess of cash balances | $ | 27.5 | $ | 29.4 | |||
Accounts payable and accrued expenses | 464.6 | 457.3 | |||||
Production and property taxes | 56.3 | 40.0 | |||||
Interest payable | 23.7 | 24.4 | |||||
Fair value of derivative contracts | 2.7 | 1.3 | |||||
Deferred income taxes | 41.9 | 85.4 | |||||
Total Current Liabilities | 616.7 | 637.8 | |||||
Long-term debt | 3,180.7 | 1,679.4 | |||||
Deferred income taxes | 1,505.8 | 1,484.7 | |||||
Asset retirement obligations | 176.6 | 163.9 | |||||
Fair value of derivative contracts | 4.1 | — | |||||
Other long-term liabilities | 135.2 | 124.8 | |||||
Commitments and contingencies | |||||||
EQUITY | |||||||
Common stock - par value $0.01 per share; 500.0 million shares authorized; 178.5 million and 177.2 million shares issued, respectively | 1.8 | 1.8 | |||||
Treasury stock - 0.4 million and 0.4 million shares, respectively | (11.6 | ) | (13.1 | ) | |||
Additional paid-in capital | 455.8 | 431.4 | |||||
Retained earnings | 2,805.6 | 2,673.5 | |||||
Accumulated other comprehensive income | 77.4 | 207.9 | |||||
Total Common Shareholders' Equity | 3,329.0 | 3,301.5 | |||||
Noncontrolling interest | 48.0 | 50.6 | |||||
Total Equity | 3,377.0 | 3,352.1 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 8,996.1 | $ | 7,442.7 | |||
11
QEP RESOURCES, INC. CONSOLIDATED CASH FLOWS (Unaudited) | |||||||
Nine Months Ended | |||||||
September 30, | |||||||
2012 | 2011 | ||||||
(in millions) | |||||||
OPERATING ACTIVITIES | |||||||
Net income | $ | 154.1 | $ | 269.7 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 647.4 | 566.4 | |||||
Deferred income taxes | 54.7 | 155.9 | |||||
Abandonment and impairment | 71.8 | 16.4 | |||||
Share-based compensation | 19.5 | 16.5 | |||||
Amortization of debt issuance costs and discounts | 3.7 | 2.4 | |||||
Dry exploratory well expense | 0.1 | 0.5 | |||||
Net gain from asset sales | (1.5 | ) | (1.4 | ) | |||
Income from unconsolidated affiliates | (5.6 | ) | (4.5 | ) | |||
Distributions from unconsolidated affiliates and other | 6.1 | 7.6 | |||||
Non-cash loss on early extinguishment of debt | — | 0.7 | |||||
Unrealized gain on derivative contracts | (32.8 | ) | (86.7 | ) | |||
Changes in operating assets and liabilities | 54.5 | 12.2 | |||||
Net Cash Provided by Operating Activities | 972.0 | 955.7 | |||||
INVESTING ACTIVITIES | |||||||
Property acquisitions | (1,400.3 | ) | (40.7 | ) | |||
Property, plant and equipment, including dry exploratory well expense | (1,040.7 | ) | (957.7 | ) | |||
Proceeds from disposition of assets | 5.3 | 7.4 | |||||
Net Cash Used in Investing Activities | (2,435.7 | ) | (991.0 | ) | |||
FINANCING ACTIVITIES | |||||||
Checks outstanding in excess of cash balances | (1.9 | ) | 7.2 | ||||
Long-term debt issued | 1,450.0 | — | |||||
Long-term debt issuance costs paid | (17.0 | ) | (10.5 | ) | |||
Long-term debt repaid | (6.7 | ) | (58.5 | ) | |||
Proceeds from credit facility | 933.5 | 280.0 | |||||
Repayments of credit facility | (876.0 | ) | (170.0 | ) | |||
Other capital contributions | (4.2 | ) | 0.1 | ||||
Dividends paid | (10.7 | ) | (10.6 | ) | |||
Excess tax benefit on share-based compensation | 2.0 | 1.5 | |||||
Distribution from Questar | — | 0.2 | |||||
Distribution to noncontrolling interest | (5.3 | ) | (4.1 | ) | |||
Net Cash Provided by Financing Activities | 1,463.7 | 35.3 | |||||
Change in cash and cash equivalents | — | — | |||||
Beginning cash and cash equivalents | — | — | |||||
Ending cash and cash equivalents | $ | — | $ | — | |||
12
QEP RESOURCES, INC. OPERATIONS BY LINE OF BUSINESS (Unaudited) QEP Energy - Production by Region | |||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
(in Bcfe) | |||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||
Northern Region | |||||||||||||||||
Pinedale | 28.0 | 21.6 | 30 | % | 73.9 | 55.6 | 33 | % | |||||||||
Uinta Basin(1) | 6.4 | 4.8 | 33 | % | 16.9 | 16.2 | 4 | % | |||||||||
Legacy | 7.3 | 5.6 | 30 | % | 20.6 | 15.1 | 36 | % | |||||||||
Total Northern Region | 41.7 | 32.0 | 30 | % | 111.4 | 86.9 | 28 | % | |||||||||
Southern Region | |||||||||||||||||
Haynesville/Cotton Valley | 27.9 | 26.8 | 4 | % | 86.8 | 80.9 | 7 | % | |||||||||
Midcontinent | 11.9 | 11.9 | — | % | 37.1 | 33.5 | 11 | % | |||||||||
Total Southern Region | 39.8 | 38.7 | 3 | % | 123.9 | 114.4 | 8 | % | |||||||||
Total production | 81.5 | 70.7 | 15 | % | 235.3 | 201.3 | 17 | % | |||||||||
(1) Includes 1.6 Bcfe from the first quarter 2011 production from prior periods due to change in ownership interest in a federal unit. | |||||||||||||||||
QEP Energy - Total Production | |||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||
QEP Energy Production Volumes | |||||||||||||||||
Natural gas (Bcf) | 64.5 | 59.8 | 8 | % | 188.0 | 175.9 | 7 | % | |||||||||
Oil (Mbbl) | 1,442.6 | 922.6 | 56 | % | 3,973.1 | 2,559.2 | 55 | % | |||||||||
NGL (Mbbl) | 1,386.7 | 894.4 | 55 | % | 3,906.2 | 1,675.0 | 133 | % | |||||||||
Total production (Bcfe) | 81.5 | 70.7 | 15 | % | 235.3 | 201.3 | 17 | % | |||||||||
Average daily production (MMcfe) | 885.8 | 767.7 | 15 | % | 858.8 | 737.2 | 16 | % | |||||||||
13
QEP Energy - Prices(1) | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
2012(2) | 2011(3) | Change | 2012 | 2011 | Change | ||||||||||||||||
Natural gas (per Mcf) | |||||||||||||||||||||
Average field-level price | $ | 2.64 | $ | 3.99 | $ | 2.50 | $ | 4.05 | |||||||||||||
Commodity derivative impact | 1.34 | 0.73 | 1.51 | 0.69 | |||||||||||||||||
Net realized price | $ | 3.98 | $ | 4.72 | (16 | )% | $ | 4.01 | $ | 4.74 | (15 | )% | |||||||||
Oil (per bbl) | |||||||||||||||||||||
Average field-level price | $ | 81.60 | $ | 82.42 | $ | 84.49 | $ | 85.82 | |||||||||||||
Commodity derivative impact | 1.83 | 0.91 | 0.55 | 0.37 | |||||||||||||||||
Net realized price | $ | 83.43 | $ | 83.33 | — | % | $ | 85.04 | $ | 86.19 | (1 | )% | |||||||||
NGL (per bbl) | |||||||||||||||||||||
Average field-level price | 27.83 | 39.44 | 34.38 | 42.43 | |||||||||||||||||
Commodity derivative impact | 2.46 | — | 1.66 | — | |||||||||||||||||
Net realized price | $ | 30.29 | $ | 39.44 | (23 | )% | $ | 36.04 | $ | 42.43 | (15 | )% | |||||||||
(1) Prior year is recast to reflect exclusion of natural gas, oil and NGL transport & other handling costs. | |||||||||||||||||||||
(2) The commodity derivative impact is reported below operating (loss) income in "Realized and unrealized gains on derivative contracts" beginning January 1, 2012, in the Condensed Consolidated Statement of Operations. | |||||||||||||||||||||
(3) The impact of settled commodity derivatives that qualified for hedge accounting was reported in "Revenues" in the Condensed Consolidated Statement of Operations. The impact of the commodity derivatives that did not qualify for hedge accounting are reported below operating (loss) income in "Realized and unrealized gains on derivative contracts" | |||||||||||||||||||||
QEP Energy - Operating Expenses | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||
(per Mcfe) | |||||||||||||||||||||
Depreciation, depletion and amortization | $ | 2.67 | $ | 2.47 | 8 | % | $ | 2.54 | $ | 2.60 | (2 | )% | |||||||||
Lease operating expense | 0.53 | 0.54 | (2 | )% | 0.53 | 0.53 | — | % | |||||||||||||
Natural gas, oil and NGL transport & other handling costs | 0.73 | 0.64 | 14 | % | 0.71 | 0.65 | 9 | % | |||||||||||||
General and administrative expense | 0.39 | 0.33 | 18 | % | 0.40 | 0.35 | 14 | % | |||||||||||||
Allocated interest expense | 0.30 | 0.29 | 3 | % | 0.30 | 0.30 | — | % | |||||||||||||
Production taxes | 0.27 | 0.37 | (27 | )% | 0.27 | 0.37 | (27 | )% | |||||||||||||
Total Operating Expenses | $ | 4.89 | $ | 4.64 | 5 | % | $ | 4.75 | $ | 4.80 | (1 | )% | |||||||||
14
QEP Field Services | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||
QEP Field Services Gathering Operating Statistics | |||||||||||||||||||||
Natural gas gathering volumes (millions of MMBtu) | 129.3 | 126.9 | 2 | % | 386.9 | 367.0 | 5 | % | |||||||||||||
Gathering revenue (per MMBtu) | $ | 0.34 | $ | 0.33 | 3 | % | $ | 0.34 | $ | 0.33 | 3 | % | |||||||||
QEP Field Services Gathering Margin (in millions) | |||||||||||||||||||||
Gathering | $ | 43.9 | $ | 41.9 | 5 | % | $ | 131.6 | $ | 120.0 | 10 | % | |||||||||
Other Gathering | 8.0 | 16.5 | (52 | )% | 28.6 | 59.2 | (52 | )% | |||||||||||||
Gathering (expense) | (9.0 | ) | (11.0 | ) | (18 | )% | (26.9 | ) | (35.3 | ) | (24 | )% | |||||||||
Gathering margin | $ | 42.9 | $ | 47.4 | (9 | )% | $ | 133.3 | $ | 143.9 | (7 | )% | |||||||||
QEP Field Services Processing Margin (in millions) | |||||||||||||||||||||
NGL sales(3) | $ | 28.9 | $ | 44.1 | (34 | )% | $ | 112.7 | $ | 119.9 | (6 | )% | |||||||||
Realized gains from commodity derivative contract settlements | 1.9 | — | — | % | 6.3 | — | — | % | |||||||||||||
Processing (fee-based) revenues | 18.2 | 15.4 | 18 | % | 51.8 | 37.6 | 38 | % | |||||||||||||
Other processing fees | 5.4 | 1.7 | 218 | % | 8.4 | 1.7 | 394 | % | |||||||||||||
Processing (expense) | (4.7 | ) | (3.1 | ) | 52 | % | (12.1 | ) | (8.9 | ) | 36 | % | |||||||||
Processing plant fuel and shrink (expense) | (8.1 | ) | (12.5 | ) | (35 | )% | (26.6 | ) | (34.1 | ) | (22 | )% | |||||||||
Natural gas, oil and NGL transport & other handling costs | (6.9 | ) | (2.5 | ) | 176 | % | (27.7 | ) | (4.6 | ) | 502 | % | |||||||||
Processing margin | $ | 34.7 | $ | 43.1 | (19 | )% | $ | 112.8 | $ | 111.6 | 1 | % | |||||||||
Keep-whole processing margin(1) | $ | 15.8 | $ | 29.1 | (46 | )% | $ | 64.7 | $ | 81.2 | (20 | )% | |||||||||
QEP Field Services Processing Operating Statistics | |||||||||||||||||||||
Natural gas processing volumes | |||||||||||||||||||||
NGL sales (MMgal) | 34.9 | 34.0 | 3 | % | 121.5 | 98.2 | 24 | % | |||||||||||||
Average net realized NGL sales price (per gal)(2) | $ | 0.88 | $ | 1.30 | (32 | )% | $ | 0.98 | $ | 1.22 | (20 | )% | |||||||||
Total fee-based processing volumes (in millions of MMBtu) | 65.0 | 63.8 | 2 | % | 189.2 | 181.1 | 4 | % | |||||||||||||
Average fee-based processing revenue (per MMBtu) | $ | 0.28 | $ | 0.24 | 17 | % | $ | 0.27 | $ | 0.21 | 29 | % | |||||||||
(1) NGL sales less processing plant fuel and shrink less natural gas, oil and NGL transport & other handling costs. | |||||||||||||||||||||
(2) Average net realized NGL sales price per gallon is calculated as NGL sales including realized gains from commodity derivative contracts settlements divided by NGL sales volumes. | |||||||||||||||||||||
(3) NGL sales for the three and nine months ended September 30, 2011, have been recast to reflect QEP's revised reporting of its transportation and handling costs. In addition, revenues for the three and nine months ended September 30, 2011, reflect the impact of QEP's settled derivative contracts which during the three and nine months ended September 30, 2012, are reflected below operating (loss) income. | |||||||||||||||||||||
15
QEP RESOURCES, INC.
NON-GAAP MEASURES
(Unaudited)
This release contains references to the non-GAAP measure of Adjusted EBITDA. Management defines Adjusted EBITDA as net income before the following items: unrealized gains and losses on derivative contracts, gains and losses from asset sales, interest and other income, income taxes, interest expense, depreciation, depletion, and amortization, abandonment and impairment, exploration expense and loss on early extinguishment of debt. Management uses Adjusted EBITDA to assess the Company's operating results. Management believes Adjusted EBITDA is an important measure of the Company's cash flow and liquidity and its ability to incur and service debt, fund capital expenditures and make distributions to shareholders and is an important measure for comparing the Company's financial performance to other gas and oil producing companies. In addition, Adjusted EBITDA is a part of the Company's debt covenants as defined in its revolving credit and term loan agreements.
The following tables reconcile QEP Resources’ and its subsidiaries’ net income to Adjusted EBITDA:
Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||||
QEP Resources | (in millions) | ||||||||||||||||||||||
Net (loss) income attributable to QEP Resources | $ | (3.1 | ) | $ | 101.5 | $ | (104.6 | ) | $ | 151.4 | $ | 267.5 | $ | (116.1 | ) | ||||||||
Net income attributable to non-controlling interest | 1.0 | 0.9 | 0.1 | 2.7 | 2.2 | 0.5 | |||||||||||||||||
Net (loss) income | (2.1 | ) | 102.4 | (104.5 | ) | 154.1 | 269.7 | (115.6 | ) | ||||||||||||||
Unrealized loss (gain) on derivative contracts | 57.1 | (27.9 | ) | 85.0 | (32.8 | ) | (86.7 | ) | 53.9 | ||||||||||||||
Net gain from asset sales | — | (1.2 | ) | 1.2 | (1.5 | ) | (1.4 | ) | (0.1 | ) | |||||||||||||
Interest and other loss (income) | 0.2 | 0.7 | (0.5 | ) | (2.4 | ) | 0.5 | (2.9 | ) | ||||||||||||||
Income taxes | (2.3 | ) | 59.1 | (61.4 | ) | 86.5 | 156.0 | (69.5 | ) | ||||||||||||||
Interest expense | 30.0 | 22.8 | 7.2 | 82.9 | 67.0 | 15.9 | |||||||||||||||||
Loss on early extinguishment of debt | — | 0.7 | (0.7 | ) | 0.6 | 0.7 | (0.1 | ) | |||||||||||||||
Depreciation, depletion and amortization | 234.1 | 189.0 | 45.1 | 647.4 | 566.4 | 81.0 | |||||||||||||||||
Abandonment and impairment | 9.5 | 5.7 | 3.8 | 71.8 | 16.4 | 55.4 | |||||||||||||||||
Exploration expenses | 2.2 | 2.4 | (0.2 | ) | 6.3 | 7.5 | (1.2 | ) | |||||||||||||||
Adjusted EBITDA | $ | 328.7 | $ | 353.7 | $ | (25.0 | ) | $ | 1,012.9 | $ | 996.1 | $ | 16.8 | ||||||||||
QEP Energy | |||||||||||||||||||||||
Net (loss) income attributable to QEP Energy | $ | (26.2 | ) | $ | 58.3 | $ | (84.5 | ) | $ | 51.6 | $ | 148.2 | $ | (96.6 | ) | ||||||||
Unrealized loss (gain) on derivative contracts | 50.9 | (27.9 | ) | 78.8 | (37.9 | ) | (86.7 | ) | 48.8 | ||||||||||||||
Net gain from asset sales | — | (1.2 | ) | 1.2 | (1.5 | ) | (1.4 | ) | (0.1 | ) | |||||||||||||
Interest and other loss (income) | 0.2 | 0.7 | (0.5 | ) | (2.2 | ) | 0.5 | (2.7 | ) | ||||||||||||||
Income taxes | (15.3 | ) | 34.4 | (49.7 | ) | 32.4 | 87.7 | (55.3 | ) | ||||||||||||||
Interest expense | 24.1 | 20.5 | 3.6 | 71.1 | 60.8 | 10.3 | |||||||||||||||||
Depreciation, depletion and amortization | 217.4 | 174.4 | 43.0 | 597.7 | 524.0 | 73.7 | |||||||||||||||||
Abandonment and impairment | 9.5 | 5.7 | 3.8 | 71.8 | 16.4 | 55.4 | |||||||||||||||||
Exploration expenses | 2.2 | 2.4 | (0.2 | ) | 6.3 | 7.5 | (1.2 | ) | |||||||||||||||
Adjusted EBITDA | $ | 262.8 | $ | 267.3 | $ | (4.5 | ) | $ | 789.3 | $ | 757.0 | $ | 32.3 | ||||||||||
16
Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||||
QEP Field Services | (in millions) | ||||||||||||||||||||||
Net income attributable to QEP Field Services | $ | 28.7 | $ | 42.0 | $ | (13.3 | ) | $ | 107.4 | $ | 114.2 | $ | (6.8 | ) | |||||||||
Net income attributable to non-controlling interest | 1.0 | 0.9 | 0.1 | 2.7 | 2.2 | 0.5 | |||||||||||||||||
Net income | 29.7 | 42.9 | (13.2 | ) | 110.1 | 116.4 | (6.3 | ) | |||||||||||||||
Unrealized loss (gain) on derivative contracts | 2.5 | — | 2.5 | (2.0 | ) | — | (2.0 | ) | |||||||||||||||
Net gain from asset sales | — | 0.1 | (0.1 | ) | — | — | — | ||||||||||||||||
Interest and other (income) | — | — | — | (0.1 | ) | — | (0.1 | ) | |||||||||||||||
Income taxes | 16.5 | 24.0 | (7.5 | ) | 59.2 | 65.6 | (6.4 | ) | |||||||||||||||
Interest expense | 3.5 | 3.8 | (0.3 | ) | 9.4 | 10.4 | (1.0 | ) | |||||||||||||||
Depreciation, depletion and amortization | 15.8 | 14.0 | 1.8 | 47.2 | 40.7 | 6.5 | |||||||||||||||||
Adjusted EBITDA | $ | 68.0 | $ | 84.8 | $ | (16.8 | ) | $ | 223.8 | $ | 233.1 | $ | (9.3 | ) | |||||||||
QEP Marketing & Other | |||||||||||||||||||||||
Net (loss) income attributable to QEP Marketing and other | $ | (5.6 | ) | $ | 1.2 | $ | (6.8 | ) | $ | (7.6 | ) | $ | 5.1 | $ | (12.7 | ) | |||||||
Unrealized loss on derivative contracts | 3.7 | — | 3.7 | 7.1 | — | 7.1 | |||||||||||||||||
Net gain from asset sales | — | (0.1 | ) | 0.1 | — | — | — | ||||||||||||||||
Interest and other (income) | — | — | — | (0.1 | ) | — | (0.1 | ) | |||||||||||||||
Income taxes | (3.5 | ) | 0.7 | (4.2 | ) | (5.1 | ) | 2.7 | (7.8 | ) | |||||||||||||
Interest expense | 2.4 | (1.5 | ) | 3.9 | 2.4 | (4.2 | ) | 6.6 | |||||||||||||||
Loss on early extinguishment of debt | — | 0.7 | (0.7 | ) | 0.6 | 0.7 | (0.1 | ) | |||||||||||||||
Depreciation, depletion and amortization | 0.9 | 0.6 | 0.3 | 2.5 | 1.7 | 0.8 | |||||||||||||||||
Adjusted EBITDA | $ | (2.1 | ) | $ | 1.6 | $ | (3.7 | ) | $ | (0.2 | ) | $ | 6.0 | $ | (6.2 | ) | |||||||
17
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, non-cash price-related asset impairments, costs from early extinguishment of debt and unrealized gains and losses on derivative contracts. 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 attributable to QEP Resources’ to Adjusted Net Income:
Three Months Ended | Nine Months Ended | ||||||||||||||
September 30, | September 30, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
(in millions, except per earnings per share) | |||||||||||||||
Net (loss) income attributable to QEP Resources | $ | (3.1 | ) | $ | 101.5 | $ | 151.4 | $ | 267.5 | ||||||
Adjustments to net income | |||||||||||||||
Net gain from asset sales | — | (1.2 | ) | (1.5 | ) | (1.4 | ) | ||||||||
Income taxes on net gain on asset sales | — | 0.4 | 0.6 | 0.5 | |||||||||||
Unrealized loss (gain) on derivative contracts | 57.1 | (27.9 | ) | (32.8 | ) | (86.7 | ) | ||||||||
Income taxes on unrealized loss (gain) on derivative contracts | (21.3 | ) | 10.3 | 12.2 | 32.2 | ||||||||||
Loss on early extinguishment of debt | — | 0.7 | 0.6 | 0.7 | |||||||||||
Income taxes on loss from early extinguishment of debt | — | (0.3 | ) | (0.2 | ) | (0.3 | ) | ||||||||
Non-cash price-related impairment charge | — | 0.2 | 49.3 | 0.2 | |||||||||||
Income taxes on non-cash price-related impairment charge | — | (0.1 | ) | (18.3 | ) | (0.1 | ) | ||||||||
Total after-tax adjustments to net income | 35.8 | (17.9 | ) | 9.9 | (54.9 | ) | |||||||||
Adjusted net income attributable to QEP Resources | $ | 32.7 | $ | 83.6 | $ | 161.3 | $ | 212.6 | |||||||
Earnings per Common Share attributable to QEP | |||||||||||||||
Diluted earnings per share | $ | (0.02 | ) | $ | 0.57 | $ | 0.85 | $ | 1.50 | ||||||
Diluted after-tax adjustments to net income per share | 0.21 | (0.10 | ) | 0.06 | (0.31 | ) | |||||||||
Diluted Adjusted Net Income per share | $ | 0.19 | $ | 0.47 | $ | 0.91 | $ | 1.19 | |||||||
Weighted-average common shares outstanding | |||||||||||||||
Diluted(1) | 178.7 | 178.5 | 178.6 | 178.5 | |||||||||||
Weighted-average common shares outstanding diluted Non-GAAP reconciliation(1) | |||||||||||||||
Weighted-average common shares outstanding used in GAAP diluted calculation | 177.9 | ||||||||||||||
Potential number of shares issuable upon exercise of in-the-money stock options under the long-term stock incentive plan | 0.8 | ||||||||||||||
Weighted-average common shares outstanding used in Non- GAAP diluted calculation | 178.7 | ||||||||||||||
(1) The three months ended September 30, 2012, 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 months ended September 30, 2012, in calculating earnings-per-share for GAAP purposes, because the effect is antidilutive due to the Company's net loss for GAAP purposes. | |||||||||||||||
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The following table presents open 2012 derivative positions as of October 26, 2012:
QEP Energy Commodity Derivative Positions | |||||||||||||||||||
Swaps | Collars | ||||||||||||||||||
Year | Type of Contract | Index | Total Volumes | Average price per unit | Floor price | Ceiling price | |||||||||||||
(in millions) | |||||||||||||||||||
Natural gas sales | (MMBtu) | ||||||||||||||||||
2012 | Swap | NYMEX | 19.3 | $ | 4.72 | ||||||||||||||
2012 | Swap | IFPEPL (1) | 1.8 | $ | 4.70 | ||||||||||||||
2012 | Swap | IFNPCR (2) | 22.1 | $ | 4.67 | ||||||||||||||
2012 | Swap | IFCNPTE (3) | 2.8 | $ | 2.66 | ||||||||||||||
2013 | Swap | NYMEX | 40.2 | $ | 3.74 | ||||||||||||||
2013 | Swap | IFNPCR (2) | 65.7 | $ | 5.66 | ||||||||||||||
2014 | Swap | NYMEX | 18.3 | $ | 4.21 | ||||||||||||||
Oil sales | (Bbls) | ||||||||||||||||||
2012 | Swap | NYMEX WTI | 1.3 | $ | 97.42 | ||||||||||||||
2012 | Collar | NYMEX WTI | 0.4 | $ | 87.50 | $ | 115.36 | ||||||||||||
2013 | Swap | NYMEX WTI | 5.1 | $ | 98.48 | ||||||||||||||
2014 | Swap | NYMEX WTI | 1.8 | $ | 92.72 | ||||||||||||||
NGL sales | (Gals) | ||||||||||||||||||
2012 | Swap | Mt. Belvieu Ethane | 3.9 | $ | 0.64 | ||||||||||||||
2012 | Swap | Mt. Belvieu Propane | 5.8 | $ | 1.28 | ||||||||||||||
QEP Field Services Commodity Derivative Positions | |||||||||||
Year | Type of Contract | Index | Total Volumes | Average Swap price per gallon | |||||||
(in millions) | |||||||||||
NGL sales | (Gals) | ||||||||||
2012 | Swap | Mt. Belvieu Ethane | 3.9 | $ | 0.64 | ||||||
2012 | Swap | Mt. Belvieu Propane | 1.9 | $ | 1.28 | ||||||
QEP Marketing Commodity Derivative Positions | |||||||||||
Year | Type of Contract | Index | Total Volumes | Average Swaps price per MMBtu | |||||||
(in millions) | |||||||||||
Natural gas sales | (MMBtu) | ||||||||||
2012 | Swap | IFNPCR | 2.3 | $ | 3.87 | ||||||
2013 | Swap | IFNPCR | 3.9 | $ | 3.79 | ||||||
Natural gas purchases | (MMBtu) | ||||||||||
2012 | Swap | IFNPCR | 2.0 | $ | 2.92 | ||||||
2013 | Swap | IFNPCR | 0.1 | $ | 2.59 | ||||||
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