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| 8-K - 8-K - QEP RESOURCES, INC. | a8-kxyenewsrelease.htm |
News ReleaseInvestors: Greg Bensen
Director, Investor Relations
303-405-6665
QEP RESOURCES REPORTS ESTIMATED FOURTH QUARTER AND FULL YEAR 2012 FINANCIAL AND OPERATING RESULTS
DENVER — February 19, 2013// QEP Resources, Inc. (NYSE: QEP) ("QEP" or the "Company"), today reported estimated fourth quarter and full year 2012 financial and operating results. The Company reported a net loss during the fourth quarter 2012 of $23.1 million, or $0.13 per diluted share, compared to a net loss of $0.3 million and no earnings per diluted share, in the fourth quarter 2011. For the year ended December 31, 2012, QEP Resources reported net income of $128.3 million, or $0.72 per diluted share, compared to $267.2 million, or $1.50 per diluted share, for the comparable 2011 period. Net income or loss includes non-cash gains and losses associated with the change in the fair value of derivative instruments, gains and losses from asset sales, costs associated with the early extinguishment of debt, non-cash price-related impairment charges and an accrual for a litigation loss contingency. Excluding these items, the Company’s Adjusted Net Income (a non-GAAP measure) was $227.9 million, or $1.28 per diluted share, for the year ended December 31, 2012, compared to $316.2 million or $1.77 per diluted share, for the comparable 2011 period. Similarly, the Company's Adjusted Net Income was $59.8 million, or $0.33 per diluted share, in the fourth quarter 2012 compared to $104.6 million, or $0.58 per diluted share, in the fourth quarter 2011. The lower Adjusted Net Income was due primarily to lower natural gas and NGL prices, lower midstream NGL sales volumes and prices, and higher depreciation, depletion and amortization and other expenses in the fourth quarter 2012 compared to 2011.
Adjusted EBITDA (a non-GAAP measure) for the fourth quarter 2012 was $391.8 million, compared to $390.5 million in the fourth quarter 2011. For the year ended December 31, 2012, the Company reported Adjusted EBITDA of $1,415.5 million compared to $1,386.6 million for the year ended December 31, 2011. A reconciliation of Adjusted EBITDA and Adjusted Net Income to net income is provided within the financial tables of this release.
Full Year 2012 Highlights
▪ | QEP Energy reported record net production of 319.2 Bcfe, an increase of 16% when compared to 2011. The growth was driven primarily by increased crude oil and NGL production, which were up 69% and 97%, respectively. |
▪ | Crude oil and NGL comprised 22% of QEP Energy's production compared to 14% in 2011. |
▪ | QEP Energy grew estimated proved reserves 9%, or 322.3 Bcfe, driven primarily by a 76% (52 million barrel) increase in crude oil reserves and a 30% (23 million barrel) increase in NGL reserves. Excluding negative price-related revisions of 152.4 Bcfe, QEP Energy's estimated proved reserves grew by 13% from 2011. |
▪ | QEP completed the largest acquisition in company history - the $1.4 billion acquisition of approximately 125 million barrels of proved and probable reserves in the Williston Basin, (the "North Dakota Acquisition"). |
"I am pleased with QEP's accomplishments in 2012," said Chuck Stanley, Chairman, President and CEO of QEP Resources. "QEP Energy's dramatic growth in liquids production drove a 16% increase in total production compared to
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2011. Crude oil and NGL volumes represented 22% of QEP Energy's production in 2012, a substantial increase from 14% in 2011. The positive impact of our North Dakota Acquisition is clear - crude oil represented 17% of QEP Energy's production in the fourth quarter 2012 compared to just 10% in the prior year period and 11% in the third quarter 2012. QEP Energy's full year 2012 Adjusted EBITDA grew 7% from 2011 levels despite a 15% decrease in the net realized price of natural gas and a 24% decrease in the net realized price of NGL. QEP Energy also grew estimated proved reserves by 9%, replacing 201% of 2012 production despite 245 Bcfe of mostly price-related negative reserve revisions." The Company's 2012 year-end proved reserves totaled 3.9 Tcfe.
"QEP Field Services 2012 Adjusted EBITDA declined 12% from a year ago, due primarily to lower NGL prices that resulted in lower keep-whole processing margins," continued Stanley. "Field Service's fee-based processing revenues in the fourth quarter 2012 were up 11% from the prior year on higher processing volume and per-unit revenue. Field Services new Iron Horse II cryogenic processing plant is in startup and commissioning and the 10,000 barrel per day expansion of our fractionator at Blacks Fork remains on track for a mid-2013 startup."
"Results to date from the three QEP-operated wells completed on the South Antelope property in North Dakota since last September continue to confirm our expectations of strong well performance. All three wells had strong initial production rates and average gross estimated ultimate recoveries of slightly over one million barrels of oil equivalent per well. Despite the challenging natural gas and NGL price environment, QEP remains well-positioned to grow crude oil production profitably from our newly acquired North Dakota properties," concluded Stanley.
QEP Financial Results Summary
Adjusted EBITDA by Subsidiary | |||||||||||||||||||||
Three Months Ended | Year Ended | ||||||||||||||||||||
December 31, | December 31, | ||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||
(in millions) | |||||||||||||||||||||
QEP Energy | $ | 333.5 | $ | 300.5 | 11 | % | $ | 1,133.6 | $ | 1,057.5 | 7 | % | |||||||||
QEP Field Services | 57.3 | 87.2 | (34 | )% | 281.1 | 320.3 | (12 | )% | |||||||||||||
QEP Marketing and other | 1.0 | 2.8 | (64 | )% | 0.8 | 8.8 | (91 | )% | |||||||||||||
Adjusted EBITDA(1) | $ | 391.8 | $ | 390.5 | — | % | $ | 1,415.5 | $ | 1,386.6 | 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 14% to 83.9 Bcfe in the fourth quarter 2012 compared to 73.9 Bcfe in 2011. Crude oil, NGL and natural gas production increased 97%, 39%, and 1%, respectively, in the fourth quarter 2012 compared to 2011. |
▪ | Adjusted EBITDA increased 11% compared to the fourth quarter 2011, driven by the 14% increase in production volumes offset by decreases of 12% and 34%, respectively, in the net realized price for natural gas and NGL. |
▪ | Crude oil and NGL revenues increased 52% compared to the fourth quarter 2011 and represented approximately 56% of field-level production revenues. |
▪ | Capital investment (on an accrual basis) for the year ended December 31, 2012, was $2.7 billion. Investments included $1.3 billion in drilling, completion and other expenditures and $1.4 billion in property acquisitions. |
▪ | QEP Energy recorded non-cash impairment charges of $58.3 million, before-tax, in the fourth quarter 2012 as a result of lower natural gas and NGL prices that impacted the carrying value of proved reserves in several Midcontinent Division (Oklahoma and Texas) and one Uinta Basin Division (not related to the Red Wash Lower Mesaverde project) successful efforts pools. |
▪ | QEP Energy recorded an accrual for a litigation loss contingency of $104.2 million, before-tax, in the fourth quarter 2012 related to a statewide royalty class action lawsuit in Oklahoma. On February 13, 2013, the parties |
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to the litigation entered into a Stipulation and Agreement of Settlement, which is subject to court approval. For details, see our Current Report on Form 8-K filed with the SEC on February 15, 2013.
▪ | The slides for the fourth quarter 2012 with maps and other supporting materials referred to in this release are posted on the Company’s website at www.qepres.com. |
QEP Field Services
▪ | QEP Field Services’ Adjusted EBITDA decreased 34% in the fourth quarter 2012 compared to the prior-year period, due primarily to an 18% decrease in net realized NGL prices, a 45% decrease in NGL sales volumes as a result of ethane rejection (where ethane is left in the production stream and sold as natural gas) and a 14% decrease in other gathering revenue related to the elimination of a third-party interruptible gathering and processing agreement for certain gas volumes in the Northern Region, partially offset by a 11% increase in total fee-based processing revenues. |
▪ | Capital investment (on an accrual basis) for the year ended December 31, 2012 totaled $171.2 million. |
QEP 2013 Guidance
QEP Resources has revised its full-year 2013 guidance due to changes in commodity prices. The Company’s guidance incorporates commodity price derivative positions in place on the date of this release, assumes full ethane recovery, and other assumptions summarized in the table below:
Guidance and Assumptions | |||
2013 | |||
Current Forecast | Previous Forecast | ||
(Adjusted EBITDA and capital investments shown in millions) | |||
QEP Resources Adjusted EBITDA(1) | $1,500 - $1,650 | $1,525 - $1,675 | |
QEP Energy capital investment | $1,480 - $1,580 | $1,480 - $1,630 | |
QEP Field Services capital investment | $120 | $120 | |
QEP Marketing capital investment | $0 | $0 | |
Corporate capital investment | $25 | $25 | |
Total QEP Resources capital investment | $1,625 - $1,725 | $1,625 - $1,775 | |
QEP Energy production - Bcfe | 325 - 330 | 325 - 330 | |
NYMEX gas price per MMBtu(2) | $3.25 - $4.25 | $3.50 - $4.50 | |
NYMEX crude oil price per bbl(2) | $90.00 - $100.00 | $85.00 - $95.00 | |
NYMEX /Rockies basis differential per MMBtu(2) | $0.15 - $0.10 | $0.15 - $0.10 | |
NYMEX/Midcontinent basis differential per MMBtu(2) | $0.20 - $0.15 | $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) For remaining 2013 forecast 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. | |||
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Proved Reserves Summary
QEP Energy's estimated proved reserves totaled 3.9 Tcfe at December 31, 2012, up 9% from year-end 2011. Approximately 33% of total proved reserves at year-end 2012 were crude oil and NGL compared to 24% at year-end 2011. Total proved developed reserves comprised 2.1 Tcfe, or 54%, of the total reserves. Additions and extensions were 572.5 Bcfe resulting from additions in the Uinta Basin and Pinedale. Purchases of reserves in place were 313.8 Bcfe due primarily to the North Dakota Acquisition. Negative price-related revisions comprised 152.4 Bcfe of the total negative reserve revision of 244.8 Bcfe. A reconciliation of reported quantities of proved reserves is summarized in the table below:
Natural Gas | Oil | NGL | Natural Gas Equivalents | |||||||||
(Bcf) | (MMbbl) | (MMbbl) | (Bcfe) | |||||||||
Balance at December 31, 2011 | 2,749.4 | 67.5 | 76.6 | 3,613.8 | ||||||||
Revisions of previous estimates | (240.6 | ) | (1.5 | ) | 0.7 | (244.8 | ) | |||||
Extensions and discoveries | 330.6 | 17.3 | 23.0 | 572.5 | ||||||||
Purchase of reserves in place | 32.3 | 42.0 | 4.9 | 313.8 | ||||||||
Sale of reserves in place | — | — | — | — | ||||||||
Production | (249.3 | ) | (6.3 | ) | (5.3 | ) | (319.2 | ) | ||||
Balance at December 31, 2012 | 2,622.4 | 119.0 | 99.9 | 3,936.1 | ||||||||
Details on year-end 2012 and 2011 proved reserves by QEP Energy division/operating area, proved reserve category and percentage of total proved reserves comprised of crude oil and NGL (liquids) are as follows:
Total (in Bcfe) | % of total | PUD % | % liquids | |||||||||
For the year ended December 31, 2012 | ||||||||||||
Northern Region | ||||||||||||
Pinedale | 1,530.8 | 39 | % | 41 | % | 23 | % | |||||
Williston Basin | 614.7 | 16 | % | 75 | % | 92 | % | |||||
Uinta Basin | 617.9 | 16 | % | 56 | % | 33 | % | |||||
Legacy | 112.2 | 3 | % | — | % | 18 | % | |||||
Southern Region | ||||||||||||
Haynesville/Cotton Valley | 530.5 | 13 | % | 42 | % | — | % | |||||
Midcontinent | 530.0 | 13 | % | 31 | % | 33 | % | |||||
Total QEP Energy | 3,936.1 | 100 | % | 46 | % | 33 | % | |||||
For the year ended December 31, 2011 | ||||||||||||
Northern Region | ||||||||||||
Pinedale | 1,531.0 | 42 | % | 47 | % | 23 | % | |||||
Williston Basin | 259.0 | 7 | % | 75 | % | 94 | % | |||||
Uinta Basin | 393.6 | 11 | % | 46 | % | 23 | % | |||||
Legacy | 128.6 | 4 | % | — | % | 15 | % | |||||
Southern Region | ||||||||||||
Haynesville/Cotton Valley | 782.9 | 22 | % | 46 | % | — | % | |||||
Midcontinent | 518.7 | 14 | % | 36 | % | 31 | % | |||||
Total QEP Energy | 3,613.8 | 100 | % | 46 | % | 24 | % | |||||
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Operations Summary
QEP Energy
Williston Basin: Continued growth in crude oil production on 117,000 net acre Bakken/Three Forks leasehold
During the fourth quarter 2012, QEP Energy's Bakken/Three Forks net production averaged 18,348 Boed. The Company completed and turned to sales 11 operated wells, including two wells in the South Antelope Area (QEP Energy's average working interest 99%) and nine wells within the Fort Berthold Reservation (QEP Energy's average working interest 74%) during the fourth quarter. The South Antelope wells were both completed in the Three Forks Formation and had an average 24-hour initial production rate of 2,175 Boed. The Fort Berthold Reservation completions included five wells (QEP Energy's working interest 76%) on the Independence Pad (three Three Forks Formation and two Bakken Formation) with an average 24-hour initial production rate of 2,550 Boed; two wells on a pad just west of the Independence Pad (QEP Energy's working interest 75%, one Three Forks Formation and one Bakken Formation) with an average 24-hour initial production rate of 2,450 Boed; and two eastern delineation wells on a pad in T 148 N-R 91 W (QEP Energy's working interest 70%, one Three Forks Formation and one Bakken Formation) with an average 24-hour initial production rate of 965 Boed.
At the end of 2012, the Company operated 84 producing wells in the Williston Basin, including 38 Bakken wells, 43 Three Forks wells and three dual lateral horizontal wells producing from both the Bakken and Three Forks formations. In addition, the Company has a working interest in 191 outside-operated producing wells.
At the end of the fourth quarter, QEP Energy had 11 operated wells drilling or at intermediate casing point and nine QEP Energy-operated wells awaiting completion (QEP Energy's average working interest 87%). The Company also had interests in 16 outside-operated wells being drilled (QEP Energy's average working interest 7%) and 23 outside-operated wells awaiting completion (QEP Energy's average working interest 3%) at the end of the fourth quarter.
At the end of 2012, QEP Energy had five rigs operating in the Bakken/Three Forks play (two in the South Antelope Area and three within the Fort Berthold Reservation). QEP Energy's operated completed well costs for a typical long-lateral Bakken or Three Forks well averaged $11 million in the second half of 2012.
Slides 6-8 depict QEP Energy's acreage and activity in the Bakken/Three Forks play.
Pinedale Anticline: 102 new well completions in 2012
During the fourth quarter 2012, QEP Energy's Pinedale net production averaged 281 MMcfed, of which 21% was oil and NGL. In response to the decline in ethane prices, QEP Energy began rejecting ethane from Pinedale production on December 1st. Ethane rejection results in approximately 7% less natural gas equivalent sales volumes but, at current ethane prices, has a negligible impact on gross revenues. The processing margins for Pinedale propane and heavier NGL components remain positive.
During the fourth quarter 2012, QEP Energy completed and turned to sales 16 new Pinedale wells, for a total of 102 new producing wells in 2012 (QEP Energy's average working interest 71%). QEP Energy 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 were suspended in November. At the end of 2012, the Company had 66 Pinedale wells awaiting completion.
Drilling and completion efficiencies have allowed QEP Energy to maintain industry-leading average gross completed well costs of approximately $4.2 million per well at Pinedale. For the year, drill times from spud to total depth averaged 12.8 days and a new record of 8.6 days was achieved.
At the end of 2012, QEP Energy had four rigs operating at Pinedale (including one rig working in an area of Pinedale where QEP Energy is the operator but does not own a working interest). The Company currently expects to complete a
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total of approximately 110 wells during 2013, including 29 wells in which QEP Energy is the designated operator but only owns a small overriding royalty interest.
Please refer to slide 9 for additional details on the Company's Pinedale operations.
Uinta Basin: Continued development drilling in the liquids-rich Lower Mesaverde Play
During the fourth quarter 2012, Uinta Basin net production averaged 75 MMcfed of which 35 MMcfed was from the Lower Mesaverde play. In response to the decline in ethane prices, QEP Energy also commenced rejecting ethane from Uinta Basin gas production in the quarter. Ethane rejection results in approximately 7% less natural gas equivalent sales volumes but, at current ethane prices, has a negligible impact on gross revenues. The processing margins for Uinta Basin propane and heavier NGL components remain positive.
QEP Energy commenced development drilling with two rigs on “Pinedale-style” multi-well pads in the Lower Mesaverde play during the fourth quarter and initially plans to drill 20-acre density development wells. The pads and wellbore geometries will be designed to allow for future 10-acre density development wells. A seven well pilot program is currently underway to ascertain the reserve potential of tighter, 10-acre density development. Average measured depth for a typical Lower Mesaverde well is approximately 11,000 feet.
At the end of 2012, the Company had 57 producing wells in the Lower Mesaverde play, eight of which were completed and turned to sales during the fourth quarter for a total of 37 wells during 2012 (QEP Energy's 100% working interest). QEP Energy has over 3,200 potential remaining locations in this significant liquids-rich gas resource play.
In addition to Lower Mesaverde activity, at the end of 2012 the Company had one rig drilling horizontal and vertical wells targeting multiple oil-bearing limestone and sandstone reservoirs in the Lower Green River Formation, at an average true vertical depth of 5,500 feet. During 2012, QEP Energy completed 10 Company-operated oil wells (four vertical and six horizontal) in the Uinta Basin (QEP Energy's average working interest 72%).
Slides 10 and 11 depict QEP Energy's acreage and additional details of the Lower Mesaverde play.
Woodford “Cana”: Currently drilling 80-acre density development wells in the liquids-rich core of the play
QEP Energy's net production from the Woodford “Cana” play averaged 48 MMcfed during the fourth quarter 2012. The Company participated in 21 outside-operated horizontal Woodford “Cana” Shale wells that were completed and turned to sales during the fourth quarter (QEP Energy's working interests ranging from less than 1% to 13%).
At the end of the year, QEP Energy operated 33 producing horizontal Cana wells (QEP Energy's average working interest 73%) and had working interests in an additional 258 outside-operated producing Cana wells (QEP Energy's average working interest 10%).
At the end of 2012, the Company had two operated rigs drilling 80-acre horizontal infill development wells (QEP Energy's average working interest 75%) and there were eight QEP Energy-operated 80-acre infill wells in one section awaiting completion (QEP Energy's working interest 100%). QEP Energy also has a working interest in 26 outside-operated wells awaiting completion (QEP Energy's working interests ranging from 1% to 4%).
Slide 12 depicts QEP Energy's acreage and additional details of the Cana play.
Granite Wash: Horizontal development in the Texas Panhandle
QEP Energy's net production from the Texas Panhandle Granite Wash play averaged 37 MMcfed during the fourth quarter 2012. During the fourth quarter 2012, QEP Energy participated in six outside-operated well completions in the Kansas City and Lansing formations in the Texas Panhandle (QEP Energy's average working interest 1.4%). At the end of 2012 the Company had one QEP Energy-operated Cherokee Formation horizontal well awaiting completion (QEP Energy's working interest 59%), one QEP Energy-operated Caldwell Formation well drilling (QEP Energy's working interest 59%) and had
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interests in four outside-operated Granite Wash wells awaiting completion (QEP Energy's working interests ranging from 12% to 24%). At the end of the fourth quarter, QEP Energy had a working interest in a total of 95 producing horizontal Granite Wash/Atoka Wash wells.
See slide 13 for details on the Granite Wash play.
Haynesville: No operated drilling activity in the Haynesville Shale play of NW Louisiana
The Company's net Haynesville production averaged 238 MMcfed and Cotton Valley/Hosston net production averaged 40 MMcfed during the fourth quarter 2012.
At the end of 2012, QEP Energy operated 126 producing wells in the play and had working interests in 124 outside-operated producing wells.
In response to depressed natural gas prices, QEP Energy released its last operated drilling rig in the Haynesville Shale play in early July 2012, and did not complete any additional Company-operated Haynesville wells after April 2012. QEP Energy had five operated wells (48% average working interest) awaiting completion at the end of 2012. The Company participated in one outside-operated Haynesville well that was completed in the fourth quarter (QEP Energy's working interest 2%).
Refer to slide 14 for additional information on QEP Energy's Haynesville activities.
QEP Field Services
QEP Field Services’ fourth quarter 2012 NGL sales volumes were down 45%, fee-based processing volumes were up 4%, and gathering volumes were down 7%, compared to the prior-year quarter.
Processing margin (total processing plant revenues less plant shrink, transportation, fractionation, and operating expenses) was $29.0 million in the fourth quarter 2012 compared to $53.6 million in the fourth quarter 2011, a 46% decrease. The fourth quarter 2012 was negatively impacted by a 64% decrease in keep-whole processing margins (NGL sales revenues less shrink, transportation and fractionation expenses), due primarily to lower NGL prices. Fee-based processing revenues were $18.3 million in the fourth quarter 2012, a 10% increase from the prior year period due to increases in total fee-based processing volumes and average revenue per MMBtu.
Gathering margin (total gathering revenues less gathering related operating expenses) was $38.8 million in the fourth quarter 2012 compared to $41.1 million in the fourth quarter 2011, a 6% decrease, due primarily to a decrease in other gathering revenue and a decline in gathering volumes between the two periods.
Approximately 81% of QEP Field Services’ fourth quarter 2012 net operating revenue was derived from fee-based gathering and processing activities compared to 62% in the fourth quarter 2011.
Construction on Iron Horse II, a 150 MMcfed cryogenic gas processing plant in the Uinta Basin, is proceeding as planned. The plant is in the process of startup and commissioning and is expected to be put into service during February 2013. This new facility is contracted under long-term, fee-based processing agreements with half of the capacity dedicated to a third-party customer and the remaining capacity available to QEP Energy and third-party customers.
During the fourth quarter, construction continued on QEP Field Services' 10,000 barrel per day NGL fractionation facility expansion at QEP’s Blacks Fork facility in southwest Wyoming. When completed 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.
Estimates of key financial and operating data follows.
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Fourth Quarter 2012 Results Conference Call
QEP Resources’ management will discuss fourth quarter and full year 2012 results in a conference call on Wednesday, February 20, 2013, beginning at 9:00 a.m. EST. The conference call can be accessed at www.qepres.com. You may also participate in the conference call by dialing (877) 869-3847 in the U.S. or Canada and (201) 689-8261 for international calls. A replay of the teleconference will be available on the website immediately after the call through March 21, 2013, 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 # 407780. In addition, QEP’s slides for the fourth 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 2013 and related assumptions for such guidance; plans to drill and complete wells; estimated average gross completed well costs; estimated reserves; average estimated ultimate recoveries per well and strong well performance; completion dates and capacity for new projects of QEP Field Services; remaining locations to drill wells; ability to profitably grow crude oil production from newly acquired properties; ethane rejection and its impact; plans to double railcar loading capacity; and estimated accrual for litigation loss contingencies. 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; 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; 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; inability to successfully integrate acquired assets; inadequate supplies of water and/or lack of water disposal sources; and the other risks discussed in the Company’s periodic filings with the Securities and Exchange Commission, including the Risk Factors section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2012. 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, 2012, and in other reports on file with the SEC.
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QEP RESOURCES, INC. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||
Three Months Ended | Year Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
REVENUES | (in millions, except per share amounts) | ||||||||||||||
Natural gas sales | $ | 197.0 | $ | 318.0 | $ | 667.4 | $ | 1,239.1 | |||||||
Oil sales | 196.9 | 103.6 | 532.6 | 324.2 | |||||||||||
NGL sales | 75.1 | 118.8 | 322.1 | 309.8 | |||||||||||
Gathering, processing and other | 39.7 | 38.2 | 181.6 | 200.8 | |||||||||||
Purchased gas, oil and NGL sales | 196.2 | 274.7 | 646.1 | 1,085.3 | |||||||||||
Total Revenues | 704.9 | 853.3 | 2,349.8 | 3,159.2 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Purchased gas, oil and NGL expense | 199.7 | 273.8 | 655.6 | 1,077.1 | |||||||||||
Lease operating expense | 49.5 | 41.1 | 172.3 | 145.2 | |||||||||||
Natural gas, oil and NGL transport & other handling costs(1) | 37.4 | 29.0 | 148.9 | 102.2 | |||||||||||
Gathering, processing and other | 21.6 | 27.9 | 88.0 | 107.3 | |||||||||||
General and administrative | 152.1 | 34.1 | 266.6 | 123.2 | |||||||||||
Production and property taxes | 35.0 | 26.9 | 103.4 | 105.4 | |||||||||||
Depreciation, depletion and amortization | 257.5 | 199.0 | 904.9 | 765.4 | |||||||||||
Exploration expenses | 4.9 | 3.0 | 11.2 | 10.5 | |||||||||||
Abandonment and impairment | 61.6 | 202.0 | 133.4 | 218.4 | |||||||||||
Total Operating Expenses | 819.3 | 836.8 | 2,484.3 | 2,654.7 | |||||||||||
Net gain from asset sales | (0.3 | ) | — | 1.2 | 1.4 | ||||||||||
OPERATING (LOSS) INCOME | (114.7 | ) | 16.5 | (133.3 | ) | 505.9 | |||||||||
Realized and unrealized gains on derivative contracts(2) | 107.2 | — | 441.9 | — | |||||||||||
Interest and other income | 4.2 | 4.6 | 6.6 | 4.1 | |||||||||||
Income from unconsolidated affiliates | 1.2 | 1.0 | 6.8 | 5.5 | |||||||||||
Loss from early extinguishment of debt | — | — | (0.6 | ) | (0.7 | ) | |||||||||
Interest expense | (40.0 | ) | (23.0 | ) | (122.9 | ) | (90.0 | ) | |||||||
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (42.1 | ) | (0.9 | ) | 198.5 | 424.8 | |||||||||
Income taxes | 20.0 | 1.6 | (66.5 | ) | (154.4 | ) | |||||||||
NET (LOSS) INCOME | (22.1 | ) | 0.7 | 132.0 | 270.4 | ||||||||||
Net income attributable to noncontrolling interest | (1.0 | ) | (1.0 | ) | (3.7 | ) | (3.2 | ) | |||||||
NET (LOSS) INCOME ATTRIBUTABLE TO QEP | $ | (23.1 | ) | $ | (0.3 | ) | $ | 128.3 | $ | 267.2 | |||||
Earnings Per Common Share Attributable to QEP | |||||||||||||||
Basic from continuing operations | $ | (0.13 | ) | $ | (0.01 | ) | $ | 0.72 | $ | 1.51 | |||||
Diluted from continuing operations | $ | (0.13 | ) | $ | — | $ | 0.72 | $ | 1.50 | ||||||
Weighted-average common shares outstanding | |||||||||||||||
Used in basic calculation | 178.3 | 176.7 | 177.8 | 176.5 | |||||||||||
Used in diluted calculation | 178.3 | 178.2 | 178.7 | 178.4 | |||||||||||
(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 year ended December 31, 2012, commodity derivative realized gains and losses from derivative contract settlements were included in "Realized and unrealized gains on derivative contracts" whereas during the year ended December 31, 2011, commodity derivative gains and losses from derivative contract settlements were included in each of the respective revenue categories. | |||||||||||||||
10
QEP RESOURCES, INC. CONDENSED CONSOLIDATED BALANCE SHEETS | |||||||
December 31, 2012 | December 31, 2011 | ||||||
ASSETS | (in millions) | ||||||
Current Assets | |||||||
Cash and cash equivalents | $ | — | $ | — | |||
Accounts receivable, net | 387.5 | 397.4 | |||||
Fair value of derivative contracts | 188.7 | 273.7 | |||||
Gas, oil and NGL inventories, at lower of average cost or market | 13.1 | 16.2 | |||||
Prepaid expenses and other | 60.4 | 43.7 | |||||
Total Current Assets | 649.7 | 731.0 | |||||
Property, Plant and Equipment (successful efforts method for gas and oil properties) | |||||||
Proved properties | 10,234.3 | 8,172.4 | |||||
Unproved properties, net | 937.9 | 326.8 | |||||
Midstream field services | 1,634.9 | 1,463.6 | |||||
Marketing and other | 64.6 | 49.8 | |||||
Materials and supplies | 61.9 | 87.6 | |||||
Total Property, Plant and Equipment | 12,933.6 | 10,100.2 | |||||
Less Accumulated Depreciation, Depletion and Amortization | |||||||
Exploration and production | 4,258.1 | 3,339.2 | |||||
Midstream field services | 357.9 | 297.5 | |||||
Marketing and other | 18.1 | 14.6 | |||||
Total Accumulated Depreciation, Depletion and Amortization | 4,634.1 | 3,651.3 | |||||
Net Property, Plant and Equipment | 8,299.5 | 6,448.9 | |||||
Investment in unconsolidated affiliates | 41.2 | 42.2 | |||||
Goodwill | 59.5 | 59.5 | |||||
Fair value of derivative contracts | 4.1 | 123.5 | |||||
Other noncurrent assets | 54.5 | 37.6 | |||||
TOTAL ASSETS | $ | 9,108.5 | $ | 7,442.7 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Checks outstanding in excess of cash balances | $ | 39.7 | $ | 29.4 | |||
Accounts payable and accrued expenses | 635.9 | 457.3 | |||||
Production and property taxes | 41.8 | 40.0 | |||||
Interest payable | 36.9 | 24.4 | |||||
Fair value of derivative contracts | 2.6 | 1.3 | |||||
Deferred income taxes | 5.0 | 85.4 | |||||
Total Current Liabilities | 761.9 | 637.8 | |||||
Long-term debt | 3,206.9 | 1,679.4 | |||||
Deferred income taxes | 1,493.5 | 1,484.7 | |||||
Asset retirement obligations | 191.4 | 163.9 | |||||
Fair value of derivative contracts | 3.6 | — | |||||
Other long-term liabilities | 137.5 | 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 - 0.1 million and 0.4 million shares, respectively | (3.7 | ) | (13.1 | ) | |||
Additional paid-in capital | 462.1 | 431.4 | |||||
Retained earnings | 2,773.0 | 2,673.5 | |||||
Accumulated other comprehensive income | 32.8 | 207.9 | |||||
Total Common Shareholders' Equity | 3,266.0 | 3,301.5 | |||||
Noncontrolling interest | 47.7 | 50.6 | |||||
Total Equity | 3,313.7 | 3,352.1 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 9,108.5 | $ | 7,442.7 | |||
11
QEP RESOURCES, INC. CONSOLIDATED CASH FLOWS | |||||||
Year Ended | |||||||
December 31, | |||||||
2012 | 2011 | ||||||
(in millions) | |||||||
OPERATING ACTIVITIES | |||||||
Net income | $ | 132.0 | $ | 270.4 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 904.9 | 765.4 | |||||
Deferred income taxes | 32.1 | 156.8 | |||||
Abandonment and impairment | 133.4 | 218.4 | |||||
Share-based compensation | 25.6 | 22.0 | |||||
Amortization of debt issuance costs and discounts | 5.3 | 4.1 | |||||
Net gain from asset sales | (1.2 | ) | (1.4 | ) | |||
Income from unconsolidated affiliates | (6.8 | ) | (5.5 | ) | |||
Distributions from unconsolidated affiliates and dry exploratory well expense | 7.9 | 8.1 | |||||
Non-cash loss on early extinguishment of debt | — | 0.7 | |||||
Unrealized gain on derivative contracts | (63.2 | ) | (117.7 | ) | |||
Changes in operating assets and liabilities | 126.0 | (28.7 | ) | ||||
Net Cash Provided by Operating Activities of Continuing Operations | 1,296.0 | 1,292.6 | |||||
INVESTING ACTIVITIES | |||||||
Property acquisitions | (1,401.0 | ) | (48.0 | ) | |||
Property, plant and equipment, including dry hole exploratory well expense | (1,398.7 | ) | (1,383.1 | ) | |||
Proceeds from disposition of assets | 5.2 | 8.2 | |||||
Net Cash Used in Investing Activities of Continuing Operations | (2,794.5 | ) | (1,422.9 | ) | |||
FINANCING ACTIVITIES | |||||||
Checks outstanding in excess of cash balances | 10.3 | 9.9 | |||||
Long-term debt issued | 1,450.0 | — | |||||
Long-term debt issuance costs paid | (17.8 | ) | (10.6 | ) | |||
Long-term debt repaid | (6.7 | ) | (58.5 | ) | |||
Proceeds from credit facility | 1,234.5 | 591.5 | |||||
Repayments of credit facility | (1,151.0 | ) | (385.0 | ) | |||
Other capital contributions | (2.2 | ) | 0.7 | ||||
Dividends paid | (14.2 | ) | (14.1 | ) | |||
Excess tax benefit on share-based compensation | 2.2 | 1.6 | |||||
Distribution from Questar | — | 0.2 | |||||
Distribution to noncontrolling interest | (6.6 | ) | (5.4 | ) | |||
Net Cash Provided by Financing Activities of Continuing Operations | 1,498.5 | 130.3 | |||||
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 QEP Energy - Production by Region | |||||||||||||||||
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||
(in Bcfe) | |||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||
Northern Region | |||||||||||||||||
Pinedale | 25.8 | 23.8 | 8 | % | 99.7 | 79.4 | 26 | % | |||||||||
Williston Basin(1) | 10.1 | 2.7 | 274 | % | 20.3 | 7.1 | 186 | % | |||||||||
Uinta Basin(2) | 7.0 | 4.6 | 52 | % | 23.9 | 20.8 | 15 | % | |||||||||
Legacy | 3.3 | 3.5 | (6 | )% | 13.7 | 14.2 | (4 | )% | |||||||||
Total Northern Region | 46.2 | 34.6 | 34 | % | 157.6 | 121.5 | 30 | % | |||||||||
Southern Region | |||||||||||||||||
Haynesville/Cotton Valley | 25.5 | 26.6 | (4 | )% | 112.3 | 107.5 | 4 | % | |||||||||
Midcontinent | 12.2 | 12.7 | (4 | )% | 49.3 | 46.2 | 7 | % | |||||||||
Total Southern Region | 37.7 | 39.3 | (4 | )% | 161.6 | 153.7 | 5 | % | |||||||||
Total production | 83.9 | 73.9 | 14 | % | 319.2 | 275.2 | 16 | % | |||||||||
(1) Results for the three and twelve months ended December 31, 2012, include increased production due to the North Dakota Acquisition. | |||||||||||||||||
(2) 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 December 31, | Year Ended December 31, | ||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||
QEP Energy Production Volumes | |||||||||||||||||
Natural gas (Bcf) | 61.3 | 60.5 | 1 | % | 249.3 | 236.4 | 5 | % | |||||||||
Oil (Mbbl) | 2,333.8 | 1,182.1 | 97 | % | 6,306.9 | 3,741.3 | 69 | % | |||||||||
NGL (Mbbl) | 1,442.8 | 1,040.6 | 39 | % | 5,349.0 | 2,715.6 | 97 | % | |||||||||
Total production (Bcfe) | 83.9 | 73.9 | 14 | % | 319.2 | 275.2 | 16 | % | |||||||||
Average daily production (MMcfe) | 911.9 | 803.3 | 14 | % | 872.1 | 753.9 | 16 | % | |||||||||
13
QEP Energy - Prices(1) | |||||||||||||||||||||
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
2012(2) | 2011(3) | Change | 2012 | 2011 | Change | ||||||||||||||||
Natural gas (per Mcf) | |||||||||||||||||||||
Average field-level price | $ | 3.22 | $ | 3.66 | $ | 2.68 | $ | 3.95 | |||||||||||||
Commodity derivative impact | 0.94 | 1.08 | 1.37 | 0.79 | |||||||||||||||||
Net realized price | $ | 4.16 | $ | 4.74 | (12 | )% | $ | 4.05 | $ | 4.74 | (15 | )% | |||||||||
Oil (per bbl) | |||||||||||||||||||||
Average field-level price | 84.38 | 87.01 | 84.45 | 86.20 | |||||||||||||||||
Commodity derivative impact | 5.23 | 0.55 | 2.28 | 0.43 | |||||||||||||||||
Net realized price | $ | 89.61 | $ | 87.56 | 2 | % | $ | 86.73 | $ | 86.63 | — | % | |||||||||
NGL (per bbl) | |||||||||||||||||||||
Average field-level price | 34.55 | 56.34 | 34.43 | 47.76 | |||||||||||||||||
Commodity derivative impact | 2.56 | — | 1.90 | — | |||||||||||||||||
Net realized price | $ | 37.11 | $ | 56.34 | (34 | )% | $ | 36.33 | $ | 47.76 | (24 | )% | |||||||||
Average net equivalent price (per Mcfe) | |||||||||||||||||||||
Average field-level price | 5.29 | 5.18 | 4.34 | 5.04 | |||||||||||||||||
Commodity derivative impact | 0.88 | 0.90 | 1.14 | 0.68 | |||||||||||||||||
Net realized price | $ | 6.17 | $ | 6.08 | 1 | % | $ | 5.48 | $ | 5.72 | (4 | )% | |||||||||
(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 December 31, | Year Ended December 31, | ||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||
(per Mcfe) | |||||||||||||||||||||
Depreciation, depletion and amortization | $ | 2.87 | $ | 2.48 | 16 | % | $ | 2.63 | $ | 2.57 | 2 | % | |||||||||
Lease operating expense | 0.60 | 0.57 | 5 | % | 0.55 | 0.54 | 2 | % | |||||||||||||
Natural gas, oil and NGL transport & other handling costs | 0.72 | 0.75 | (4 | )% | 0.71 | 0.68 | 4 | % | |||||||||||||
General and administrative expense (1) | 1.71 | 0.39 | 338 | % | 0.74 | 0.36 | 106 | % | |||||||||||||
Allocated interest expense | 0.55 | 0.29 | 90 | % | 0.37 | 0.30 | 23 | % | |||||||||||||
Production taxes | 0.40 | 0.34 | 18 | % | 0.30 | 0.36 | (17 | )% | |||||||||||||
Total Operating Expenses | $ | 6.85 | $ | 4.82 | 42 | % | $ | 5.30 | $ | 4.81 | 10 | % | |||||||||
(1) General and administrative expense for the three months and year ended December 31, 2012, includes a $104.2 million and $115 million, respectively, accrual for a litigation loss contingency. Excluding this charge, general and administrative expense for 2012 would have been $0.47/Mcfe and $0.38/Mcfe for fourth quarter and full year, respectively. | |||||||||||||||||||||
14
QEP Field Services | |||||||||||||||||||||
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||
QEP Field Services Gathering Operating Statistics | |||||||||||||||||||||
Natural gas gathering volumes (millions of MMBtu) | 119.6 | 128.4 | (7 | )% | 506.5 | 495.4 | 2 | % | |||||||||||||
Gathering revenue (per MMBtu) | $ | 0.35 | $ | 0.32 | 9 | % | $ | 0.34 | $ | 0.33 | 3 | % | |||||||||
QEP Field Services Gathering Margin (in millions) | |||||||||||||||||||||
Gathering | $ | 41.3 | $ | 41.1 | — | % | $ | 172.9 | $ | 161.1 | 7 | % | |||||||||
Other Gathering | 8.0 | 9.3 | (14 | )% | 36.6 | 68.5 | (47 | )% | |||||||||||||
Gathering (expense) | (10.5 | ) | (9.3 | ) | 13 | % | (37.4 | ) | (44.6 | ) | (16 | )% | |||||||||
Gathering margin | $ | 38.8 | $ | 41.1 | (6 | )% | $ | 172.1 | $ | 185.0 | (7 | )% | |||||||||
QEP Field Services Processing Margin (in millions) | |||||||||||||||||||||
NGL sales(1) | $ | 25.2 | $ | 60.1 | (58 | )% | $ | 137.9 | $ | 180.0 | (23 | )% | |||||||||
Realized gains from commodity derivative contract settlements | 2.1 | — | — | % | 8.4 | — | — | % | |||||||||||||
Processing (fee-based) revenues | 17.8 | 16.1 | 11 | % | 69.6 | 53.7 | 30 | % | |||||||||||||
Other processing revenues | 0.5 | 0.5 | — | % | 8.9 | 2.2 | 305 | % | |||||||||||||
Processing (expense) | (4.0 | ) | (3.3 | ) | 21 | % | (16.1 | ) | (12.2 | ) | 32 | % | |||||||||
Processing plant fuel and shrink (expense) | (6.7 | ) | (15.1 | ) | (56 | )% | (33.3 | ) | (49.2 | ) | (32 | )% | |||||||||
Natural gas, oil and NGL transport & other handling costs | (5.9 | ) | (4.7 | ) | 26 | % | (33.6 | ) | (9.3 | ) | 261 | % | |||||||||
Processing margin | $ | 29.0 | $ | 53.6 | (46 | )% | $ | 141.8 | $ | 165.2 | (14 | )% | |||||||||
Keep-whole processing margin(2) | $ | 14.7 | $ | 40.3 | (64 | )% | $ | 79.4 | $ | 121.5 | (35 | )% | |||||||||
Fee-based processing margin | $ | 14.3 | $ | 13.3 | 8 | % | $ | 62.4 | $ | 43.7 | 43 | % | |||||||||
QEP Field Services Processing Operating Statistics | |||||||||||||||||||||
Natural gas processing volumes | |||||||||||||||||||||
NGL sales (Mbbl) | 576.6 | 1,039.0 | (45 | )% | 3,470.3 | 3,376.4 | 3 | % | |||||||||||||
Average net realized NGL sales price (per Bbl)(3) | $ | 47.53 | $ | 57.91 | (18 | )% | $ | 42.18 | $ | 53.33 | (21 | )% | |||||||||
Total fee-based processing volumes (in millions of MMBtu) | 62.1 | 59.6 | 4 | % | 251.3 | 240.7 | 4 | % | |||||||||||||
Average fee-based processing revenue (per MMBtu) | $ | 0.28 | $ | 0.27 | 4 | % | $ | 0.28 | $ | 0.22 | 27 | % | |||||||||
(1) NGL sales for the three and twelve months ended December 31, 2011, have been recast to reflect QEP's revised reporting of its transportation and handling costs. In addition, revenues for the three and twelve months ended December 31, 2011, reflect the impact of QEP's settled derivative contracts which during the three and twelve months ended December 31, 2012, are reflected below operating (loss) income. | |||||||||||||||||||||
(2) Keep-whole processing margin is calculated as NGL sales less processing plant fuel and shrink, natural gas, oil and NGL transport, fractionation expense and other handling costs. | |||||||||||||||||||||
(3) Average net realized NGL sales price per barrel is calculated as NGL sales including realized gains from commodity derivative contracts settlements divided by NGL sales volumes. | |||||||||||||||||||||
15
QEP RESOURCES, INC.
NON-GAAP MEASURES
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, loss on early extinguishment of debt and accrued litigation loss contingency. 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.
The following tables reconcile QEP Resources’ and its subsidiaries’ net income to Adjusted EBITDA:
Three Months Ended | Year Ended | ||||||||||||||||||||||
December 31, | December 31, | ||||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||||
QEP Resources | (in millions) | ||||||||||||||||||||||
Net (loss) income attributable to QEP Resources | $ | (23.1 | ) | $ | (0.3 | ) | $ | (22.8 | ) | $ | 128.3 | $ | 267.2 | $ | (138.9 | ) | |||||||
Net income attributable to noncontrolling interest | 1.0 | 1.0 | — | 3.7 | 3.2 | 0.5 | |||||||||||||||||
Net (loss) income | (22.1 | ) | 0.7 | (22.8 | ) | 132.0 | 270.4 | (138.4 | ) | ||||||||||||||
Unrealized gains on derivative contracts | (30.4 | ) | (31.0 | ) | 0.6 | (63.2 | ) | (117.7 | ) | 54.5 | |||||||||||||
Net gain from asset sales | 0.3 | — | 0.3 | (1.2 | ) | (1.4 | ) | 0.2 | |||||||||||||||
Interest and other income | (4.2 | ) | (4.6 | ) | 0.4 | (6.6 | ) | (4.1 | ) | (2.5 | ) | ||||||||||||
Income tax (benefit) provision | (20.0 | ) | (1.6 | ) | (18.4 | ) | 66.5 | 154.4 | (87.9 | ) | |||||||||||||
Interest expense | 40.0 | 23.0 | 17.0 | 122.9 | 90.0 | 32.9 | |||||||||||||||||
Accrued litigation loss contingency | 104.2 | — | 104.2 | 115.0 | — | 115.0 | |||||||||||||||||
Loss on early extinguishment of debt | — | — | — | 0.6 | 0.7 | (0.1 | ) | ||||||||||||||||
Depreciation, depletion and amortization | 257.5 | 199.0 | 58.5 | 904.9 | 765.4 | 139.5 | |||||||||||||||||
Abandonment and impairment | 61.6 | 202.0 | (140.4 | ) | 133.4 | 218.4 | (85.0 | ) | |||||||||||||||
Exploration expenses | 4.9 | 3.0 | 1.9 | 11.2 | 10.5 | 0.7 | |||||||||||||||||
Adjusted EBITDA | $ | 391.8 | $ | 390.5 | $ | 1.3 | $ | 1,415.5 | $ | 1,386.6 | $ | 28.9 | |||||||||||
QEP Energy | |||||||||||||||||||||||
Net (loss) income attributable to QEP Energy | $ | (52.3 | ) | $ | (43.5 | ) | $ | (8.8 | ) | $ | (0.7 | ) | $ | 104.7 | $ | (105.4 | ) | ||||||
Unrealized gains on derivative contracts | (30.5 | ) | (31.0 | ) | 0.5 | (68.4 | ) | (117.7 | ) | 49.3 | |||||||||||||
Net gain from asset sales | 0.3 | — | 0.3 | (1.2 | ) | (1.4 | ) | 0.2 | |||||||||||||||
Interest and other income | (4.0 | ) | (4.5 | ) | 0.5 | (6.2 | ) | (4.0 | ) | (2.2 | ) | ||||||||||||
Income tax (benefit) provision | (36.7 | ) | (29.8 | ) | (6.9 | ) | (4.3 | ) | 57.9 | (62.2 | ) | ||||||||||||
Interest expense | 45.7 | 21.1 | 24.6 | 116.8 | 81.9 | 34.9 | |||||||||||||||||
Accrued litigation loss contingency | 104.2 | — | 104.2 | 115.0 | — | 115.0 | |||||||||||||||||
Depreciation, depletion and amortization | 240.3 | 183.2 | 57.1 | 838.0 | 707.2 | 130.8 | |||||||||||||||||
Abandonment and impairment | 61.6 | 202.0 | (140.4 | ) | 133.4 | 218.4 | (85.0 | ) | |||||||||||||||
Exploration expenses | 4.9 | 3.0 | 1.9 | 11.2 | 10.5 | 0.7 | |||||||||||||||||
Adjusted EBITDA | $ | 333.5 | $ | 300.5 | $ | 33.0 | $ | 1,133.6 | $ | 1,057.5 | $ | 76.1 | |||||||||||
16
Three Months Ended | Year Ended | ||||||||||||||||||||||
December 31, | December 31, | ||||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||||
QEP Field Services | (in millions) | ||||||||||||||||||||||
Net income attributable to QEP Field Services | $ | 21.6 | $ | 40.3 | $ | (18.7 | ) | $ | 129.0 | $ | 154.5 | $ | (25.5 | ) | |||||||||
Net income attributable to noncontrolling interest | 1.0 | 1.0 | — | 3.7 | 3.2 | 0.5 | |||||||||||||||||
Net income | 22.6 | 41.3 | (18.7 | ) | 132.7 | 157.7 | (25.0 | ) | |||||||||||||||
Unrealized losses on derivative contracts | 2.0 | — | 2.0 | — | — | — | |||||||||||||||||
Interest and other income | (0.1 | ) | (0.1 | ) | — | (0.2 | ) | (0.1 | ) | (0.1 | ) | ||||||||||||
Income tax provision | 12.6 | 27.8 | (15.2 | ) | 71.8 | 93.4 | (21.6 | ) | |||||||||||||||
Interest expense | 4.2 | 3.2 | 1.0 | 13.6 | 13.6 | — | |||||||||||||||||
Depreciation, depletion and amortization | 16.0 | 15.0 | 1.0 | 63.2 | 55.7 | 7.5 | |||||||||||||||||
Adjusted EBITDA | $ | 57.3 | $ | 87.2 | $ | (29.9 | ) | $ | 281.1 | $ | 320.3 | $ | (39.2 | ) | |||||||||
QEP Marketing & Other | |||||||||||||||||||||||
Net income attributable to QEP Marketing and other | $ | 7.6 | $ | 2.9 | $ | 4.7 | $ | — | $ | 8.0 | $ | (8.0 | ) | ||||||||||
Unrealized (gains) losses on derivative contracts | (1.9 | ) | — | (1.9 | ) | 5.2 | — | 5.2 | |||||||||||||||
Other income | (0.1 | ) | — | (0.1 | ) | (0.2 | ) | — | (0.2 | ) | |||||||||||||
Income tax provision (benefit) | 4.1 | 0.4 | 3.7 | (1.0 | ) | 3.1 | (4.1 | ) | |||||||||||||||
Interest expense | (9.9 | ) | (1.3 | ) | (8.6 | ) | (7.5 | ) | (5.5 | ) | (2.0 | ) | |||||||||||
Loss on early extinguishment of debt | — | — | — | 0.6 | 0.7 | (0.1 | ) | ||||||||||||||||
Depreciation, depletion and amortization | 1.2 | 0.8 | 0.4 | 3.7 | 2.5 | 1.2 | |||||||||||||||||
Adjusted EBITDA | $ | 1.0 | $ | 2.8 | $ | (1.8 | ) | $ | 0.8 | $ | 8.8 | $ | (8.0 | ) | |||||||||
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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, accrued litigation loss contingency, costs from early extinguishment of debt and non-cash price-related asset impairments. 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 | Year Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||
(in millions, except per earnings per share) | |||||||||||||||
Net (loss) income attributable to QEP Resources | $ | (23.1 | ) | $ | (0.3 | ) | $ | 128.3 | $ | 267.2 | |||||
Adjustments to net income | |||||||||||||||
Net gain from asset sales | 0.3 | — | (1.2 | ) | (1.4 | ) | |||||||||
Income taxes on net gain on asset sales | (0.1 | ) | — | 0.4 | 0.5 | ||||||||||
Unrealized gains on derivative contracts | (30.4 | ) | (31.0 | ) | (63.2 | ) | (117.7 | ) | |||||||
Income taxes on unrealized gains on derivative contracts | 11.1 | 11.2 | 23.4 | 42.5 | |||||||||||
Accrued litigation loss contingency | 104.2 | — | 115.0 | — | |||||||||||
Income taxes on accrued litigation loss contingency | (38.8 | ) | — | (42.8 | ) | — | |||||||||
Loss on early extinguishment of debt | — | — | 0.6 | 0.7 | |||||||||||
Income taxes on loss from early extinguishment of debt | — | — | (0.2 | ) | (0.3 | ) | |||||||||
Non-cash price-related impairment charge | 58.3 | 195.2 | 107.6 | 195.2 | |||||||||||
Income taxes on non-cash price-related impairment charge | (21.7 | ) | (70.5 | ) | (40.0 | ) | (70.5 | ) | |||||||
Total after-tax adjustments to net income | 82.9 | 104.9 | 99.6 | 49.0 | |||||||||||
Adjusted net income attributable to QEP Resources | $ | 59.8 | $ | 104.6 | $ | 227.9 | $ | 316.2 | |||||||
Earnings per Common Share attributable to QEP | |||||||||||||||
Diluted earnings per share | $ | (0.13 | ) | $ | — | $ | 0.72 | $ | 1.50 | ||||||
Diluted after-tax adjustments to net income per share | 0.46 | 0.58 | 0.56 | 0.27 | |||||||||||
Diluted Adjusted Net Income per share | $ | 0.33 | $ | 0.58 | $ | 1.28 | $ | 1.77 | |||||||
Weighted-average common shares outstanding | |||||||||||||||
Diluted(1) | 178.9 | 178.2 | 178.7 | 178.4 | |||||||||||
Weighted-average common shares outstanding diluted Non-GAAP reconciliation(1) | |||||||||||||||
Weighted-average common shares outstanding used in GAAP diluted calculation | 178.3 | ||||||||||||||
Potential number of shares issuable upon exercise of in-the-money stock options under the long-term stock incentive plan | 0.6 | ||||||||||||||
Weighted-average common shares outstanding used in Non- GAAP diluted calculation | 178.9 | ||||||||||||||
(1) The three months ended December 31, 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 December 31, 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 2013 derivative positions as of February 12, 2013:
QEP Energy Commodity Derivative Positions | |||||||||||
Year | Type of Contract | Index | Total Volumes | Average price per unit | |||||||
(in millions) | |||||||||||
Natural gas sales | (MMBtu) | ||||||||||
2013 | Swap | NYMEX | 51.10 | $ | 3.79 | ||||||
2013 | Swap | IFNPCR (1) | 65.70 | $ | 5.66 | ||||||
2014 | Swap | NYMEX | 18.25 | $ | 4.21 | ||||||
2014 | Swap | IFNPCR | 7.30 | $ | 4.00 | ||||||
Oil sales | (Bbls) | ||||||||||
2013 | Swap | NYMEX WTI | 5.72 | $ | 98.35 | ||||||
2013 | Swap | Brent | 0.33 | $ | 107.80 | ||||||
2014 | Swap | NYMEX WTI | 4.75 | $ | 92.99 | ||||||
(1) IFNPCR - Inside FERC monthly settlement index for the Northwest Pipeline Corp. Rocky Mountains. | |||||||||||
QEP Marketing Commodity Derivative Positions | |||||||||||
Year | Type of Contract | Index | Total Volumes | Average price per MMBtu | |||||||
(in millions) | |||||||||||
Natural gas sales | (MMBtu) | ||||||||||
2013 | Swap | IFNPCR | 4.03 | $ | 3.78 | ||||||
Natural gas purchases | (MMBtu) | ||||||||||
2013 | Swap | IFNPCR | 0.16 | $ | 2.88 | ||||||
2014 | Swap | IFNPCR | 0.04 | $ | 3.02 | ||||||
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