News ReleaseInvestors: Greg Bensen
Director, Investor Relations
303-405-6665
QEP RESOURCES REPORTS FIRST QUARTER 2013 FINANCIAL AND OPERATING RESULTS
DENVER — April 30, 2013 // QEP Resources, Inc. (NYSE: QEP) ("QEP" or the "Company") today reported first quarter 2013 financial and operating results. The Company reported a net loss during the first quarter 2013 of $4.3 million, or $0.02 per diluted share, compared to net income of $155.2 million, or $0.87 earnings per diluted share, in the first quarter 2012. 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, non-cash price-related impairment charges, and certain significant accrued litigation loss contingencies. Excluding these items, the Company’s Adjusted Net Income (a non-GAAP measure) was $49.4 million, or $0.28 per diluted share, for the first quarter 2013, compared to $78.1 million, or $0.44 per diluted share, for the comparable 2012 period. The lower Adjusted Net Income was due primarily to lower midstream NGL revenue and higher depreciation, depletion and amortization and other expenses in the first quarter 2013 compared to 2012.
Adjusted EBITDA (a non-GAAP measure) for the first quarter 2013 was $375.0 million, compared to $350.7 million in the first quarter 2012. A reconciliation of Adjusted EBITDA and Adjusted Net Income to net income is provided within the financial tables of this release.
First Quarter 2013 Highlights
▪ | QEP Energy reported net production of 78.0 Bcfe, an increase of 5% over 2012. QEP Energy's crude oil production increased 75% over the first quarter 2012. |
▪ | Crude oil and NGL comprised 25% of QEP Energy's production compared to 20% in the first quarter 2012. |
▪ | Crude oil and NGL revenue represented 55% of QEP Energy's field level revenue. |
▪ | QEP Field Services' fee-based revenue increased 12% compared to 2012. |
"We continue to make good progress on our efforts to grow QEP's crude oil production," said Chuck Stanley, Chairman, President and CEO of QEP Resources. "QEP Energy's crude oil production increased 75% compared to a year ago. Excluding the contribution from our recent North Dakota acquisition, crude oil volumes grew 29% from last year. Crude oil represented 16% of total production, up from just 10% one year ago. While QEP Energy's NGL sales volumes decreased 23% from the fourth quarter due to the impact of ethane rejection, NGL revenue was up slightly on a higher per-barrel NGL price resulting from a reduced volume of lower value ethane. Most importantly, the impact of increased crude oil volumes can be seen in QEP Energy's financial performance, with Adjusted EBITDA up 21% from a year ago despite flat net realized natural gas prices.
"QEP Energy's production was up 5% from a year ago, but as expected, production volumes declined from fourth quarter levels due to our typical suspension of completion activities at Pinedale during the coldest winter months and a shift to pad drilling on our recently acquired South Antelope properties in North Dakota," continued Stanley. "With resumption of completion activity late in the first quarter and planned activity through 2013, we expect to deliver crude oil production
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growth of at least 70% in 2013. While the recent increase in natural gas prices is encouraging and makes our deep portfolio of natural gas assets more valuable, we do not plan to shift capital away from the strong returns of our crude oil dominant properties at this time.
"QEP Field Services fee-based processing revenue increased 12% from the first quarter 2012. However, financial performance was challenged by lower keep-whole margin resulting from substantially weaker market prices for NGL components such as ethane and propane and increased natural gas prices. Field Services new Iron Horse II cryogenic processing plant is now fully operational and the 10,000 barrel per day expansion of our fractionator at Blacks Fork remains on track for a mid-2013 startup," concluded Stanley.
QEP Financial Results Summary
Adjusted EBITDA by Subsidiary | ||||||||||
Three Months Ended | ||||||||||
March 31, | ||||||||||
2013 | 2012 | Change | ||||||||
(in millions) | ||||||||||
QEP Energy | $ | 323.7 | $ | 267.8 | 21 | % | ||||
QEP Field Services | 53.2 | 82.9 | (36 | )% | ||||||
QEP Marketing and other | (1.9 | ) | — | — | % | |||||
Adjusted EBITDA(1) | $ | 375.0 | $ | 350.7 | 7 | % | ||||
(1) See attached schedule for a reconciliation of Adjusted EBITDA to net income. | ||||||||||
QEP Energy
▪ | Total net equivalent natural gas, crude oil and NGL production increased 5% to 78.0 Bcfe in the first quarter 2013 compared to 74.2 Bcfe in 2012. Crude oil production increased 75% while natural gas and NGL production decreased 2% and 9%, respectively, in the first quarter 2013 compared to 2012. |
▪ | Adjusted EBITDA increased 21% compared to the first quarter 2012, driven by the 5% increase in production volumes and 5% and 11% increases in the net realized price for oil and NGL, respectively. |
▪ | Crude oil and NGL revenues increased 52% compared to the first quarter 2012 and represented approximately 55% of field-level production revenues. |
▪ | Capital investment (on an accrual basis) for the first quarter 2013, was $325.4 million including $23.6 million of acquisitions. |
▪ | In April 2013, the Company entered into Purchase and Sale Agreements related to the disposition of some of its non-core properties in the Northern Region for total consideration of $145.0 million before purchase price adjustments. The Company expects to record a gain on the sale of these assets of approximately $100.0 million and anticipates closing the transactions in the second quarter 2013. |
▪ | Slides with maps and other supporting materials for the first quarter 2013 results 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 36% in the first quarter 2013 compared to the prior-year period, due primarily to lower processing margins driven by weaker NGL component prices, higher natural gas prices and a 68% decrease in NGL sales volumes as a result of ethane rejection (where ethane is left in the production stream and sold as natural gas instead of being recovered as an NGL) and a 10% decrease in natural gas gathering volumes as a result of declining dry gas production volumes on our Haynesville gathering system. |
▪ | Capital investment (on an accrual basis) for the first quarter 2013 totaled $12.0 million. |
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QEP 2013 Guidance
QEP Resources has revised its full-year 2013 guidance due to changes in commodity prices. The guidance incorporates commodity price derivative positions in place on the date of this release, assumes ethane rejection for all of 2013, and includes 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) | $1,575 - $1,675 | $1,500 - $1,650 | |
QEP Energy capital investment | $1,480 - $1,580 | $1,480 - $1,580 | |
QEP Field Services capital investment | $120 | $120 | |
QEP Marketing capital investment | $1 | $0 | |
Corporate capital investment | $24 | $25 | |
Total QEP Resources capital investment | $1,625 - $1,725 | $1,625 - $1,725 | |
QEP Energy production - Bcfe(2) | 315 - 320 | 325 - 330 | |
NYMEX gas price per MMBtu(3) | $3.75 - $4.50 | $3.25 - $4.25 | |
NYMEX crude oil price per bbl(3) | $85.00 - $95.00 | $90.00 - $100.00 | |
NYMEX/Rockies basis differential per MMBtu(3) | $0.25 - $0.20 | $0.15 - $0.10 | |
NYMEX/Midcontinent basis differential per MMBtu(3) | $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) The production decrease from the previous forecast is due solely to the impact of assumed ethane rejection. The previous forecast assumed ethane recovery for the full year and the current forecast assumes ethane rejection for the full year. | |||
(3) Prices for remaining 2013 forecast volumes that are not protected by commodity price derivative contracts. See attached schedule at the end of this release for a summary of Commodity Derivative Positions in place on the date of this release. | |||
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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
QEP Energy's Bakken/Three Forks net production averaged 17 MBoed during the first quarter 2013. The Company completed and turned to sales 12 operated wells, including one well in the South Antelope Area (working interest 99%) and 11 wells within the Fort Berthold Reservation (average working interest 91%) during the first quarter. The Fort Berthold Reservation completions included five wells on the first pod of our Buffalo 10-well Pad (three Three Forks and two Bakken, working interest 82%) and five wells on the first pod of our Skunk Creek 10-well Pad (three Bakken and two Three Forks, working interest 98%). These wells are performing consistent with or ahead of our expectations.
At the end of the first quarter, QEP Energy had 20 operated wells drilling or at intermediate casing point (average working interest 83%) and 10 operated wells waiting on completion (average working interest 85%). The Company also had interests in 14 outside-operated wells being drilled (average working interest 6%) and 20 outside-operated wells waiting on completion (average working interest 4%) at the end of the first quarter.
QEP Energy had seven rigs operating in the Bakken/Three Forks play (four in the South Antelope Area and three within the Fort Berthold Reservation) at the end of the first quarter. QEP Energy's operated completed well costs for a typical long-lateral Bakken or Three Forks well averaged approximately $10.8 million in the first quarter.
Slides 6-8 depict QEP Energy's acreage and activity in the Bakken/Three Forks play.
Pinedale Anticline: 110 new well completions expected in 2013
During the first quarter 2013, QEP Energy's Pinedale net production averaged 241 MMcfed, of which 13% was oil and NGL. In response to the decline in ethane prices, QEP Energy began rejecting ethane from Pinedale production on December 1, 2012. While ethane rejection results in 7 - 8% less natural gas equivalent sales volumes, it has a negligible impact on gross revenues at current ethane prices. The processing margins for Pinedale propane and heavier NGL components remain positive.
QEP Energy completed and turned to sales 22 new Pinedale wells (average working interest 68%) during the first quarter. QEP Energy suspends Pinedale completion operations during the coldest months of the winter, generally from December to mid-March. At the end of the first quarter, the Company had 51 Pinedale wells with QEP working interests drilled, cased and 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. In the first quarter, drill times from spud to total depth averaged 11.9 days compared to an average of 12.8 days in 2012.
At the end of the first quarter, QEP Energy had four rigs operating at Pinedale (including one rig working in an area where QEP Energy is the operator but owns only a small overriding royalty interest). The Company currently expects to complete a total of approximately 110 wells during 2013, including 29 wells in the area in which QEP Energy is the designated operator but owns only a small overriding royalty interest.
Please refer to slides 9-10 for additional details on the Company's Pinedale operations.
Uinta Basin: Continued development drilling in the liquids-rich Lower Mesaverde Play
During the first quarter 2013, Uinta Basin net production averaged 65 MMcfed of which 30 MMcfed was from the Lower Mesaverde play. In response to the decline in ethane prices, QEP Energy commenced rejecting ethane from Uinta Basin gas production in the fourth quarter 2012. Ethane rejection results in 7 - 8% less natural gas equivalent sales volumes but
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has only a negligible impact on gross revenues at current ethane prices. Processing margins for propane and heavier NGL components remain positive.
QEP Energy commenced development drilling on “Pinedale-style” multi-well pads in the Lower Mesaverde play during the fourth quarter 2012 and initially plans to drill 20-acre density development wells. The pads and wellbore geometries will be designed to allow for possible future 10-acre density development wells. Data from a recently completed seven well pilot program is being analyzed 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.
The Company had two operated drilling rigs working in the Lower Mesaverde play and had 61 producing wells in the play, four of which were completed and turned to sales during the first quarter (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 the first quarter the Company had one rig drilling horizontal and vertical wells targeting multiple crude oil-bearing limestone and sandstone reservoirs in the Lower Green River Formation, at an average true vertical depth of 5,500 feet. During the first quarter, QEP Energy completed three Company-operated horizontal oil wells in the Uinta Basin (average working interest 79%).
Slides 11-12 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 80 MMcfed during the first quarter 2013. During the first quarter, QEP Energy completed four operated wells in the play (working interest 100%). The Company also participated in 27 outside-operated horizontal Woodford “Cana” Shale wells that were completed and turned to sales during the first quarter (working interests ranging from less than 1% to 4%).
At the end of first quarter, the Company had one operated rig drilling 80-acre horizontal infill development wells (working interest 75%) and there were seven QEP Energy-operated 80-acre infill wells in one section awaiting completion (working interest 75%). QEP Energy also has a working interest in 17 outside-operated wells awaiting completion (working interests ranging from less than 1% to 37%).
Slide 13 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 42 MMcfed during the first quarter 2013. During the quarter, QEP Energy completed three operated wells in the play (one Cherokee Formation and two Caldwell Formation, average working interest 56%) with an average 24-hour initial gross production rate of 775 Boed. QEP Energy also participated in five outside-operated well completions in the Kansas City Formation (or Hogshooter Formation, average working interest 17%) with an average 24-hour initial gross production rate of 976 Boed. At the end of the first quarter the Company had one operated Granite Wash “A” Formation horizontal well drilling (working interest 72%).
See slide 14 for details on the Granite Wash play.
Haynesville: No operated drilling activity in the Haynesville Shale play of NW Louisiana
The Company's Haynesville/Cotton Valley net production averaged 248 MMcfed during the first quarter 2013.
In response to low natural gas prices, QEP Energy released its last operated drilling rig in the Haynesville play in July 2012 and deferred completion of the last five wells drilled. QEP Energy completed these five deferred Haynesville wells during the first quarter 2013 (working interest 48%). The Company also participated in one outside-operated horizontal Haynesville well that was completed in the first quarter (working interest 9%).
Refer to slide15 for additional information on QEP Energy's Haynesville activities.
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QEP Field Services
QEP Field Services' total revenue from fee-based processing activity increased by 12%, or $2.2 million, in the first quarter 2013 compared to the first quarter 2012. This was offset by lower first quarter 2013 NGL sales volumes, which were down 68% primarily as a result of our processing plants operating in ethane rejection, and lower gathering volumes, which were down 10% compared to the prior-year quarter. Approximately 82% of QEP Field Services’ first quarter 2013 net operating revenue was derived from fee-based gathering and processing activities compared to 72% in the first quarter 2012.
Processing margin (total processing plant revenues less plant shrink, transportation, fractionation, and operating expenses) was $26.3 million in the first quarter 2013 compared to $45.0 million in the first quarter 2012, a 42% decrease. First quarter 2013 results were negatively impacted by a 69% decrease in keep-whole processing margin (NGL sales revenues less shrink, transportation and fractionation expenses), due primarily to weaker NGL component prices and higher natural gas prices. Total fee-based processing revenues were $21.3 million in the first quarter 2013, a 12% increase from the prior year period.
Gathering margin (total gathering revenues less gathering related operating expenses) was $37.5 million in the first quarter 2013 compared to $43.6 million in the first quarter 2012, a 14% decrease, due primarily to a 32% decline in our northwest Louisiana Haynesville gathering volumes between the two periods.
After commissioning and startup in the first quarter, Field Services' new Iron Horse II cryogenic processing plant is now fully operational. During the first quarter, construction continued on 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.
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First Quarter 2013 Results Conference Call
QEP Resources’ management will discuss first quarter 2013 results in a conference call on Wednesday, May 1, 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 May 31, 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 # 411290. In addition, QEP’s slides for the first quarter 2013, 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, the Texas Panhandle, and Louisiana) 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, 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; ethane rejection and its impact; and plans to double railcar loading capacity. 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 (Unaudited) | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2013 | 2012 | ||||||
REVENUES | (in millions except per share data) | ||||||
Natural gas sales | $ | 197.6 | $ | 161.2 | |||
Oil sales | 194.2 | 110.8 | |||||
NGL sales | 68.4 | 97.4 | |||||
Gathering, processing and other | 45.6 | 49.8 | |||||
Purchased gas, oil and NGL sales | 190.7 | 184.0 | |||||
Total Revenues | 696.5 | 603.2 | |||||
OPERATING EXPENSES | |||||||
Purchased gas, oil and NGL expense | 196.8 | 188.4 | |||||
Lease operating expense | 38.9 | 40.1 | |||||
Natural gas, oil and NGL transportation and other handling costs | 34.0 | 34.5 | |||||
Gathering, processing and other | 20.6 | 23.7 | |||||
General and administrative | 46.0 | 36.0 | |||||
Production and property taxes | 35.9 | 24.7 | |||||
Depreciation, depletion and amortization | 254.2 | 199.3 | |||||
Exploration expenses | 5.1 | 2.0 | |||||
Impairment | — | 6.5 | |||||
Total Operating Expenses | 631.5 | 555.2 | |||||
Net (loss) gain from asset sales | (0.2 | ) | 1.5 | ||||
OPERATING INCOME | 64.8 | 49.5 | |||||
Realized and unrealized (losses) gains on derivative contracts (See Note 7) | (34.6 | ) | 216.3 | ||||
Interest and other income | 2.0 | 1.7 | |||||
Income from unconsolidated affiliates | 1.3 | 1.9 | |||||
Interest expense | (39.4 | ) | (24.7 | ) | |||
(LOSS) INCOME BEFORE INCOME TAXES | (5.9 | ) | 244.7 | ||||
Income tax benefit (provision) | 2.2 | (88.7 | ) | ||||
NET (LOSS) INCOME | (3.7 | ) | 156.0 | ||||
Net income attributable to noncontrolling interest | (0.6 | ) | (0.8 | ) | |||
NET (LOSS) INCOME ATTRIBUTABLE TO QEP | $ | (4.3 | ) | $ | 155.2 | ||
Earnings Per Common Share Attributable to QEP | |||||||
Basic total | $ | (0.02 | ) | $ | 0.87 | ||
Diluted total | $ | (0.02 | ) | $ | 0.87 | ||
Weighted-average common shares outstanding | |||||||
Used in basic calculation | 177.0 | 177.4 | |||||
Used in diluted calculation | 177.0 | 178.5 | |||||
Dividends per common share | $ | 0.02 | $ | 0.02 | |||
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QEP RESOURCES, INC. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) | |||||||
March 31, 2013 | December 31, 2012 | ||||||
ASSETS | (in millions) | ||||||
Current Assets | |||||||
Cash and cash equivalents | $ | — | $ | — | |||
Accounts receivable, net | 432.3 | 387.5 | |||||
Fair value of derivative contracts | 85.6 | 188.7 | |||||
Gas, oil and NGL inventories, at lower of average cost or market | 7.1 | 13.1 | |||||
Prepaid expenses and other | 50.0 | 60.4 | |||||
Deferred income taxes | 18.1 | — | |||||
Total Current Assets | 593.1 | 649.7 | |||||
Property, Plant and Equipment (successful efforts method for gas and oil properties) | |||||||
Proved properties | 10,502.4 | 10,234.3 | |||||
Unproved properties | 961.4 | 937.9 | |||||
Midstream field services | 1,647.2 | 1,634.9 | |||||
Marketing and other | 69.1 | 64.6 | |||||
Material and supplies | 60.9 | 61.9 | |||||
Total Property, Plant and Equipment | 13,241.0 | 12,933.6 | |||||
Less Accumulated Depreciation, Depletion and Amortization | |||||||
Exploration and production | 4,458.1 | 4,258.1 | |||||
Midstream field services | 372.5 | 357.9 | |||||
Marketing and other | 19.7 | 18.1 | |||||
Total Accumulated Depreciation, Depletion and Amortization | 4,850.3 | 4,634.1 | |||||
Net Property, Plant and Equipment | 8,390.7 | 8,299.5 | |||||
Investment in unconsolidated affiliates | 41.0 | 41.2 | |||||
Goodwill | 59.5 | 59.5 | |||||
Fair value of derivative contracts | 2.5 | 4.1 | |||||
Other noncurrent assets | 57.1 | 54.5 | |||||
TOTAL ASSETS | $ | 9,143.9 | $ | 9,108.5 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Checks outstanding in excess of cash balances | $ | 99.7 | $ | 39.7 | |||
Accounts payable and accrued expenses | 455.5 | 635.9 | |||||
Production and property taxes | 46.0 | 41.8 | |||||
Interest payable | 34.0 | 36.9 | |||||
Fair value of derivative contracts | 15.5 | 2.6 | |||||
Deferred income taxes | — | 5.0 | |||||
Total Current Liabilities | 650.7 | 761.9 | |||||
Long-term debt | 3,367.5 | 3,206.9 | |||||
Deferred income taxes | 1,496.1 | 1,493.5 | |||||
Asset retirement obligations | 197.1 | 191.4 | |||||
Fair value of derivative contracts | 3.2 | 3.6 | |||||
Other long-term liabilities | 141.5 | 137.5 | |||||
Commitments and contingencies | |||||||
EQUITY | |||||||
Common stock - par value $0.01 per share; 500.0 million shares authorized; 179.6 million and 178.5 million shares issued, respectively | 1.8 | 1.8 | |||||
Treasury stock - 0.3 million and 0.1 million shares, respectively | (11.9 | ) | (3.7 | ) | |||
Additional paid-in capital | 472.0 | 462.1 | |||||
Retained earnings | 2,765.2 | 2,773.0 | |||||
Accumulated other comprehensive income | 13.9 | 32.8 | |||||
Total Common Shareholders' Equity | 3,241.0 | 3,266.0 | |||||
Noncontrolling interest | 46.8 | 47.7 | |||||
Total Equity | 3,287.8 | 3,313.7 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 9,143.9 | $ | 9,108.5 | |||
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QEP RESOURCES, INC. CONSOLIDATED CASH FLOWS (Unaudited) | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2013 | 2012 | ||||||
(in millions) | |||||||
OPERATING ACTIVITIES | |||||||
Net (loss) income | $ | (3.7 | ) | $ | 156.0 | ||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 254.2 | 199.3 | |||||
Deferred income taxes | (9.3 | ) | 69.1 | ||||
Impairment | — | 6.5 | |||||
Share-based compensation | 6.1 | 5.7 | |||||
Amortization of debt issuance costs and discounts | 1.5 | 1.1 | |||||
Dry exploratory well expense | — | 0.1 | |||||
Net loss (gain) from asset sales | 0.2 | (1.5 | ) | ||||
Income from unconsolidated affiliates | (1.3 | ) | (1.9 | ) | |||
Distributions from unconsolidated affiliates and other | 1.5 | 1.6 | |||||
Unrealized loss (gain) on derivative contracts | 85.3 | (128.3 | ) | ||||
Changes in operating assets and liabilities | (162.4 | ) | 20.8 | ||||
Net Cash Provided by Operating Activities | 172.1 | 328.5 | |||||
INVESTING ACTIVITIES | |||||||
Property acquisitions | (23.6 | ) | (1.4 | ) | |||
Property, plant and equipment, including dry exploratory well expense | (361.0 | ) | (336.5 | ) | |||
Proceeds from disposition of assets | 1.5 | 3.3 | |||||
Net Cash Used in Investing Activities | (383.1 | ) | (334.6 | ) | |||
FINANCING ACTIVITIES | |||||||
Checks outstanding in excess of cash balances | 60.0 | 29.2 | |||||
Long-term debt issued | — | 500.0 | |||||
Long-term debt issuance costs paid | — | (6.9 | ) | ||||
Proceeds from credit facility | 545.5 | 120.0 | |||||
Repayments of credit facility | (385.0 | ) | (626.0 | ) | |||
Treasury stock repurchases | (7.5 | ) | (9.3 | ) | |||
Other capital contributions | 2.1 | 2.4 | |||||
Dividends paid | (3.6 | ) | (3.6 | ) | |||
Excess tax benefit on share-based compensation | 1.0 | 2.0 | |||||
Distribution to noncontrolling interest | (1.5 | ) | (1.7 | ) | |||
Net Cash Provided by Financing Activities | 211.0 | 6.1 | |||||
Change in cash and cash equivalents | — | — | |||||
Beginning cash and cash equivalents | — | — | |||||
Ending cash and cash equivalents | — | — | |||||
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QEP RESOURCES, INC. OPERATIONS BY LINE OF BUSINESS (Unaudited) QEP Energy - Production by Region | ||||||||
Three Months Ended March 31, | ||||||||
(in Bcfe) | ||||||||
2013 | 2012 | Change | ||||||
Northern Region | ||||||||
Pinedale | 21.7 | 22.2 | (2 | )% | ||||
Williston Basin | 9.0 | 3.1 | 190 | % | ||||
Uinta Basin | 5.8 | 4.6 | 26 | % | ||||
Legacy | 3.5 | 3.7 | (5 | )% | ||||
Total Northern Region | 40.0 | 33.6 | 19 | % | ||||
Southern Region | ||||||||
Haynesville/Cotton Valley | 22.3 | 28.0 | (20 | )% | ||||
Midcontinent | 15.7 | 12.6 | 25 | % | ||||
Total Southern Region | 38.0 | 40.6 | (6 | )% | ||||
Total production | 78.0 | 74.2 | 5 | % | ||||
QEP Energy - Total Production | ||||||||
Three Months Ended March 31, | ||||||||
2013 | 2012 | Change | ||||||
QEP Energy Production Volumes | ||||||||
Natural gas (Bcf) | 58.5 | 59.5 | (2 | )% | ||||
Oil (Mbbl) | 2,138.9 | 1,222.5 | 75 | % | ||||
NGL (Mbbl) | 1,108.5 | 1,221.7 | (9 | )% | ||||
Total production (Bcfe) | 78.0 | 74.2 | 5 | % | ||||
Average daily production (MMcfe) | 866.4 | 815.1 | 6 | % | ||||
12
QEP Energy - Prices | ||||||||||
Three Months Ended March 31, | ||||||||||
2013 | 2012 | Change | ||||||||
Natural gas (per Mcf) | ||||||||||
Average field-level price | $ | 3.38 | $ | 2.71 | ||||||
Commodity derivative impact | 0.76 | 1.44 | ||||||||
Net realized price | $ | 4.14 | $ | 4.15 | — | % | ||||
Oil (per bbl) | ||||||||||
Average field-level price | 90.81 | 90.67 | ||||||||
Commodity derivative impact | 2.43 | (2.20 | ) | |||||||
Net realized price | $ | 93.24 | $ | 88.47 | 5 | % | ||||
NGL (per bbl) | ||||||||||
Average field-level price | 45.64 | 40.87 | ||||||||
Commodity derivative impact | — | 0.34 | ||||||||
Net realized price | $ | 45.64 | $ | 41.21 | 11 | % | ||||
Average net equivalent price (per Mcfe) | ||||||||||
Average field-level price | 5.67 | 4.34 | ||||||||
Commodity derivative impact | 0.64 | 1.13 | ||||||||
Net realized price | $ | 6.31 | $ | 5.47 | 15 | % | ||||
QEP Energy - Operating Expenses | ||||||||||
Three Months Ended March 31, | ||||||||||
2013 | 2012 | Change | ||||||||
(per Mcfe) | ||||||||||
Depreciation, depletion and amortization | $ | 3.05 | $ | 2.47 | 23 | % | ||||
Lease operating expense | 0.53 | 0.55 | (4 | )% | ||||||
Natural gas, oil and NGL transport & other handling costs | 0.72 | 0.68 | 6 | % | ||||||
General and administrative expense | 0.49 | 0.44 | 11 | % | ||||||
Allocated interest expense | 0.58 | 0.32 | 81 | % | ||||||
Production taxes | 0.44 | 0.31 | 42 | % | ||||||
Total Operating Expenses | $ | 5.81 | $ | 4.77 | 22 | % | ||||
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Three Months Ended March 31, | ||||||||||
2013 | 2012 | Change | ||||||||
QEP Field Services Gathering Operating Statistics | ||||||||||
Natural gas gathering volumes (millions of MMBtu) | 111.3 | 123.7 | (10 | )% | ||||||
Gathering revenue (per MMBtu) | $ | 0.34 | $ | 0.34 | — | % | ||||
QEP Field Services Gathering Margin (in millions) | ||||||||||
Gathering | $ | 37.6 | $ | 41.9 | (10 | )% | ||||
Other Gathering | 10.2 | 11.3 | (10 | )% | ||||||
Gathering (expense) | (10.3 | ) | (9.6 | ) | 7 | % | ||||
Gathering margin | $ | 37.5 | $ | 43.6 | (14 | )% | ||||
QEP Field Services Processing Margin (in millions) | ||||||||||
NGL sales | $ | 17.8 | $ | 47.5 | (63 | )% | ||||
Realized gains from commodity derivative contract settlements | — | 1.1 | — | % | ||||||
Processing (fee-based) revenues | 16.4 | 16.0 | 3 | % | ||||||
Other processing revenues | 4.9 | 3.0 | 63 | % | ||||||
Processing (expense) | (4.1 | ) | (3.7 | ) | 11 | % | ||||
Processing plant fuel and shrink (expense) | (5.9 | ) | (10.1 | ) | (42 | )% | ||||
Natural gas, oil and NGL transport & other handling costs | (2.8 | ) | (8.8 | ) | (68 | )% | ||||
Processing margin | $ | 26.3 | $ | 45.0 | (42 | )% | ||||
Keep-whole processing margin(1) | $ | 9.1 | $ | 29.7 | (69 | )% | ||||
Fee-based processing margin | $ | 17.2 | $ | 15.3 | 12 | % | ||||
QEP Field Services Processing Operating Statistics | ||||||||||
Natural gas processing volumes | ||||||||||
NGL sales (Mbbl) | 341.1 | 1,076.7 | (68 | )% | ||||||
Average net realized NGL sales price (per Bbl)(2) | $ | 52.32 | $ | 45.09 | 16 | % | ||||
Total fee-based processing volumes (in millions of MMBtu) | 53.7 | 59.7 | (10 | )% | ||||||
Average fee-based processing revenue (per MMBtu) | $ | 0.31 | $ | 0.27 | 15 | % | ||||
(1) 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. | ||||||||||
(2) 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. | ||||||||||
14
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 or benefit, interest expense, depreciation, depletion, and amortization, impairment, exploration expense, loss on early extinguishment of debt and certain significant accrued litigation loss contingencies. 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:
QEP Energy | QEP Field Services | QEP Marketing & Other | QEP Resources | ||||||||||||
Three Months Ended March 31, 2013 | (in millions) | ||||||||||||||
Net (loss) income attributable to QEP | $ | (29.8 | ) | $ | 21.6 | $ | 3.9 | $ | (4.3 | ) | |||||
Unrealized losses on derivative contracts | 84.0 | — | 1.3 | 85.3 | |||||||||||
Net (gain) loss from asset sales | (0.1 | ) | 0.3 | — | 0.2 | ||||||||||
Interest and other income | (1.7 | ) | (0.3 | ) | — | (2.0 | ) | ||||||||
Income tax (benefit) provision | (17.2 | ) | 12.5 | 2.5 | (2.2 | ) | |||||||||
Interest expense | 45.3 | 4.0 | (9.9 | ) | 39.4 | ||||||||||
Depreciation, depletion and amortization(1) | 238.1 | 15.1 | 0.3 | 253.5 | |||||||||||
Impairment | — | — | — | — | |||||||||||
Exploration expenses | 5.1 | — | — | 5.1 | |||||||||||
Adjusted EBITDA | $ | 323.7 | $ | 53.2 | $ | (1.9 | ) | $ | 375.0 | ||||||
Three Months Ended March 31, 2012 | |||||||||||||||
Net income attributable to QEP | $ | 108.1 | $ | 45.4 | $ | 1.7 | $ | 155.2 | |||||||
Unrealized gains on derivative contracts | (123.7 | ) | (3.0 | ) | (1.6 | ) | (128.3 | ) | |||||||
Net gain from asset sales | (1.5 | ) | — | — | (1.5 | ) | |||||||||
Interest and other income | (1.7 | ) | — | — | (1.7 | ) | |||||||||
Income tax provision | 64.3 | 23.5 | 0.9 | 88.7 | |||||||||||
Interest expense | 23.6 | 2.3 | (1.2 | ) | 24.7 | ||||||||||
Accrued litigation loss contingency(2) | 6.5 | — | — | 6.5 | |||||||||||
Depreciation, depletion and amortization(1) | 183.7 | 14.7 | 0.2 | 198.6 | |||||||||||
Impairment | 6.5 | — | — | 6.5 | |||||||||||
Exploration expenses | 2.0 | — | — | 2.0 | |||||||||||
Adjusted EBITDA | $ | 267.8 | $ | 82.9 | $ | — | $ | 350.7 | |||||||
(1) Excludes the noncontrolling interest's 22% share, or $0.7 million, during the three months ended March 31, 2013 and 2012, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C. | |||||||||||||||
(2) Includes certain significant litigation contingency items for the three months ended March 31, 2012. | |||||||||||||||
15
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, certain significant accrued litigation loss contingencies, 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 March 31, | ||||||||
2013 | 2012 | |||||||
(in millions, except per earnings per share) | ||||||||
Net (loss) income attributable to QEP | $ | (3.7 | ) | $ | 156.0 | |||
Adjustments to net income | ||||||||
Net loss (gain) from asset sales | 0.2 | (1.5 | ) | |||||
Income taxes on net loss (gain) on asset sales | (0.1 | ) | 0.6 | |||||
Unrealized loss (gain) on derivative contracts | 85.3 | (128.3 | ) | |||||
Income taxes on unrealized loss (gain) on derivative contracts | (31.7 | ) | 47.7 | |||||
Accrued litigation loss contingency(1) | — | 6.5 | ||||||
Income taxes on accrued litigation loss contingency | — | (2.4 | ) | |||||
Non-cash price-related impairment charge | — | 0.4 | ||||||
Income taxes on non-cash price-related impairment charge | — | (0.1 | ) | |||||
Total after-tax adjustments to net income | 53.7 | (77.1 | ) | |||||
Adjusted net income attributable to QEP Resources | $ | 49.4 | $ | 78.1 | ||||
Earnings per Common Share attributable to QEP | ||||||||
Diluted earnings per share | $ | (0.02 | ) | $ | 0.87 | |||
Diluted after-tax adjustments to net income per share | 0.30 | (0.43 | ) | |||||
Diluted Adjusted Net Income per share | $ | 0.28 | $ | 0.44 | ||||
Weighted-average common shares outstanding | ||||||||
Diluted(2) | 177.3 | 178.5 | ||||||
Weighted-average common shares outstanding diluted Non-GAAP reconciliation(2) | ||||||||
Weighted-average common shares outstanding used in GAAP diluted calculation | 177.0 | |||||||
Potential number of shares issuable upon exercise of in-the-money stock options under the long-term stock incentive plan | 0.3 | |||||||
Weighted-average common shares outstanding used in Non- GAAP diluted calculation | 177.3 | |||||||
(1) Includes certain significant litigation contingency items for the three months ended March 31, 2012. | ||||||||
(2) The three months ended March 31, 2013, 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 March 31, 2013, in calculating earnings-per-share for GAAP purposes, because the effect is antidilutive due to the Company's net loss for GAAP purposes. | ||||||||
16
The following table presents open 2013 derivative positions as of April 26, 2013:
QEP Energy Commodity Derivative Positions | |||||||||||
Year | Type of Contract | Index | Total Volumes | Weighted-average price per unit | |||||||
(in millions) | |||||||||||
Natural gas sales | (MMBtu) | ||||||||||
2013 | Swap | IFNPCR(1) | 54.7 | $ | 5.50 | ||||||
2013 | Swap | NYMEX | 44.0 | $ | 3.81 | ||||||
2014 | Swap | IFNPCR(1) | 29.2 | $ | 3.98 | ||||||
2014 | Swap | NYMEX | 25.6 | $ | 4.19 | ||||||
Oil sales | (Bbls) | ||||||||||
2013 | Swap | NYMEX WTI | 4.4 | $ | 98.33 | ||||||
2013 | Swap | BRENT ICE | 0.3 | $ | 107.80 | ||||||
2014 | Swap | NYMEX WTI | 4.7 | $ | 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 | Weighted-average price per MMBtu | |||||||
(in millions) | |||||||||||
Natural gas sales | (MMBtu) | ||||||||||
2013 | Swap | IFNPCR | 2.1 | $ | 3.52 | ||||||
Natural gas purchases | (MMBtu) | ||||||||||
2013 | Swap | IFNPCR | 0.2 | $ | 3.57 | ||||||
2014 | Swap | IFNPCR | 0.1 | $ | 3.78 | ||||||
17