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| 8-K - QEP RESOURCES INC 8-K 10-25-2011 - QEP RESOURCES, INC. | form8k.htm |
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News Release |
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QEP Resources, Inc.
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1050 17th Street, Suite 500
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Denver, CO 80265
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AND PRODUCTION OF 70.7 BCFE
Company increases 2011 adjusted EBITDA and production guidance and provides an update on operations
DENVER — QEP Resources (NYSE: QEP) reported adjusted EBITDA (a non-GAAP measure) of $353.7 million for the third quarter of 2011 compared to $297.5 million in the 2010 period, a 19% increase. Factors driving QEP’s results included increased gathering and processing margins at QEP Field Services, 15% higher net production from QEP Energy, and higher net realized crude oil and NGL prices which more than offset net realized natural gas prices that were 14% lower than a year ago at QEP Energy.
ADJUSTED EBITDA BY SUBSIDIARY
(in millions)
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3 Months Ended
September 30,
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9 Months Ended
September 30,
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2011
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2010
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Change
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2011
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2010
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Change
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QEP Energy
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$ | 267.3 | $ | 246.0 | 9 | % | $ | 757.0 | $ | 683.8 | 11 | % | ||||||||||||
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QEP Field Services
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84.8 | 48.7 | 74 | 233.1 | 151.4 | 54 | ||||||||||||||||||
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QEP Marketing and other
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1.6 | 2.8 | (43 | ) | 6.0 | 6.8 | (12 | ) | ||||||||||||||||
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TOTAL(a)
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$ | 353.7 | $ | 297.5 | 19 | % | $ | 996.1 | $ | 842.0 | 18 | % | ||||||||||||
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(a)
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See attached schedule for a reconciliation of adjusted EBITDA to net income.
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QEP Resources net income from continuing operations for the third quarter was $101.5 million or $0.57 per diluted share, compared to $71.1 million or $0.40 per diluted share in the 2010 period. Excluding changes in unrealized gains and losses on natural gas basis-only swaps, gains and losses on non-core asset sales, separation costs and losses on early extinguishment of debt, QEP Resources adjusted net income from continuing operations (a non-GAAP measure) was $83.5 million or $0.47 per diluted share in the third quarter compared to $57.2 million or $0.32 per diluted share in the 2010 period.
NET INCOME BY SUBSIDIARY
(in millions, except earnings per share)
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3 Months Ended
September 30,
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9 Months Ended
September 30,
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2011
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2010
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Change
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2011
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2010
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Change
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QEP Energy
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$ | 58.3 | $ | 58.6 | (1 | %) | $ | 148.2 | $ | 165.0 | (10 | %) | ||||||||||||
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QEP Field Services(a)
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42.0 | 21.0 | 100 | 114.2 | 68.5 | 67 | ||||||||||||||||||
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QEP Marketing and other
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1.6 | 2.0 | (20 | ) | 5.5 | 3.6 | 53 | |||||||||||||||||
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Separation and debt extinguishment costs
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(0.4 | ) | (10.5 | ) | - | (0.4 | ) | (19.1 | ) | - | ||||||||||||||
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Income from continuing operations(a)
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$ | 101.5 | $ | 71.1 | 43 | % | $ | 267.5 | $ | 218.0 | 23 | % | ||||||||||||
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Discontinued operations(b)
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- | - | - | - | 43.2 | - | ||||||||||||||||||
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NET INCOME(a)
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$ | 101.5 | $ | 71.1 | 43 | % | $ | 267.5 | $ | 261.2 | 2 | % | ||||||||||||
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Earnings per diluted share
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From continuing operations
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$ | 0.57 | $ | 0.40 | $ | 1.50 | $ | 1.23 | ||||||||||||||||
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Total earnings
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$ | 0.57 | $ | 0.40 | $ | 1.50 | $ | 1.47 | ||||||||||||||||
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Weighted average diluted shares
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178.5 | 177.9 | 178.5 | 177.6 | ||||||||||||||||||||
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(a)
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Net income represents amounts attributable to QEP Resources after deducting non-controlling interest.
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(b)
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QEP Resources completed its tax-free spin-off from Questar Corporation on June 30, 2010. In conjunction with the spin-off, QEP Resources distributed the common stock of its wholly-owned subsidiary, Wexpro Company, to Questar. Accordingly, Wexpro’s historical financial results have been presented as discontinued operations in this release.
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“The third quarter of 2011 was another strong quarter for QEP Resources,” said Chuck Stanley, President and CEO. “QEP Energy production was up 15% from a year ago, driven by strong results from the Pinedale Anticline and Haynesville Shale plays, combined with significant contributions from new wells in our Woodford “Cana” Shale and Bakken/Three Forks plays. With 65% of our 2011 drilling capital directed to oil and liquids-rich gas plays, we grew oil and NGL production 44% year-to-date compared to the same period a year ago. Oil and NGL production accounted for 29% of QEP Energy net realized production revenues year-to-date and we expect that share to grow as we continue to allocate capital to our higher-margin liquids-rich resource plays. We also completed the successful early startup, commissioning and loading of Field Service’s new Blacks Fork II gas processing plant, which made a significant contribution to both QEP Energy and Field Services results during the quarter and should continue to do so for many years to come,” Stanley added.
Third Quarter 2011 Highlights
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QEP Energy grew natural gas, oil and NGL net production to 70.7 billion cubic feet of natural gas equivalent (Bcfe) compared to 61.7 Bcfe in the 2010 period. Crude oil and NGL comprised 15% of reported production volumes.
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QEP Energy adjusted EBITDA increased 9% compared to the 2010 period, driven by a 15% increase in production and increased net realized liquid prices – 31% for crude oil and 27% for NGL, partially offset by a 14% decrease in net realized natural gas prices.
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QEP Energy net realized natural gas prices averaged $4.00 per thousand cubic feet (Mcf), compared to $4.64 per Mcf in the 2010 period. Field-level natural gas prices in 2011 were $3.27 per Mcf compared to $3.37 per Mcf in 2010. Natural gas-related derivative settlements contributed $43.7 million in 2011 ($0.73 per Mcf) compared to $69.7 million in 2010 ($1.27 per Mcf).
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QEP Energy net crude oil and NGL revenues (including the settlement of crude oil-related derivatives) increased 86% compared to the third quarter of 2010 and represented 32% of net realized production revenues.
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Net realized crude oil prices averaged $82.44 per barrel, up 31% compared to the 2010 period. Oil related derivative settlements contributed $0.9 million in 2011 ($0.91 per bbl) compared to a loss of $1.4 million in 2010 ($1.80 per bbl).
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Net realized NGL prices at QEP Energy averaged $38.17 per barrel, up 27% compared to the 2010 period.
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QEP Field Services adjusted EBITDA increased 74% from the third quarter of 2010, driven by a 26% increase in gathering margin and a 127% increase in processing margin. Net income was $42.0 million – double the $21.0 million generated in the third quarter of 2010.
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QEP Energy year-to-date capital investment (on an accrual basis) was $939.4 million comprised of $898.7 million in drilling and completion and other expenditures (including $0.5 million of dry hole exploration expense) and $40.7 million in property acquisition costs.
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QEP Field Services year-to-date capital investments (on an accrual basis) to expand capacity at its gathering, processing and treating facilities in western Wyoming, eastern Utah and the Haynesville/Cotton Valley area of northwest Louisiana totaled $68.1 million.
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Field Services introduced gas into the Blacks Fork II plant on July 14th. QEP Energy entered into a fee-based processing agreement with QEP Field Services under which Field Services provides cryogenic gas processing services for QEP Energy’s Pinedale production volumes at Blacks Fork II.
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Separation costs and losses on early extinguishment of debt reduced QEP Resources pre-tax income from continuing operations by $0.7 million in the quarter compared to $13.5 million in the 2010 period.
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QEP raises 2011 adjusted EBITDA and Production Guidance
QEP now expects 2011 adjusted EBITDA to range from $1,315 to $1,350 million, compared to a previously forecast range of $1,275 to $1,325 million. QEP Energy expects 2011 production should range from 270 to 274 Bcfe, compared to a previously forecast range of 265 to 269 Bcfe.
The company’s guidance assumes hedge positions in place on the date of this release and other assumptions summarized in the table below:
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Guidance and Assumptions
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2011
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2011
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Current
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Previous
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QEP Resources adjusted EBITDA (millions)
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$ | 1,315-$1,350 | $ | 1,275-$1,325 | ||||
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QEP Energy capital investment (millions)
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$ | 1,250 | $ | 1,173 | ||||
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QEP Field Services capital investment (millions)
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95 | 125 | ||||||
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QEP Marketing and Other capital investment (millions)
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5 | 2 | ||||||
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Total QEP Resources capital investment (millions)
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$ | 1,350 | $ | 1,300 | ||||
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QEP Energy production – Bcfe
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270 - 274 | 265 - 269 | ||||||
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NYMEX gas price per MMBtu(a)
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$ | 3.50-$4.00 | $ | 4.00-$4.50 | ||||
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NYMEX crude oil price per bbl(a)
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$ | 80.00-$90.00 | $ | 90.00-$100.00 | ||||
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NYMEX/Rockies basis differential per MMBtu(a)
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$ | 0.25-$0.10 | $ | 0.50-$0.30 | ||||
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NYMEX/Midcontinent basis differential per MMBtu(a)
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$ | 0.25-$0.10 | $ | 0.30-$0.15 | ||||
(a) For remaining 2011 un-hedged volumes
Approximately 72% of QEP Energy’s forecast natural gas production and 27% of forecast oil production for the remainder of 2011 is hedged with a combination of fixed price swaps and costless price collars. On a natural gas equivalent basis, the company has approximately 60% of its forecast production for the remainder of 2011 hedged. A table with details of the Company’s hedge positions is included at the end of this release.
QEP now forecasts 2011 total capital investment of $1,350 million, comprised of $1,250 million in QEP Energy, $95 million in QEP Field Services, and $5 million in QEP Marketing. The increase in forecasted capital investment in QEP Energy is due to: 1) an increase in the number of net completed Pinedale and Haynesville Shale wells by year-end due to continued drilling/completion efficiency gains; 2) increased completed well costs associated with non-operated Haynesville wells; 3) accelerated investment for a produced water gathering/disposal system in the Williston Basin; and 4) an increase in lease acquisition spending. Forecasted capital investment in QEP Field Services declined $30 million compared to the prior forecast due to actual costs associated with new plants being less than forecast and a change in timing of expenditures on certain other gathering and processing projects.
QEP Energy Results
QEP Energy’s third quarter production increased 15% to 70.7 Bcfe compared to 61.7 Bcfe in the 2010 period. The Southern Region (formerly the Midcontinent region) contributed 55% of current quarter production compared to 54% in the 2010 period.
QEP Energy – Production by Major Area (Bcfe)
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3 Months Ended
September 30, |
9 Months Ended
September 30, |
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2011
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2010
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Change
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2011
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2010
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Change
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Southern Region
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Haynesville/Cotton Valley
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26.6 | 22.0 | 21 | % | 80.4 | 56.7 | 42 | % | ||||||||||||||||
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Midcontinent
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12.1 | 11.4 | 6 | 34.0 | 30.4 | 12 | ||||||||||||||||||
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Total Southern Region
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38.7 | 33.4 | 16 | 114.4 | 87.1 | 31 | ||||||||||||||||||
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Northern Region
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Pinedale Anticline
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21.6 | 17.9 | 21 | 55.6 | 49.9 | 11 | ||||||||||||||||||
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Uinta Basin
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4.8 | 5.3 | (9 | ) |
(a)16.2
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15.9 | 2 | |||||||||||||||||
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Rockies Legacy
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5.6 | 5.1 | 10 | 15.1 | 14.0 | 8 | ||||||||||||||||||
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Total Northern Region
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32.0 | 28.3 | 13 | 86.9 | 79.8 | 9 | ||||||||||||||||||
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Total QEP Energy
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70.7 | 61.7 | 15 | % | 201.3 | 166.9 | 21 | % | ||||||||||||||||
(a) Includes 1.6 Bcfe in Q1 from prior periods due to a change in ownership interest in a federal unit.
QEP Energy – Commodity Prices
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3 Months Ended
September 30, |
9 Months Ended
September 30, |
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2011
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2010
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Change
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2011
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2010
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Change
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Average field-level natural gas price ($ per Mcf)
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$ | 3.27 | $ | 3.37 | (3 | %) | $ | 3.34 | $ | 3.80 | (12 | %) | ||||||||||||
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Natural gas hedging impact ($ per Mcf) (a)
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1.20 | 1.77 | 1.19 | 1.62 | ||||||||||||||||||||
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Average revenue ($ per Mcf)
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4.47 | 5.14 | 4.53 | 5.42 | ||||||||||||||||||||
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Realized losses on basis-only swaps ($ per Mcf) (b)
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(0.47 | ) | (0.50 | ) | (0.50 | ) | (0.61 | ) | ||||||||||||||||
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Net realized natural gas price ($ per Mcf)
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$ | 4.00 | $ | 4.64 | (14 | %) | $ | 4.03 | $ | 4.81 | (16 | %) | ||||||||||||
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Average field-level oil price ($ per bbl)
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$ | 81.53 | $ | 64.85 | 26 | % | $ | 84.95 | $ | 67.31 | 26 | % | ||||||||||||
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Oil hedging impact ($ per bbl) (a)
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0.91 | (1.80 | ) | 0.38 | (2.42 | ) | ||||||||||||||||||
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Net realized oil price ($ per bbl)
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$ | 82.44 | $ | 63.05 | 31 | % | $ | 85.33 | $ | 64.89 | 31 | % | ||||||||||||
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Average field-level NGL price ($ per bbl)
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$ | 38.17 | $ | 30.07 | 27 | % | $ | 40.48 | $ | 34.83 | 16 | % | ||||||||||||
(a) Reported in revenues in the consolidated income statement.
(b) Reported below operating income in the consolidated income statement.
QEP Energy – Production Costs (per Mcfe)
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3 Months Ended
September 30, |
9 Months Ended
September 30, |
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2011
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2010
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2011
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2010
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Change
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Depreciation, depletion and amortization
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$ | 2.47 | $ | 2.56 | (4 | %) | $ | 2.60 | $ | 2.59 | - | % | ||||||||||||
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Lease operating expense
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0.54 | 0.54 | - | 0.53 | 0.55 | (4 | ) | |||||||||||||||||
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General and administrative expense
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0.33 | 0.29 | 14 | 0.35 | 0.33 | 6 | ||||||||||||||||||
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Allocated interest expense
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0.29 | 0.34 | (15 | ) | 0.30 | 0.35 | (14 | ) | ||||||||||||||||
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Production taxes
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0.37 | 0.30 | 23 | 0.37 | 0.35 | 6 | ||||||||||||||||||
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Total Production costs
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$ | 4.00 | $ | 4.03 | (1 | %) | $ | 4.15 | $ | 4.17 | - | % | ||||||||||||
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Depreciation, depletion and amortization expense per Mcfe (the DD&A rate) decreased in the third quarter of 2011 compared to 2010 primarily as the result of booking additional NGL reserves in Pinedale associated with the Blacks Fork II processing plant and the addition of lower cost reserves in the Haynesville/Cotton Valley area.
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Lease operating expense per Mcfe decreased in the year-to-date period compared to 2010 as a result of increased production volumes in lower operating cost areas. Growing production from new high-rate, low-operating cost wells in the Haynesville/Cotton Valley area and Pinedale coupled with declining production from higher cost areas lowered average per Mcfe lease operating expense. For the quarter, lease operating expenses per Mcfe were flat.
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General and administrative (G&A) expense per Mcfe increased in the three and nine months ended September 30, 2011, as the result of higher employee benefit plan related expenses, increased legal and outside professional services and higher insurance costs which were partially offset by increased production in the three and nine months ended September 30, 2011.
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Production taxes per Mcfe increased in the current year periods compared to 2010 as the result of increased field-level crude oil and NGL prices.
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QEP Energy total cash cost of production – lease operating expense plus general and administrative expense, allocated interest, and production taxes was $1.53 per Mcfe in the third quarter, compared to $1.47 per Mcfe in the 2010 period, a 4% increase.
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QEP Energy Operations Update
Growth continues in the Haynesville Shale of NW Louisiana
Since the last update, QEP has completed 13 additional company-operated Haynesville wells, each with strong production rates and pressures. In 2011, QEP drill times have averaged 32 days from spud to total depth on company-operated Haynesville wells, down from 37 days in 2010. Improved drilling performance and completion efficiencies have allowed QEP to remain the lowest cost operator in its portion of the Haynesville play. QEP-operated gross completed well costs averaged $9.1 million in 2011 compared to $9.3 million in 2010. QEP has 7 wells waiting on completion or being completed and currently has 6 operated rigs working in the Haynesville play. The Company also participated in 14 outside-operated Haynesville wells that were completed and turned to sales since the last operations update. Working interest in these wells ranged from less than 1% to 38%. QEP has interests in 8 outside-operated Haynesville wells that are waiting on completion. Slides with maps and other supporting materials referred to in this release are posted on the Company’s website www.qepres.com - please refer to slides 3 and 4 for additional information on QEP’s Haynesville activities.
During the third quarter of 2011, the company’s Haynesville net production averaged approximately 238 MMcfd and Cotton Valley/Hosston net production averaged approximately 50 MMcfd. QEP net production from the Haynesville play continues to be impacted by the Company’s decision to restrict the flowing rate of Haynesville wells to decrease near-wellbore pressure drawdown. The Company continues to restrict flow rates to minimize reservoir and propped fracture damage which should lead to increased ultimate recoverable reserves.
QEP on track to deliver 100 to 105 new Pinedale well completions in 2011
QEP has completed and turned to sales 89 new wells at Pinedale since resuming completion operations in mid-March 2011. The company suspends completion operations at Pinedale during the coldest months of the winter. QEP currently has 16 operated wells drilled and cased and waiting on completion. Drilling and completion efficiencies have allowed QEP to maintain its industry leading Pinedale completed well costs which were approximately $3.8 million per well in the third quarter. The average drill time from spud to total depth is 13.8 days in 2011 compared to 17 days in 2010. The company has 4 rigs currently working at Pinedale. During the third quarter of 2011, QEP’s Pinedale net production averaged approximately 235 MMcfed. As a result of a new fee-based processing agreement between QEP Energy and QEP Field Services, QEP Energy average net equivalent production for the third quarter included a significant contribution from liquids (193 MMcf/day, 1,621 Bbl Oil/day and 5,315 Bbl NGL/day). The new fee-based processing agreement was effective August 1. Slides 5 and 6 provide additional details on QEP’s Pinedale activity.
Strong industry activity continues in the Woodford “Cana” Shale play
QEP has completed and turned to sales 4 new QEP-operated Woodford “Cana” Shale wells in western Oklahoma. QEP has 2 operated wells currently being drilled and one operated well waiting on completion. The company currently operates 22 producing wells and has a non-operated working interest in 169 producing wells across the play. The company also has interests in 7 wells currently being drilled and 18 wells waiting on completion that are operated by others. During the third quarter of 2011, QEP net production from the play averaged approximately 45 MMcfed. Slide 7 shows QEP’s acreage and additional details on the Cana play.
Bakken/Three Forks production grows on company’s 90,000 acre North Dakota leasehold
QEP has completed and turned to sales 3 additional Bakken Formation operated wells in the Williston Basin of North Dakota. QEP has 4 operated wells currently being completed and 6 operated wells waiting on completion in the play. QEP also has interests in 8 outside-operated wells currently being drilled and 9 outside-operated wells waiting on completion. The company operates 20 producing wells in the play and has a working interest in 79 producing wells that are operated by others. During the third quarter of 2011, QEP’s Bakken/Three Forks net production averaged approximately 4,100 Boepd. Gross costs for recently completed QEP-operated long lateral Bakken/Three Forks (10,000’ average lateral length) wells have averaged $9.7 million, up over $1 million from early 2011. Slide 8 shows QEP’s acreage and activity in the Bakken/Three Forks play.
Granite Wash and Atoka Wash horizontal development in the Texas Panhandle
Since the last operations update, the company has completed and turned to sales 2 additional QEP operated Atoka Wash horizontal wells and one additional Caldwell zone horizontal well in Wheeler County, Texas. QEP has a 100% working interest in all three newly completed wells. The company currently has one Caldwell zone horizontal well and one Cherokee zone horizontal well waiting on completion. QEP is also participating in one outside-operated well currently being drilled. QEP has approximately 38,900 net acres in the “Wash” plays in the western Anadarko Basin including 25,300 acres in the Texas Panhandle. QEP has a working interest in a total of 50 producing horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle. During the third quarter of 2011, net production from this play (vertical and horizontal wells) averaged approximately 38 MMcfed. Slide 9 shows QEP’s acreage position and the location of the QEP-operated wells completed in the play since the last operations update and the two operated wells that are waiting on completion.
QEP Field Services Adjusted EBITDA Up 74%; Fee-based processing volumes up 11%; NGL sales volume up 32%
QEP Field Services (Field Services) – a QEP subsidiary that provides gas gathering and processing services – third quarter adjusted EBITDA increased 74% to $84.8 million compared to $48.7 million in the 2010 period. The increase was the result of higher gathering and processing margins.
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Gathering margin (total gathering revenues less gathering related operating expenses) increased 26%, or $ 9.9 million compared to the third quarter of 2010, driven primarily by increased other gathering revenue related to a third party processing arrangement for certain gas volumes in the Northern Region and a 6% increase in the average gathering rate. Total system throughput volume for the quarter averaged 1.4 million MMBtu per day.
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Processing margin (total processing plant revenues less plant operating expenses and shrinkage) increased 127%, or $24.1 million compared to the third quarter of 2010, driven primarily by keep-whole processing margins that were 126% higher. The increased keep-whole processing margin was primarily the result of a 52% increase in NGL prices and a 32% increase in NGL volumes.
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Approximately 72% of Field Services’ third quarter net operating revenue was derived from fee-based gathering and processing activities compared to 81% in the 2010 period.
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QEP Field Services gathering volumes totaled 126.9 million MMBtu for the third quarter of 2011 compared to 126.6 million MMBtu for the third quarter of 2010.
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Fee-based processing revenues increased 73% compared to the third quarter 2010, due to a 11% increase in fee-based processing volumes to 63.8 million MMBtu and a 50% increase in the average processing fee rate to $0.24 per MMBtu.
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NGL sales volumes totaled 34.0 million gallons during the 2011 quarter compared to 25.8 million gallons during the 2010 quarter, a 32% increase.
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The new 420 MMcfd Blacks Forks II cryogenic gas processing plant in southwest Wyoming was completed on July 14th, well ahead of schedule and within budget. Blacks Fork II generated $9.6 million of processing margin for QEP Field Services during the third quarter. With the completion of Blacks Fork II, QEP Field Services owns and operates processing plants in the Northern (Rocky Mountain) Region with an aggregate processing capacity of 1.37 Bcfd of natural gas. Slides 10 and 11 show the location of QEP Field Services assets and the new Blacks Fork II plant.
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Financing Activities
During the third quarter, QEP entered into a new $1.5 billion, 5-year, unsecured revolving credit agreement with a group of 19 financial institutions. The credit facility replaces the $1.0 billion credit facility that was scheduled to mature in March of 2013. The new credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The agreement also contains provisions which would allow for the amount of the facility to be increased to $2.0 billion and for the maturity date to be extended for two additional one-year periods. QEP expensed $0.7 million of deferred financial costs associated with the old credit facility in the period.
Third Quarter 2011 Results Conference Call
QEP Resources management will discuss third quarter 2011 results in a conference call on Wednesday, October 26, beginning at 11:00 a.m. ET. The call can be accessed at www.qepres.com. A replay of the teleconference will be available on the website and from October 26 to November 9 by dialing (855) 859-2056 in the U.S. or Canada and (404) 537-3406 for international calls, and then entering passcode 17043271. In addition, 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
QEP Resources, Inc. (NYSE:QEP) is a leading independent natural gas and oil exploration and production company with operations focused in the Rocky Mountain and Midcontinent of the United States. QEP Resources also gathers, compresses, treats, processes and stores natural gas.
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 2011 and related assumptions for such guidance; percentage of net realized production revenues attributed to oil and NGL production; number of rigs planned in operating areas; changes in lease operating expenses; the effects of restricting the flowing rate at the Haynesville Shale; and the capacity of the Blacks Fork II plant and the timing of such plant being fully operational. 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; changes in local, regional, national and global demand for natural gas, oil and NGL; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; weather conditions; changes in maintenance and construction costs; the availability and cost of credit; 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, 2010. QEP Resources undertakes no obligation to publicly correct or update the forward-looking statements in this news release, in other documents, or on the Web site to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.
For more information, visit QEP Resources’ website at: www.qepres.com.
QEP Energy Hedge Positions – October 25, 2011
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Time Periods
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Northern Region
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Southern Region
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Total
|
Northern Region
|
Southern Region
|
Total
|
||||||||||||||||||
|
Estimated
|
||||||||||||||||||||||||
|
Gas (Bcf) fixed-price swaps
|
Average price per Mcf, net to the well
|
|||||||||||||||||||||||
|
2011 remaining
|
20.6 | 13.2 | 33.8 | $ | 4.09 | $ | 4.88 | $ | 4.40 | |||||||||||||||
|
2012
|
46.9 | 73.2 | 120.1 | $ | 5.27 | $ | 4.09 | $ | 4.55 | |||||||||||||||
|
2013
|
50.3 | - | 50.3 | $ | 5.44 | - | $ | 5.44 | ||||||||||||||||
|
Estimated
|
||||||||||||||||||||||||
|
Gas (Bcf) costless collars
|
Average price per Mcf, net to the well
|
|||||||||||||||||||||||
|
Floor - Ceiling
|
Floor - Ceiling
|
Floor - Ceiling
|
||||||||||||||||||||||
|
2011 remaining
|
3.6 | 3.7 | 7.3 | $ | 3.01 - $5.25 | $ | 5.05 - $6.66 | $ | 4.04 - $5.97 | |||||||||||||||
|
Oil (Mbbl) fixed-price swaps
|
Average price per bbl, net to the well
|
|||||||||||||||||||||||
|
2011 remaining
|
46.0 | - | 46.0 | $ | 98.00 | - | $ | 98.00 | ||||||||||||||||
|
2012
|
1,464.0 | 183.0 | 1,647.0 | $ | 86.10 | $ | 108.00 | $ | 88.53 | |||||||||||||||
|
2013
|
- | 182.5 | 182.5 | - | $ | 103.80 | $ | 103.80 | ||||||||||||||||
|
Estimated
|
||||||||||||||||||||||||
|
Oil (Mbbl) costless collars
|
Average price per Bbl, net to the well
|
|||||||||||||||||||||||
|
Floor - Ceiling
|
Floor - Ceiling
|
Floor - Ceiling
|
||||||||||||||||||||||
|
2011 remaining
|
216.2 | 59.8 | 276.0 | $ | 51.38 - $99.98 | $ | 53.00 - $109.75 | $ | 51.73 - $102.10 | |||||||||||||||
|
Time Periods
|
Propane (MM gallons)
fixed-price swaps
|
Average price per gallon
|
||||||
|
2012
|
7.7 | $ | 1.28 | |||||
|
Time Periods
|
Ethane (MM gallons)
fixed-price swaps
|
Average price per gallon
|
||||||
|
2012
|
7.7 | $ | 0.59 | |||||
QEP Field Services Hedge Positions – October 25, 2011
|
Time Periods
|
Propane (MM gallons)
fixed-price swaps
|
Average price per gallon
|
||||||
|
2011 remaining
|
3.9 | $ | 1.45 | |||||
|
2012
|
15.3 | $ | 1.36 | |||||
|
Time Periods
|
Ethane (MM gallons)
fixed-price swaps
|
Average price per gallon
|
||||||
|
2012
|
7.7 | $ | 0.59 | |||||
|
CONSOLIDATED STATEMENTS OF INCOME
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
3 Months Ended September 30,
|
9 Months Ended September 30,
|
|||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
(in millions, except per share amounts)
|
||||||||||||||||
|
REVENUES
|
||||||||||||||||
|
Natural gas sales
|
$ | 266.7 | $ | 283.2 | $ | 795.8 | $ | 808.4 | ||||||||
|
Oil sales
|
76.1 | 49.9 | 218.4 | 139.5 | ||||||||||||
|
NGL sales
|
34.1 | 9.3 | 67.8 | 27.4 | ||||||||||||
|
Gathering, processing and other
|
118.7 | 76.4 | 340.1 | 238.7 | ||||||||||||
|
Purchased gas and oil sales
|
356.8 | 145.8 | 810.6 | 460.4 | ||||||||||||
|
Total Revenues
|
852.4 | 564.6 | 2,232.7 | 1,674.4 | ||||||||||||
|
OPERATING EXPENSES
|
||||||||||||||||
|
Purchased gas and oil expense
|
352.7 | 143.6 | 803.3 | 455.4 | ||||||||||||
|
Lease operating expense
|
37.0 | 32.8 | 104.1 | 89.7 | ||||||||||||
|
Gathering, processing and other
|
27.0 | 19.5 | 79.4 | 62.6 | ||||||||||||
|
General and administrative
|
28.7 | 24.7 | 89.1 | 75.6 | ||||||||||||
|
Separation costs
|
- | 0.2 | - | 14.2 | ||||||||||||
|
Production and property taxes
|
27.7 | 19.7 | 78.5 | 61.6 | ||||||||||||
|
Depreciation, depletion and amortization
|
189.0 | 170.5 | 566.4 | 469.5 | ||||||||||||
|
Exploration expense
|
2.4 | 2.9 | 7.5 | 9.2 | ||||||||||||
|
Abandonment and impairment
|
5.7 | 12.2 | 16.4 | 29.1 | ||||||||||||
|
Total Operating Expenses
|
670.2 | 426.1 | 1,744.7 | 1,266.9 | ||||||||||||
|
Net gain (loss) from asset sales
|
1.2 | 10.8 | 1.4 | 12.3 | ||||||||||||
|
OPERATING INCOME
|
183.4 | 149.3 | 489.4 | 419.8 | ||||||||||||
|
Interest and other income (loss)
|
(0.7 | ) | 1.6 | (0.5 | ) | 4.4 | ||||||||||
|
Income from unconsolidated affiliates
|
2.3 | 1.1 | 4.5 | 2.5 | ||||||||||||
|
Loss from early extinguishment of debt
|
(0.7 | ) | (13.3 | ) | (0.7 | ) | (13.3 | ) | ||||||||
|
Interest expense
|
(22.8 | ) | (22.6 | ) | (67.0 | ) | (62.8 | ) | ||||||||
|
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
|
161.5 | 116.1 | 425.7 | 350.6 | ||||||||||||
|
Income taxes
|
(59.1 | ) | (44.2 | ) | (156.0 | ) | (130.5 | ) | ||||||||
|
INCOME FROM CONTINUING OPERATIONS
|
102.4 | 71.9 | 269.7 | 220.1 | ||||||||||||
|
Discontinued operations, net of income tax
|
- | - | - | 43.2 | ||||||||||||
|
NET INCOME
|
102.4 | 71.9 | 269.7 | 263.3 | ||||||||||||
|
Net income attributable to non-controlling interest
|
(0.9 | ) | (0.8 | ) | (2.2 | ) | (2.1 | ) | ||||||||
|
NET INCOME ATTRIBUTABLE TO QEP
|
$ | 101.5 | $ | 71.1 | $ | 267.5 | $ | 261.2 | ||||||||
|
EARNINGS PER COMMON SHARE - ATTRIBUTABLE TO QEP
|
||||||||||||||||
|
Basic from continuing operations
|
$ | 0.58 | $ | 0.40 | $ | 1.52 | $ | 1.24 | ||||||||
|
Basic from discontinued operations
|
- | - | - | 0.25 | ||||||||||||
|
Basic total
|
$ | 0.58 | $ | 0.40 | $ | 1.52 | $ | 1.49 | ||||||||
|
Diluted from continuing operations
|
$ | 0.57 | $ | 0.40 | $ | 1.50 | $ | 1.23 | ||||||||
|
Diluted from discontinued operations
|
- | - | - | 0.24 | ||||||||||||
|
Diluted total
|
$ | 0.57 | $ | 0.40 | $ | 1.50 | $ | 1.47 | ||||||||
|
Weighted-Average Common Shares Outstanding
|
||||||||||||||||
|
Used in basic calculation
|
176.6 | 175.4 | 176.5 | 175.2 | ||||||||||||
|
Used in diluted calculation
|
178.5 | 177.9 | 178.5 | 177.6 | ||||||||||||
|
QEP RESOURCES, INC.
|
||||||||
|
CONDENSED CONSOLIDATED BALANCE SHEETS
|
||||||||
|
(Unaudited)
|
||||||||
|
September 30,
2011 |
December 31,
2010 |
|||||||
|
(in millions)
|
||||||||
|
ASSETS
|
||||||||
|
Current Assets
|
||||||||
|
Accounts receivable, net
|
$ | 355.3 | $ | 269.9 | ||||
|
Fair value of derivative contracts
|
225.4 | 257.3 | ||||||
|
Inventories, at lower of average cost
|
||||||||
|
Gas oil and NGL
|
16.1 | 16.4 | ||||||
|
Materials and supplies
|
87.1 | 65.4 | ||||||
|
Prepaid expenses and other
|
35.6 | 45.2 | ||||||
|
Total Current Assets
|
719.5 | 654.2 | ||||||
|
Property, Plant and Equipment (successful efforts method for gas and oil properties)
|
||||||||
|
Proved Properties
|
7,780.8 | 6,874.3 | ||||||
|
Unproved properties, not being depleted
|
326.3 | 322.0 | ||||||
|
Midstream field services
|
1,430.6 | 1,360.5 | ||||||
|
Marketing and other
|
47.8 | 44.5 | ||||||
|
Total Property, Plant and Equipment
|
9,585.5 | 8,601.3 | ||||||
|
Less Accumulated Depreciation, Depletion and Amortization
|
||||||||
|
Exploration and production
|
2,963.6 | 2,454.4 | ||||||
|
Midstream field services
|
283.7 | 244.6 | ||||||
|
Marketing and other
|
14.0 | 12.3 | ||||||
|
Total Accumulated Depreciation, Depletion and Amortization
|
3,261.3 | 2,711.3 | ||||||
|
Net Property, Plant and Equipment
|
6,324.2 | 5,890.0 | ||||||
|
Investment in unconsolidated affiliates
|
44.1 | 44.5 | ||||||
|
Goodwill
|
59.5 | 59.6 | ||||||
|
Fair value of derivative contracts
|
116.4 | 120.8 | ||||||
|
Other noncurrent assets
|
33.2 | 16.2 | ||||||
|
TOTAL ASSETS
|
$ | 7,296.9 | $ | 6,785.3 | ||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current Liabilities
|
||||||||
|
Checks outstanding in excess of cash balances
|
$ | 26.7 | $ | 19.5 | ||||
|
Accounts payable and accrued expenses
|
455.3 | 332.2 | ||||||
|
Production and property taxes
|
40.4 | 18.9 | ||||||
|
Interest payable
|
6.2 | 28.1 | ||||||
|
Fair value of derivative contracts
|
39.8 | 139.3 | ||||||
|
Deferred income taxes
|
20.7 | 27.8 | ||||||
|
Current portion of long-term debt
|
- | 58.5 | ||||||
|
Total Current Liabilities
|
589.1 | 624.3 | ||||||
|
Long-term debt, less current portion
|
1,582.7 | 1,472.3 | ||||||
|
Deferred income taxes
|
1,535.0 | 1,377.7 | ||||||
|
Asset retirement obligations
|
160.2 | 148.3 | ||||||
|
Fair value of derivative contracts
|
- | 0.3 | ||||||
|
Other long-term liabilities
|
103.3 | 99.3 | ||||||
|
EQUITY
|
||||||||
|
Common Stock
|
1.8 | 1.8 | ||||||
|
Treasury Stock
|
(11.6 | ) | (3.8 | ) | ||||
|
Additional paid-in capital
|
423.9 | 398.0 | ||||||
|
Retained earnings
|
2,677.2 | 2,420.0 | ||||||
|
Accumulated other comprehensive income
|
184.4 | 194.3 | ||||||
|
Total Common Shareholders' Equity
|
3,275.7 | 3,010.3 | ||||||
|
Non-controlling interest
|
50.9 | 52.8 | ||||||
|
Total Equity
|
3,326.6 | 3,063.1 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 7,296.9 | $ | 6,785.3 | ||||
|
QEP RESOURCES, INC.
|
||||||||
|
CONDENSED CONSOLIDATED CASH FLOWS
|
||||||||
|
(Unaudited)
|
||||||||
|
9 Months Ended September 30,
|
||||||||
|
2011
|
2010
|
|||||||
|
(in millions)
|
||||||||
|
OPERATING ACTIVITIES
|
||||||||
|
Net income
|
$ | 269.7 | $ | 263.3 | ||||
|
Discontinued operations, net of income tax
|
- | (43.2 | ) | |||||
|
Adjustments to reconcile net income to net cash provided by operating activities
|
||||||||
|
Depreciation, depletion and amortization
|
566.4 | 469.5 | ||||||
|
Deferred income taxes
|
155.9 | 206.3 | ||||||
|
Abandonment and impairment
|
16.4 | 29.1 | ||||||
|
Share-based compensation
|
16.5 | 11.3 | ||||||
|
Amortization of debt issuance costs and discounts
|
2.4 | 1.8 | ||||||
|
Dry exploratory well expense
|
0.5 | - | ||||||
|
Net (gain) from asset sales
|
(1.4 | ) | (12.3 | ) | ||||
|
(Income) from unconsolidated affiliates
|
(4.5 | ) | (2.5 | ) | ||||
|
Distributions from unconsolidated affiliates and other
|
7.6 | 2.1 | ||||||
|
Loss on early extinguishment of debt
|
0.7 | 13.3 | ||||||
|
Unrealized (gain) loss on basis-only swaps
|
(86.7 | ) | (90.0 | ) | ||||
|
Changes in operating assets and liabilities
|
12.2 | (80.7 | ) | |||||
|
Net Cash Provided By Operating Activities Of Continuing Operations
|
955.7 | 768.0 | ||||||
|
INVESTING ACTIVITIES
|
||||||||
|
Property acquisitions
|
(40.7 | ) | (94.1 | ) | ||||
|
Property, plant and equipment, including dry exploratory well expense
|
(957.7 | ) | (941.8 | ) | ||||
|
Proceeds from disposition of assets
|
7.4 | 25.4 | ||||||
|
Change in notes receivable
|
- | 52.9 | ||||||
|
Net Cash Used In Investing Activities Of Continuing Operations
|
(991.0 | ) | (957.6 | ) | ||||
|
FINANCING ACTIVITIES
|
||||||||
|
Checks outstanding in excess of cash balances
|
7.2 | - | ||||||
|
Long-term debt issued
|
280.0 | 819.3 | ||||||
|
Long-term debt issuance costs paid
|
(10.5 | ) | (18.1 | ) | ||||
|
Current Portion Long-term debt repaid
|
(58.5 | ) | (91.5 | ) | ||||
|
Repayments of notes payable
|
- | (39.3 | ) | |||||
|
Long-term debt repaid
|
(170.0 | ) | (721.5 | ) | ||||
|
Long-term debt extinguishment costs
|
- | (4.9 | ) | |||||
|
Equity contribution
|
- | 250.0 | ||||||
|
Other capital contributions
|
1.6 | 1.4 | ||||||
|
Dividends paid
|
(10.6 | ) | (3.5 | ) | ||||
|
Distribution from Questar
|
0.2 | (15.7 | ) | |||||
|
Distribution to noncontrolling interest
|
(4.1 | ) | (3.7 | ) | ||||
|
Net Cash Provided from (Used In) Financing Activities Of Continuing Operations
|
35.3 | 172.5 | ||||||
|
CASH USED IN CONTINUING OPERATIONS
|
$ | - | (17.1 | ) | ||||
|
Cash provided by operating activities of discontinued operations
|
- | 68.6 | ||||||
|
Cash used in investing activities of discontinued operations
|
- | (39.9 | ) | |||||
|
Cash used by financing activities of discontinued operations
|
- | (26.9 | ) | |||||
|
Effect of change in cash and cash equivalents of discontinued operations
|
- | (1.8 | ) | |||||
|
Change in cash and cash equivalents
|
- | (17.1 | ) | |||||
|
Beginning cash and cash equivalents
|
- | 19.3 | ||||||
|
Ending cash and cash equivalents
|
$ | - | $ | 2.2 | ||||
|
OPERATIONS BY LINE OF BUSINESS
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
3 Months Ended September 30,
|
9 Months Ended September 30,
|
|||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
(in millions)
|
||||||||||||||||
|
Revenues
|
||||||||||||||||
|
QEP Energy
|
$ | 590.6 | $ | 343.5 | $ | 1,456.5 | $ | 979.0 | ||||||||
|
QEP Field Services
|
116.3 | 75.3 | 331.6 | 234.1 | ||||||||||||
|
QEP Marketing and other
|
145.5 | 145.8 | 444.6 | 461.3 | ||||||||||||
|
Total
|
$ | 852.4 | $ | 564.6 | $ | 2,232.7 | $ | 1,674.4 | ||||||||
|
Operating Income
|
||||||||||||||||
|
QEP Energy
|
$ | 113.9 | $ | 112.2 | $ | 297.1 | $ | 317.0 | ||||||||
|
QEP Field Services
|
68.4 | 35.3 | 188.0 | 111.9 | ||||||||||||
|
QEP Marketing and other
|
1.1 | 2.0 | 4.3 | 5.1 | ||||||||||||
|
Separation costs
|
- | (0.2 | ) | - | (14.2 | ) | ||||||||||
|
Total
|
$ | 183.4 | $ | 149.3 | $ | 489.4 | $ | 419.8 | ||||||||
|
Net Income (Loss) from Continuing Operations Attributable to QEP Resources
|
||||||||||||||||
|
QEP Energy
|
$ | 58.3 | $ | 58.6 | $ | 148.2 | $ | 165.0 | ||||||||
|
QEP Field Services
|
42.0 | 21.0 | 114.2 | 68.5 | ||||||||||||
|
QEP Marketing and other
|
1.6 | 2.0 | 5.5 | 3.6 | ||||||||||||
|
Separation and early debt extinguishment costs
|
(0.4 | ) | (10.5 | ) | (0.4 | ) | (19.1 | ) | ||||||||
|
Total
|
$ | 101.5 | $ | 71.1 | $ | 267.5 | $ | 218.0 | ||||||||
|
QEP RESOURCES, INC.
|
||||||||||||||||
|
SELECTED OPERATING STATISTICS
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
3 Months Ended September 30,
|
9 Months Ended September 30,
|
|||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
QEP Energy production volumes
|
||||||||||||||||
|
Natural gas (Bcf)
|
59.8 | 55.0 | 175.9 | 149.2 | ||||||||||||
|
Oil (Mbbl)
|
922.6 | 790.1 | 2,559.2 | 2,149.5 | ||||||||||||
|
NGL (Mbbl)
|
894.4 | 310.7 | 1,675.0 | 786.9 | ||||||||||||
|
Total production (Bcfe)
|
70.7 | 61.7 | 201.3 | 166.9 | ||||||||||||
|
Average daily production (MMcfe)
|
767.7 | 670.3 | 737.2 | 611.2 | ||||||||||||
|
QEP Energy average net realized price
|
||||||||||||||||
|
Natural gas (per Mcf)
|
$ | 4.00 | $ | 4.64 | $ | 4.03 | $ | 4.81 | ||||||||
|
Oil (per bbl)
|
$ | 82.44 | $ | 63.05 | $ | 85.33 | $ | 64.89 | ||||||||
|
NGL (per bbl)
|
$ | 38.17 | $ | 30.07 | $ | 40.48 | $ | 34.83 | ||||||||
|
Oil and NGL (per bbl)
|
$ | 60.65 | $ | 53.74 | $ | 67.58 | $ | 56.83 | ||||||||
|
Production by Major Area
|
||||||||||||||||
|
QEP Energy - Natural Gas (Bcf)
|
||||||||||||||||
|
Haynesville/CottonValley
|
26.6 | 21.9 | 80.2 | 56.4 | ||||||||||||
|
Midcontinent
|
8.9 | 8.8 | 24.7 | 23.6 | ||||||||||||
|
Pinedale Anticline
|
17.8 | 17.1 | 50.2 | 47.5 | ||||||||||||
|
Uinta Basin
|
3.6 | 3.8 | 11.8 | 11.2 | ||||||||||||
|
Rockies Legacy
|
2.9 | 3.4 | 9.0 | 10.5 | ||||||||||||
|
Total
|
59.8 | 55.0 | 175.9 | 149.2 | ||||||||||||
|
QEP Energy - Oil (Mbbl)
|
||||||||||||||||
|
Haynesville/CottonValley
|
8.8 | 13.8 | 32.8 | 49.8 | ||||||||||||
|
Midcontinent
|
187.0 | 163.4 | 543.5 | 488.3 | ||||||||||||
|
Pinedale Anticline
|
149.2 | 147.1 | 419.0 | 401.9 | ||||||||||||
|
Uinta Basin
|
198.6 | 236.5 | 657.3 | 706.5 | ||||||||||||
|
Rockies Legacy
|
379.0 | 229.3 | 906.6 | 503.0 | ||||||||||||
|
Total
|
922.6 | 790.1 | 2,559.2 | 2,149.5 | ||||||||||||
|
QEP Energy - NGL (Mbbl)
|
||||||||||||||||
|
Haynesville/CottonValley
|
- | - | - | - | ||||||||||||
|
Midcontinent
|
348.3 | 252.3 | 1,013.1 | 622.7 | ||||||||||||
|
Pinedale Anticline
|
489.0 | - | 489.0 | - | ||||||||||||
|
Uinta Basin
|
23.6 | 31.6 | 83.1 | 89.3 | ||||||||||||
|
Rockies Legacy
|
33.5 | 26.8 | 89.8 | 74.9 | ||||||||||||
|
Total
|
894.4 | 310.7 | 1,675.0 | 786.9 | ||||||||||||
|
QEP Production by Major Area (Bcfe)
|
||||||||||||||||
|
Haynesville/CottonValley
|
26.6 | 22.0 | 80.4 | 56.7 | ||||||||||||
|
Midcontinent
|
12.1 | 11.4 | 34.0 | 30.4 | ||||||||||||
|
Pinedale Anticline
|
21.6 | 17.9 | 55.6 | 49.9 | ||||||||||||
|
Uinta Basin
|
4.8 | 5.3 | 16.2 | 15.9 | ||||||||||||
|
Rockies Legacy
|
5.6 | 5.1 | 15.1 | 14.0 | ||||||||||||
|
Total
|
70.7 | 61.7 | 201.3 | 166.9 | ||||||||||||
|
QEP Field Services Gathering Margin
|
||||||||||||||||
|
Gathering
|
$ | 41.9 | $ | 38.9 | $ | 120.0 | $ | 113.3 | ||||||||
|
Other Gathering
|
16.5 | 7.1 | 59.2 | 25.7 | ||||||||||||
|
Gathering (expense)
|
(11.0 | ) | (8.5 | ) | (35.3 | ) | (27.1 | ) | ||||||||
|
Gathering Margin
|
$ | 47.4 | $ | 37.5 | $ | 143.9 | $ | 111.9 | ||||||||
|
Operating Statistics
|
||||||||||||||||
|
Natural gas gathering volumes (millions of MMBtu)
|
||||||||||||||||
|
For unaffiliated customers
|
66.3 | 74.3 | 193.4 | 210.0 | ||||||||||||
|
For affiliated customers
|
60.6 | 52.3 | 173.6 | 144.5 | ||||||||||||
|
Total gathering
|
126.9 | 126.6 | 367.0 | 354.5 | ||||||||||||
|
Gathering revenue (per MMBtu)
|
$ | 0.33 | $ | 0.31 | $ | 0.33 | $ | 0.32 | ||||||||
|
QEP Field Services Processing Margin
|
||||||||||||||||
|
NGL Sales
|
$ | 41.6 | $ | 20.9 | $ | 115.3 | $ | 70.6 | ||||||||
|
Processing (fee based)
|
15.4 | 8.9 | 37.6 | 26.2 | ||||||||||||
|
Other Processing fees
|
1.7 | - | 1.7 | - | ||||||||||||
|
Processing (expense)
|
(3.1 | ) | (2.8 | ) | (8.9 | ) | (8.8 | ) | ||||||||
|
Processing plant shrinkage (expense)
|
(12.5 | ) | (8.0 | ) | (34.1 | ) | (25.9 | ) | ||||||||
|
Processing Margin
|
$ | 43.1 | $ | 19.0 | $ | 111.6 | $ | 62.1 | ||||||||
|
Frac spread (NGL sales – Processing plant shrinkage)
|
$ | 29.1 | $ | 12.9 | $ | 81.2 | $ | 44.7 | ||||||||
|
Operating Statistics
|
||||||||||||||||
|
NGL sales (MMgal)
|
34.0 | 25.8 | 98.2 | 77.3 | ||||||||||||
|
NGL sales price (per gal)
|
$ | 1.23 | $ | 0.81 | $ | 1.17 | $ | 0.91 | ||||||||
|
Fee-based processing (millions of MMBtu)
|
||||||||||||||||
|
For unaffiliated customers
|
31.9 | 29.4 | 96.4 | 87.9 | ||||||||||||
|
For affiliated customers
|
31.9 | 28.2 | 84.7 | 80.5 | ||||||||||||
|
Total fee-based processing volumes
|
63.8 | 57.6 | 181.1 | 168.4 | ||||||||||||
|
Fee-based processing (per MMBtu)
|
$ | 0.24 | $ | 0.16 | $ | 0.21 | $ | 0.16 | ||||||||
|
QEP Marketing gas and oil marketing volumes (millions of MMBtu)
|
108.5 | 60.4 | 254.4 | 170.1 | ||||||||||||
QEP RESOURCES, INC.
NON-GAAP MEASURES
(Unaudited)
This release contains references to a non-GAAP measure of earnings per diluted share from continuing operations excluding gains and losses from asset sales, unrealized gains and losses on basis-only swaps, separation costs and loss on early extinguishment of debt. Management believes earnings per diluted share excluding asset sales, unrealized basis-only swaps, separation costs and loss on early extinguishment of debt is an important measure of the Company's operational performance relative to other gas and oil producing companies.
The following table calculates earnings per diluted share excluding gains and losses on assets sales, unrealized gains and losses on basis-only swaps, separations costs and loss on early extinguishment of debt:
|
3 Months Ended September 30,
|
9 Months Ended September 30,
|
|||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
(in millions, except earnings per share)
|
||||||||||||||||
|
Net income attributable to QEP Resources
|
$ | 101.5 | $ | 71.1 | $ | 267.5 | $ | 261.2 | ||||||||
|
Less: Discontinued operations
|
- | - | - | (43.2 | ) | |||||||||||
|
Net Income from continuing operations attributable to QEP Resources
|
$ | 101.5 | $ | 71.1 | $ | 267.5 | $ | 218.0 | ||||||||
|
Exclusion of net (gain) loss from assets sales, unrealized (gain) loss on basis-only swaps, separation costs and loss on early extinguishment of debt from net income
|
||||||||||||||||
|
Net (gain) loss from asset sales
|
(1.2 | ) | (10.8 | ) | (1.4 | ) | (12.3 | ) | ||||||||
|
Income taxes on net (gain) loss on asset sales
|
0.4 | 3.9 | 0.5 | 4.5 | ||||||||||||
|
Unrealized (gain) loss on basis-only swaps
|
(27.9 | ) | (27.9 | ) | (86.7 | ) | (90.0 | ) | ||||||||
|
Income taxes on unrealized (gain) loss on basis-only swaps
|
10.3 | 10.4 | 32.2 | 33.4 | ||||||||||||
|
Separation costs
|
- | 0.2 | - | 14.2 | ||||||||||||
|
Income taxes on separation costs
|
- | 2.1 | - | (3.3 | ) | |||||||||||
|
Loss from early extinguishment of debt
|
0.7 | 13.3 | 0.7 | 13.3 | ||||||||||||
|
Income taxes on loss from early extinguishment of debt
|
(0.3 | ) | (5.1 | ) | (0.3 | ) | (5.1 | ) | ||||||||
|
After-tax (gain) loss on assets sales, unrealized (gain) loss on basis-only swaps, separation costs and loss from early extinguishment of debt
|
(18.0 | ) | (13.9 | ) | (55.0 | ) | (45.3 | ) | ||||||||
|
Net income attributable to QEP Resources excluding (gain) loss from assets sales, unrealized (gain) loss on basis-only swaps, separation costs and loss from early extinguishment of debt
|
$ | 83.5 | $ | 57.2 | $ | 212.5 | $ | 172.7 | ||||||||
|
EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ATTRIBUTABLE TO QEP RESOURCES
|
||||||||||||||||
|
Diluted
|
$ | 0.57 | $ | 0.40 | $ | 1.50 | $ | 1.23 | ||||||||
|
Diluted after-tax (gain) loss from asset sales, unrealized (gain) loss on basis-only swaps, separation costs and loss from early extinguishment of debt
|
(0.10 | ) | (0.08 | ) | (0.31 | ) | (0.26 | ) | ||||||||
|
Earnings per diluted share attributable to QEP Resources excluding asset sales, unrealized (gain) loss on basis only swaps, separation costs and loss from early extinguishment of debt
|
$ | 0.47 | $ | 0.32 | $ | 1.19 | $ | 0.97 | ||||||||
|
Weighted-Average Common Shares Outstanding
|
||||||||||||||||
|
Diluted
|
178.5 | 177.9 | 178.5 | 177.6 | ||||||||||||
This release also contains references to a non-GAAP measure of adjusted EBITDA. Management defines adjusted EBITDA as net income before the following items: discontinued operations, unrealized gains and losses on basis-only swaps, gains and losses from asset sales, interest and other income, income taxes, interest expense, separation costs, loss on early extinguishment of debt, depreciation, depletion, and amortization, abandonment and impairment, and exploration expense. Management believes adjusted EBITDA is an important measure of the Company's cash flow and liquidity and an important measure for comparing the Company's financial performance to other gas and oil producing companies.
The following table reconciles QEP Resources’ net income to adjusted EBITDA:
|
3 Months Ended September 30,
|
9 Months Ended September 30,
|
|||||||||||||||
|
2011
|
2010
|
2011
|
2010
|
|||||||||||||
|
(in millions)
|
||||||||||||||||
|
Net income attributable to QEP Resources
|
$ | 101.5 | $ | 71.1 | $ | 267.5 | $ | 261.2 | ||||||||
|
Net income attributable to non-controlling interest
|
0.9 | 0.8 | 2.2 | 2.1 | ||||||||||||
|
Net Income
|
102.4 | 71.9 | 269.7 | 263.3 | ||||||||||||
|
Discontinued operations, net of tax
|
- | - | - | (43.2 | ) | |||||||||||
|
Income from continuing operations
|
102.4 | 71.9 | 269.7 | 220.1 | ||||||||||||
|
Unrealized (gain) loss on basis-only swaps
|
(27.9 | ) | (27.9 | ) | (86.7 | ) | (90.0 | ) | ||||||||
|
Net (gain) loss from asset sales
|
(1.2 | ) | (10.8 | ) | (1.4 | ) | (12.3 | ) | ||||||||
|
Interest and other income
|
0.7 | (1.6 | ) | 0.5 | (4.4 | ) | ||||||||||
|
Income taxes
|
59.1 | 44.2 | 156.0 | 130.5 | ||||||||||||
|
Interest expense
|
22.8 | 22.6 | 67.0 | 62.8 | ||||||||||||
|
Separation costs
|
- | 0.2 | - | 14.2 | ||||||||||||
|
Loss from early extinguishment of debt
|
0.7 | 13.3 | 0.7 | 13.3 | ||||||||||||
|
Depreciation, depletion and amortization
|
189.0 | 170.5 | 566.4 | 469.5 | ||||||||||||
|
Abandonment and impairment
|
5.7 | 12.2 | 16.4 | 29.1 | ||||||||||||
|
Exploration
|
2.4 | 2.9 | 7.5 | 9.2 | ||||||||||||
|
Adjusted EBITDA
|
$ | 353.7 | $ | 297.5 | $ | 996.1 | $ | 842.0 | ||||||||