Attached files
| file | filename |
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| 8-K - WHITING PETROLEUM FORM 8-K, DATED JULY 25, 2012 - WHITING PETROLEUM CORP | form8-l.htm |
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Company contact:
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John B. Kelso, Director of Investor Relations
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303.837.1661 or john.kelso@whiting.com
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Whiting Petroleum Corporation Announces Second Quarter
2012 Financial and Operating Results
Q2 2012 Production Up 26% from Q2 2011
Q2 2012 Net Income Available to Common Shareholders of $150.6
Million or $1.27 per Diluted Share and Adjusted Net Income of $86.8
Million or $0.73 per Diluted Share
Q2 2012 Discretionary Cash Flow Totals $310.5 Million
Increasing 2012 Production Guidance to 20% - 23% over 2011 and
Capital Budget to $1.9 Billion from $1.8 Billion
Company Reports Positive Results from its Williston Basin Pad
Drilling Program and Continued Success in the Permian Basin
DENVER – July 25, 2012 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the second quarter of 2012 totaled 7.34 million barrels of oil equivalent (MMBOE), of which 86% were crude oil/natural gas liquids (NGLs). This second quarter 2012 production total equates to a daily average production rate of 80,700 barrels of oil equivalent (BOE), representing a 26% increase over the second quarter 2011 average daily rate of 64,120 BOE per day. During the second quarter, Whiting replaced the approximate 4,500 BOE per day of production that was conveyed from Whiting Petroleum Corporation to Whiting USA Trust II effective March 28, 2012, through new drilling. Production would have increased 33% without the Trust II conveyance.
Based on continued good results across our properties, we are increasing our 2012 production growth guidance to 20% - 23% from 17% - 22% and revising upward our capital budget to $1.9 billion from $1.8 billion.
James J. Volker, Whiting’s Chairman and CEO, commented, “Our objectives for 2012 remain intact:
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·
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We continue to execute on our active drilling program and have increased our guidance for the third time this year to a range of 20% to 23% production growth;
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·
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Our plan to drill 257 gross (160 net) wells throughout our prospect areas remains unchanged. By high-grading our drilling rig fleet and using pad drilling and sliding sleeve completions, we believe we can efficiently reach our 2012 drilling goals;
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·
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At current oil prices, our discretionary cash flow, recent WHZ Trust unit sale and Belfield Plant sale will substantially fund our 2012 capital budget of $1.9 billion;
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·
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We continue to experience success in emerging development areas such as Big Tex and build solid acreage positions in new exploration areas at attractive prices and attractive net revenue interests.
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·
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We continue to monitor oil prices and have flexibility in our rig contracts. Of our 29 contracted rigs 13 have contracts that can be terminated without penalty by December 31, 2012 and another seven have contracts that can be terminated without penalty by December 31, 2013. Currently our plans call for the release of three rigs. One in Sanish in early September, one in Hidden Bench in late August and one in Pronghorn in late August. These are generally less efficient rigs when compared to others we have under contract. Due to the efficiency of the rigs we will retain under contract, we anticipate no reduction in the number of wells we intend to drill in 2012."
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Mr. Volker continued, “We added more than 10,500 net acres to our Williston Basin acreage position in the second quarter and now hold over 712,000 net acres in the Basin. With further drilling in our new development areas and our established core properties, we expect a strong second half in 2012."
2
Operating and Financial Results
The following table summarizes the second quarter operating and financial results for 2012 and 2011:
| Three Months Ended June 30, | |||||||||
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2012
|
2011
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Change
|
|||||||
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Production (MBOE/d)
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80.70 | 64.12 | 26% | ||||||
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Discretionary Cash Flow-MM$ (1)
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310.5 | 313.3 | (1%) | ||||||
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Realized Price ($/BOE)
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66.13 | 78.45 | (16%) | ||||||
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Total Revenues-MM$
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502.2 | 481.2 |
4%
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||||||
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Net Income Available to Common Shareholders-MM$
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150.6 | 202.9 | (26%) | ||||||
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Per Basic Share
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$ | 1.28 | $ | 1.73 | (26%) | ||||
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Per Diluted Share
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$ | 1.27 | $ | 1.71 | (26%) | ||||
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Adjusted Net Income Available to Common Shareholders-MM$ (2)
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86.8 | 120.3 | (28%) | ||||||
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Per Basic Share
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$ | 0.74 | $ | 1.02 | (27%) | ||||
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Per Diluted Share
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$ | 0.73 | $ | 1.02 | (28%) | ||||
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(1)
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A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.
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(2)
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A reconciliation of adjusted net income available to common shareholders to net income available to common shareholders is included later in this news release.
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Historically, Whiting included the price of NGLs in its oil differentials and its guidance. In the second quarter, NGLs represented 11.2% of the Company’s total liquids production and reduced our overall liquids price by $4.76 per barrel. Our true crude oil differential was $13.59 per barrel.
In this news release and going forward, we will break out our NGL production from our crude oil production along with the average price of each. We will continue to provide guidance for crude oil and natural gas differentials.
3
Operations Update
Pictured above a Whiting drilling operation: one well drilling, one well being completed and one well producing in Sanish Field in Mountrail County, North Dakota.
Core Development Areas
Bakken and Three Forks Development
Sanish Field.
Whiting’s net production from the Sanish Field averaged 31,530 BOE per day in the second quarter of 2012, an increase of 10% from 28,790 in the first quarter of 2012.
Highlighting recent results in the Sanish field were the completions of our first two wells using pad-style completions. Both wells were drilled on the western side of the Sanish field. The S-Bar 14-7XH, a cross-unit well, was completed in the Middle Bakken flowing 1,568 BOE per day on May 21, 2012. The well’s 9,658-foot lateral was fracture stimulated in a total of 30 stages.
The adjacent 10,121-foot lateral at the S-Bar 14-7TFX was fraced in 25 stages soon after the S-Bar 14-7XH. This cross-unit well was completed in the Three Forks formation flowing 955 BOE per day on May 27, 2012.
4
Combined with our DWOP (Drill Wells on Paper) training, white sand and sliding sleeve completions, pad drilling is providing efficiencies for drilling and fracture stimulation that lead to an estimated savings of $2 million per well. These factors enable us to drill and complete our Williston Basin wells for approximately $7 million. Each rig now drills approximately 12 wells per year rather than 10 and allows wells to be efficiently fraced and placed on production sequentially thereby minimizing equipment moves and truck traffic. Currently 25% of our rig fleet in the Williston Basin is pad capable. We anticipate that over 50% will be pad capable by year-end 2012.
Also of note at the Sanish field was the July 5, 2012 completion of our highest-rate wing well to date. The Smith 41-12H flowed 2,974 BOE per day from the Middle Bakken. The well’s 6,996-foot lateral was fracture stimulated in a total of 22 stages.
Lewis & Clark/Pronghorn Prospects. Whiting’s net production from the Lewis & Clark/Pronghorn prospects averaged 10,275 BOE per day in the second quarter of 2012. We own 381,403 gross (261,445 net) acres in the Lewis & Clark/Pronghorn prospects.
We completed our first two wells off a pad at the Pronghorn prospect. The 3J Trust 34-8TFH was completed in the Pronghorn Sand formation flowing 2,254 BOE per day. The well’s 10,568-foot lateral was fraced in 30 stages. Whiting owns an 88% working interest and a 71% net revenue interest in the 3J Trust 34-8TFH well. The 3J Trust 24-8PH flowed 2,157 BOE per day on completion in the Pronghorn Sand. The well’s 10,001-foot lateral was fraced in 30 stages. The Company holds an 89% working interest and a 71% net revenue interest in the 3J Trust 24-8PH well. Both 3J Trust wells were tested on June 22, 2012.
Hidden Bench/Tarpon Prospects. Whiting’s net production from the Hidden Bench/Tarpon prospects averaged 2,190 BOE per day in the second quarter of 2012. We currently hold 58,124 gross (36,301 net) acres in the Hidden Bench/Tarpon prospects, which are located in McKenzie County, North Dakota. Of note at Hidden Bench is the recent completion of the Johnson 34-33H. This well was completed in the Middle Bakken formation on May 25, 2012 flowing 2,213 BOE per day. We hold a 94% working interest and a 75% net revenue interest in the well.
Missouri Breaks Prospect. In the second quarter, we acquired an additional 4,000 net undeveloped acres and now hold 89,580 gross (61,794 net) acres in the Missouri Breaks prospect, located in Richland County, Montana. To date, we have drilled and completed three wells on the western portion of our Missouri Breaks prospect. Going forward, we estimate ultimate recoveries in the 300,000 – 400,000 BOE range in this area.
5
Big Island Red River Play. We have identified more than 50 vertical Red River prospects at our Big Island play in Golden Valley County, North Dakota, using 3-D seismic interpretations as well as porosity anomalies. All five vertical Red River wells drilled to date at Big Island have been completed as successful oil producers. Estimated ultimate recoveries for these wells range from 200,000 BOE to 300,000 BOE. The wells have an estimated completed well cost of approximately $3.5 million.
Midstream Assets
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Robinson Lake Gas Plant pictured to the left: 112 miles of oil lines, 321 miles of gas lines, 540 wells connected, 1,538 estimated total wells can be connected, 60 MMcf per day current volume, 90 MMcf per day planned processing capacity, $122MM estimated total capital investment, $40MM estimated net income in 2013. Capital investment and net income estimates pertain to Whiting’s 50% ownership interest.
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Robinson Lake Gas Plant. As of July 9, 2012, the plant was processing approximately 60 MMcf of gas per day (gross). There is inlet compression in place to process 64 MMcf per day. We plan to add compression to bring the inlet capacity to 72 MMcf per day by August 2012 and we have the ability to increase to 90 MMcf per day in the future. Whiting owns a 50% interest in the plant.
Belfield Gas Processing Plant. In May 2012, we sold a 50% ownership interest in our Belfield gas processing plant, gas gathering, oil gathering and related facilities in Stark County, North Dakota. The transaction was executed with Bitter Creek Pipelines, LLC, a subsidiary of MDU Resources. Under the agreement, Bitter Creek Pipelines paid 60% of the capital costs of the project to date and will pay 60% of certain future capital costs with respect to its 50% ownership. A $66.2 million payment was made to Whiting at closing for capital costs to date. Fidelity Exploration & Production Company, also a subsidiary of MDU, has dedicated gas production from its development activity in the area to the Belfield gas plant. Whiting is pleased to have MDU as a partner in the Belfield gas plant. Whiting will continue to operate the facilities.
As of July 9, 2012, the Belfield plant was processing 13.1 MMcf of gas per day (gross). Currently, there is inlet compression in place to process 24 MMcf per day. Whiting owns 50% of the Belfield plant.
6
EOR Projects
North Ward Estes Field. Net production from our North Ward Estes field averaged 8,630 BOE per day in the second quarter of 2012. This average rate was up 6% from the 8,125 BOE average daily rate in the second quarter of 2011. One of the largest phases at North Ward Estes (Phase 3B) is pressuring up with CO2, and we anticipate a production response by the first quarter of 2013. Whiting is currently injecting approximately 330 MMcf of CO2 per day into the field, of which about 60% is recycled gas.
Other Development Areas
Delaware Basin: Big Tex Prospect. Whiting’s lease position at Big Tex consists of 117,521 gross (87,017 net) acres, located primarily in Pecos County, Texas. Highlighting recent drilling results was the completion of the May 2501. This vertical well was completed flowing 323 BOE per day from the Upper Wolfcamp formation on May 24, 2012. Whiting owns a 100% working interest and an 80% net revenue interest in the new producer, which was drilled on the west side of the prospect approximately one mile southwest of the Company’s Stewart 101 well. The Stewart well flowed 232 BOE per day from the Wolfcamp at a vertical depth of approximately 12,000 feet on February 20, 2012.
On the north side of the prospect, we have fracture stimulated the Legear 1102H, a horizontal Wolfcamp test. The well is currently flowing back oil and load water up casing as it cleans up. The Legear well is overpressured. Once pressures decrease, we plan to put the well on pump and obtain an initial production rate. Whiting holds a 100% working interest and a 75% net revenue interest in the Legear well.
Denver Basin: Redtail Niobrara Prospect. The Redtail prospect targets the Niobrara formation in the Denver Basin, in Weld County, Colorado. In the second quarter, we added approximately 4,500 net acres to our acreage position at Redtail, bringing our total acreage to 106,889 gross (79,256 net) acres in the play. We resumed drilling operations at Redtail in June 2012. We currently have one well waiting on completion and one well drilling.
7
Operated Drilling and Workover Rig Count
As of June 30, 2012, 25 operated drilling rigs and 75 operated workover rigs were active on our properties.
The breakdown of our operated rigs as of June 30, 2012 was as follows:
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Region
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Drilling
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Workover
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||||||
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Northern Rockies
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20 | 26 | ||||||
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Permian Basin
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1 | 10 | ||||||
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Central Rockies
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2 | - | ||||||
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EOR Projects
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Postle
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2 | 4 | ||||||
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North Ward Estes
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- | 35 | ||||||
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Totals
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25 | 75 | ||||||
We have 29 drilling rigs under contract. Four of these contracts commence subsequent to June 30, 2012, which explains the difference between our second quarter operated rig count of 25 and our 29 contracted rig count. Thirteen of the total 29 contracted rigs have contracts that can be terminated without penalty by December 31, 2012 and another seven rigs have contracts that can be terminated without penalty by December 31, 2013.
Currently our plans call for the release of three rigs. One in Sanish in early September, one in Hidden Bench in late August and one in Pronghorn in late August. These are generally less efficient rigs when compared to others we have under contract. Due to the efficiency of the rigs we will retain under contract, we anticipate no reduction in the number of wells we intend to drill in 2012.
8
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended June 30, 2012 and 2011:
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Three Months
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||||||||||
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Ended June 30,
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||||||||||
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Production
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2012
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2011
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Change
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Oil (MMBbls)
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5.58 | 4.31 | 29% | |||||||
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NGLs (MMBOE)
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0.70 | 0.48 | 46% | |||||||
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Natural gas (Bcf)
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6.38 | 6.29 | 1% | |||||||
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Total equivalent (MMBOE)
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7.34 | 5.84 | 26% | |||||||
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Average Sales Price
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||||||||||
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Oil (per Bbl):
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||||||||||
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Price received
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$ | 79.92 | $ | 96.88 | (18%) | |||||
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Effect of crude oil hedging (1)
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(1.35 | ) | (3.78 | ) | ||||||
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Realized price
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$ | 78.57 | $ | 93.10 | (16%) | |||||
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NYMEX oil (per Bbl)
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$ | 93.51 | $ | 102.55 | (9%) | |||||
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NGLs (per BOE):
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||||||||||
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Realized price
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$ | 37.45 | $ | 53.22 | (30%) | |||||
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Natural gas (per Mcf):
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||||||||||
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Price received
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$ | 3.25 | $ | 4.94 | (34%) | |||||
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Effect of natural gas hedging (1)
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0.06 | 0.03 | ||||||||
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Realized price
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$ | 3.31 | $ | 4.97 | (33%) | |||||
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NYMEX natural gas (per Mcf)
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$ | 2.21 | $ | 4.32 | (49%) | |||||
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(1)
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Whiting realized pre-tax cash settlement losses of $7.5 million on its crude oil hedges and gains of $0.4 million on its natural gas hedges during the second quarter of 2012. A summary of Whiting’s outstanding hedges is included later in this news release.
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9
Second Quarter and First Half 2012 Costs and Margins
A summary of production, cash revenues and cash costs on a per BOE basis is as follows:
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Per BOE, Except Production
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||||||||||||||||
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Three Months
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Six Months
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Ended June 30,
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Ended June 30,
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|||||||||||||||
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2012
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2011
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2012
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2011
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Production (MMBOE)
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7.34 | 5.84 | 14.69 | 11.78 | ||||||||||||
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Sales price, net of hedging
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$ | 66.13 | $ | 78.45 | $ | 70.15 | $ | 74.36 | ||||||||
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Lease operating expense
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12.19 | 12.65 | 12.54 | 12.34 | ||||||||||||
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Production tax
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5.55 | 5.87 | 5.81 | 5.60 | ||||||||||||
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General & administrative
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3.43 | 3.58 | 4.06 | 3.34 | ||||||||||||
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Exploration
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1.84 | 2.12 | 1.58 | 2.29 | ||||||||||||
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Cash interest expense
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2.12 | 2.26 | 2.16 | 2.17 | ||||||||||||
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Cash income tax expense
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0.15 | 0.27 | 0.17 | 0.31 | ||||||||||||
| $ | 40.85 | $ | 51.70 | $ | 43.83 | $ | 48.31 | |||||||||
2012 Capital Budget
We increased our 2012 capital budget to $1,900 million from $1,800 million. Our revised 2012 capital budget is currently allocated among our major development areas as indicated in the table below:
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2012 CAPEX (MM)
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Gross Wells
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Net Wells
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% of Total
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||||||||||||
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Northern Rockies
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$ | 851 | 218 | 124 | 45% | ||||||||||
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EOR
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223 |
NA
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(1) |
NA
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(1) | 12% | |||||||||
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Permian
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97 | 19 | 19 | 5% | |||||||||||
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Central Rockies
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85 | 20 | 17 | 4% | |||||||||||
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Non-Operated
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160 | - | - | 8% | |||||||||||
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Land
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163 | - | - | 9% | |||||||||||
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Exploration Expense(2)
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56 | - | - | 3% | |||||||||||
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Facilities
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215 | - | - | 11% | |||||||||||
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Well Work, Misc. Costs, Other
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50 | - | - | 3% | |||||||||||
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Total Budget
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$ | 1,900 | (3) | 257 | 160 | 100% | |||||||||
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(1)
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These multi-year CO2 projects involve many re-entries, workovers and conversions. Therefore, they are budgeted on a project basis not a well basis.
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(2)
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Comprised primarily of exploration salaries, seismic activities and delay rentals.
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(3)
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The change in our 2012 capital budget consisted of increases of $50MM in well recompletions and capitalized workovers, $46MM in our EOR projects (primarily Residual Oil Zone capex), $27MM in non-operated drilling and a reduction of $23MM to our facilities budget due to the Belfield plant sale.
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10
Second Quarter and First Half 2012 Drilling and Expenditures Summary
The table below summarizes Whiting’s operated and non-operated drilling activity and capital expenditures for the three and six months ended June 30, 2012:
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Gross/Net Wells Completed
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|||||||||
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Total New
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% Success
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CAPEX
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Producing
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Non-Producing
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Drilling
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Rate
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(in MM)
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|||||
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Q2 12
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91 / 44.1
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0 / 0
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91 / 44.1
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100% / 100%
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$456.0
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||||
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6M 12
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175 / 79.9
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0 / 0
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175 / 79.9
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100% / 100%
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$984.0
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||||
Outlook for Third Quarter and Full-Year 2012
The following table provides guidance for the third quarter and full-year 2012 based on current forecasts, including Whiting’s full-year 2012 capital budget of $1,900 million.
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Guidance
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||||||||||||||||||||
| Third Quarter | Full-Year | |||||||||||||||||||
| 2012 | 2012 | |||||||||||||||||||
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Production (MMBOE)
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7.40 | - | 7.80 | 29.70 | - | 30.50 | ||||||||||||||
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Lease operating expense per BOE
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$ | 11.90 | - | $ | 12.30 | $ | 12.20 | - | $ | 12.50 | ||||||||||
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General and admin. expense per BOE
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$ | 3.30 | - | $ | 3.60 | $ | 3.60 | - | $ | 3.90 | ||||||||||
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Interest expense per BOE
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$ | 2.30 | - | $ | 2.50 | $ | 2.30 | - | $ | 2.60 | ||||||||||
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Depr., depletion and amort. per BOE
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$ | 22.10 | - | $ | 22.70 | $ | 21.90 | - | $ | 22.30 | ||||||||||
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Prod. taxes (% of production revenue)
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8.3% | - | 8.5% | 8.2% | - | 8.4% | ||||||||||||||
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Oil price differentials to NYMEX per Bbl (1)
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( | $ | 9.00 | ) | - | ( | $ | 10.00 | ) | ( | $ | 10.50 | ) | - | ( | $ | 11.50 | ) | ||
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Gas price premium to NYMEX per Mcf (2)
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$ | 0.60 | - | $ | 0.90 | $ | 0.60 | - | $ | 0.90 | ||||||||||
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(1)
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Does not include the effect of NGLs.
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(2)
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Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release.
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11
Oil Hedges
The following summarizes Whiting’s crude oil hedges as of July 16, 2012:
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Weighted Average
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As a Percentage of
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|||||
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Hedge
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Contracted Volume
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NYMEX Price Collar Range
|
June 2012
|
|||
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Period
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(Bbls per Month)
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(per Bbl)
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Oil Production
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|||
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2012
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||||||
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Q3
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1,163,440
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$68.93 - $106.81 (1)
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54.9%
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|||
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Q4
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1,163,157
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$68.93 - $106.81 (1)
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54.8%
|
|||
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2013
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||||||
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Q1
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294,560
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$48.17 - $90.71
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13.9%
|
|||
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Q2
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294,550
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$48.17 - $90.71
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13.9%
|
|||
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Q3
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294,450
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$48.16 - $90.70
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13.9%
|
|||
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Oct
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294,340
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$48.15 - $90.69
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13.9%
|
|||
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Nov
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194,340
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$47.96 - $85.90
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9.2%
|
|||
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Dec
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4,340
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$80.00 - $122.50
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0.2%
|
|||
|
2014
|
||||||
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Q1
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4,250
|
$80.00 - $122.50
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0.2%
|
|||
|
Q2
|
4,150
|
$80.00 - $122.50
|
0.2%
|
|||
|
Q3
|
4,060
|
$80.00 - $122.50
|
0.2%
|
|||
|
Q4
|
3,970
|
$80.00 - $122.50
|
0.2%
|
|
(1)
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In July, Whiting added two new oil hedges as follows:
|
|
Hedge
|
Contracted Volume
|
NYMEX Floor
|
NYMEX Ceiling
|
|||
|
Period
|
(Bbls per Month)
|
(per Bbl)
|
(per Bbl)
|
|||
|
July – Dec. 2012
|
75,000
|
$80.00
|
$96.45
|
|||
|
July – Dec. 2012
|
100,000
|
$80.00
|
$96.70
|
These new hedges are included in the calculation of the Weighted Average Collar Range shown above.
12
The following summarizes Whiting Petroleum Corporation’s natural gas hedges as of July 16, 2012:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
NYMEX Price Collar Range
|
June 2012
|
|||
|
Period
|
(Mcf per Month)
|
(per Mcf)
|
Gas Production
|
|||
|
2012
|
||||||
|
Q3
|
31,502
|
$6.00 - $14.45
|
1.5%
|
|||
|
Q4
|
30,640
|
$7.00 - $13.40
|
1.5%
|
Whiting also has the following fixed-price natural gas contracts in place as of July 16, 2012:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
Contracted Price
|
June 2012
|
|||
|
Period
|
(MMBtu per Month)
|
(per MMBtu)
|
Gas Production
|
|||
|
2012
|
||||||
|
Q3
|
465,630
|
$5.41
|
22.3%
|
|||
|
Q4
|
398,667
|
$5.46
|
19.1%
|
|||
|
2013
|
||||||
|
Q1
|
360,000
|
$5.47
|
17.2%
|
|||
|
Q2
|
364,000
|
$5.47
|
17.4%
|
|||
|
Q3
|
368,000
|
$5.47
|
17.6%
|
|||
|
Q4
|
368,000
|
$5.47
|
17.6%
|
|||
|
2014
|
||||||
|
Q1
|
330,000
|
$5.49
|
15.8%
|
|||
|
Q2
|
333,667
|
$5.49
|
16.0%
|
|||
|
Q3
|
337,333
|
$5.49
|
16.1%
|
|||
|
Q4
|
337,333
|
$5.49
|
16.1%
|
13
Selected Operating and Financial Statistics
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
Selected operating statistics
|
||||||||||||||||
|
Production
|
||||||||||||||||
|
Oil, MBbl
|
5,577 | 4,307 | 11,159 | 8,591 | ||||||||||||
|
NGLs, MBOE
|
703 | 480 | 1,367 | 970 | ||||||||||||
|
Natural gas, MMcf
|
6,383 | 6,289 | 12,987 | 13,289 | ||||||||||||
|
Oil equivalents, MBOE
|
7,344 | 5,835 | 14,691 | 11,775 | ||||||||||||
|
Average Prices
|
||||||||||||||||
|
Oil per Bbl (excludes hedging)
|
$ | 79.92 | $ | 96.88 | $ | 85.22 | $ | 91.16 | ||||||||
|
NGL per BOE
|
$ | 37.45 | $ | 53.22 | $ | 41.73 | $ | 51.94 | ||||||||
|
Natural gas per Mcf (excludes hedging)
|
$ | 3.25 | $ | 4.94 | $ | 3.35 | $ | 4.97 | ||||||||
|
Per BOE Data
|
||||||||||||||||
|
Sales price (including hedging)
|
$ | 66.13 | $ | 78.45 | $ | 70.15 | $ | 74.36 | ||||||||
|
Lease operating
|
$ | 12.19 | $ | 12.65 | $ | 12.54 | $ | 12.34 | ||||||||
|
Production taxes
|
$ | 5.55 | $ | 5.87 | $ | 5.81 | $ | 5.60 | ||||||||
|
Depreciation, depletion and amortization
|
$ | 21.87 | $ | 18.89 | $ | 21.56 | $ | 18.51 | ||||||||
|
General and administrative (1)
|
$ | 3.43 | $ | 3.58 | $ | 4.06 | $ | 3.34 | ||||||||
|
Selected Financial Data
|
||||||||||||||||
|
(In thousands, except per share data)
|
||||||||||||||||
|
Total revenues and other income
|
$ | 502,174 | $ | 481,206 | $ | 1,065,880 | $ | 913,427 | ||||||||
|
Total costs and expenses
|
$ | 260,894 | $ | 163,688 | $ | 667,155 | $ | 563,685 | ||||||||
|
Net income available to common shareholders
|
$ | 150,612 | $ | 202,880 | $ | 248,813 | $ | 222,024 | ||||||||
|
Earnings per common share, basic
|
$ | 1.28 | $ | 1.73 | $ | 2.12 | $ | 1.89 | ||||||||
|
Earnings per common share, diluted
|
$ | 1.27 | $ | 1.71 | $ | 2.10 | $ | 1.87 | ||||||||
|
Weighted average shares outstanding, basic
|
117,622 | 117,373 | 117,569 | 117,308 | ||||||||||||
|
Weighted average shares outstanding, diluted
|
118,853 | 118,659 | 118,889 | 118,707 | ||||||||||||
|
Net cash provided by operating activities
|
$ | 282,193 | $ | 374,163 | $ | 635,185 | $ | 588,218 | ||||||||
|
Net cash used in investing activities
|
$ | (464,883 | ) | $ | (445,357 | ) | $ | (677,935 | ) | $ | (846,613 | ) | ||||
|
Net cash provided by financing activities
|
$ | 179,672 | $ | 77,257 | $ | 33,746 | $ | 250,532 | ||||||||
|
(1)
|
For the six months ended June 30, 2012, the cost includes the effect of a one-time charge under our Production Participation Plan related to the Whiting USA Trust II of $0.59 per BOE.
|
14
Conference Call
The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, July 26, 2012 at 11:00 a.m. EDT (10:00 a.m. CDT, 9:00 a.m. MDT) to discuss Whiting’s second quarter 2012 financial and operating results. Please call (888) 396-2384 (U.S./Canada) or (617) 847-8711 (International) and enter the pass code 24584957 to be connected to the call. Access to a live Internet broadcast will be available at www.whiting.com by clicking on the “Investor Relations” box on the menu and then on the link titled “Webcasts.” Slides for the conference call will be available on this website beginning at 11:00 a.m. (EDT) on July 26, 2012.
A telephonic replay will be available beginning approximately two hours after the call on Thursday, July 26, 2012 and continuing through Thursday, August 2, 2012. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 61822693. You may also access a web archive at www.whiting.com beginning approximately one hour after the conference call.
About Whiting Petroleum Corporation
Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that explores for, develops, acquires and produces oil, natural gas and natural gas liquids primarily in the Rocky Mountain, Permian Basin, Mid-Continent, Michigan and Gulf Coast regions of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota and its Enhanced Oil Recovery fields in Oklahoma and Texas. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit www.whiting.com.
Forward-Looking Statements
This news release contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this news release, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
15
These risks and uncertainties include, but are not limited to: declines in oil or natural gas prices; our level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; our ability to obtain sufficient quantities of CO2 necessary to carry out our enhanced oil recovery projects; inaccuracies of our reserve estimates or our assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; risks related to our level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations and acquisitions; federal and state initiatives relating to the regulation of hydraulic fracturing; the potential impact of federal debt reduction initiatives and tax reform legislation being considered by the U.S. Federal government that could have a negative effect on the oil and gas industry; impacts of the global recession and tight credit markets; our ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; our ability to successfully complete potential asset dispositions; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry in the regions in which we operate; risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors” in our Annual Report on Form 10-K for the period ended December 31, 2011. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.
16
SELECTED FINANCIAL DATA
For further information and discussion on the selected financial data below, please refer to Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
|
June 30,
2012
|
December 31,
2011
|
|||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 6,807 | $ | 15,811 | ||||
|
Accounts receivable trade, net
|
293,672 | 262,515 | ||||||
|
Prepaid expenses and other
|
23,220 | 20,377 | ||||||
|
Total current assets
|
323,699 | 298,703 | ||||||
|
Property and equipment:
|
||||||||
|
Oil and gas properties, successful efforts method:
|
||||||||
|
Proved properties
|
7,765,534 | 7,221,550 | ||||||
|
Unproved properties
|
382,495 | 354,774 | ||||||
|
Other property and equipment
|
155,482 | 150,933 | ||||||
|
Total property and equipment
|
8,303,511 | 7,727,257 | ||||||
|
Less accumulated depreciation, depletion and amortization
|
(2,238,740 | ) | (2,088,517 | ) | ||||
|
Total property and equipment, net
|
6,064,771 | 5,638,740 | ||||||
|
Debt issuance costs
|
29,735 | 33,306 | ||||||
|
Other long-term assets
|
92,379 | 74,860 | ||||||
|
TOTAL ASSETS
|
$ | 6,510,584 | $ | 6,045,609 | ||||
17
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share data)
|
June 30,
2012
|
December 31,
2011
|
|||||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable trade
|
$ | 102,004 | $ | 56,673 | ||||
|
Accrued capital expenditures
|
109,635 | 142,827 | ||||||
|
Accrued liabilities and other
|
146,012 | 157,214 | ||||||
|
Revenues and royalties payable
|
116,410 | 103,894 | ||||||
|
Taxes payable
|
35,099 | 31,195 | ||||||
|
Derivative liabilities
|
23,364 | 73,647 | ||||||
|
Deferred income taxes
|
11,140 | 1,584 | ||||||
|
Total current liabilities
|
543,664 | 567,034 | ||||||
|
Long-term debt
|
1,420,000 | 1,380,000 | ||||||
|
Deferred income taxes
|
960,284 | 823,643 | ||||||
|
Derivative liabilities
|
17,085 | 47,763 | ||||||
|
Production Participation Plan liability
|
80,641 | 80,659 | ||||||
|
Asset retirement obligations
|
55,184 | 61,984 | ||||||
|
Deferred gain on sale
|
126,932 | 29,619 | ||||||
|
Other long-term liabilities
|
26,973 | 25,776 | ||||||
|
Total liabilities
|
3,230,763 | 3,016,478 | ||||||
|
Commitments and contingencies
|
||||||||
|
Equity:
|
||||||||
|
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, 172,391 issued and outstanding as of June 30, 2012 and December 31, 2011, aggregate liquidation preference of $17,239,100 at June 30, 2012
|
- | - | ||||||
|
Common stock, $0.001 par value, 300,000,000 shares authorized; 118,584,788 issued and 117,631,451 outstanding as of June 30, 2012, 118,105,279 issued and 117,380,884 outstanding as of December 31, 2011
|
119 | 118 | ||||||
|
Additional paid-in capital
|
1,557,345 | 1,554,223 | ||||||
|
Accumulated other comprehensive income (loss)
|
(951 | ) | 240 | |||||
|
Retained earnings
|
1,715,089 | 1,466,276 | ||||||
|
Total Whiting shareholders’ equity
|
3,271,602 | 3,020,857 | ||||||
|
Noncontrolling interest
|
8,219 | 8,274 | ||||||
|
Total equity
|
3,279,821 | 3,029,131 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 6,510,584 | $ | 6,045,609 | ||||
18
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
REVENUES AND OTHER INCOME:
|
||||||||||||||||
|
Oil and natural gas sales
|
$ | 492,756 | $ | 473,865 | $ | 1,051,453 | $ | 899,548 | ||||||||
|
Gain on hedging activities
|
759 | 2,391 | 1,886 | 5,454 | ||||||||||||
|
Amortization of deferred gain on sale
|
8,892 | 3,570 | 12,645 | 6,937 | ||||||||||||
|
Gain (loss) on sale of properties
|
(362 | ) | 1,227 | (362 | ) | 1,227 | ||||||||||
|
Interest income and other
|
129 | 153 | 258 | 261 | ||||||||||||
|
Total revenues and other income
|
502,174 | 481,206 | 1,065,880 | 913,427 | ||||||||||||
|
COSTS AND EXPENSES:
|
||||||||||||||||
|
Lease operating
|
89,504 | 73,785 | 184,294 | 145,307 | ||||||||||||
|
Production taxes
|
40,763 | 34,258 | 85,374 | 65,902 | ||||||||||||
|
Depreciation, depletion and amortization
|
160,589 | 110,250 | 316,709 | 217,978 | ||||||||||||
|
Exploration and impairment
|
27,902 | 20,171 | 55,480 | 42,408 | ||||||||||||
|
General and administrative
|
25,209 | 20,913 | 59,577 | 39,326 | ||||||||||||
|
Interest expense
|
17,905 | 15,279 | 36,361 | 29,737 | ||||||||||||
|
Change in Production Participation Plan liability
|
(953 | ) | 2,650 | (18 | ) | 2,207 | ||||||||||
|
Commodity derivative (gain) loss, net
|
(100,025 | ) | (113,618 | ) | (70,622 | ) | 20,820 | |||||||||
|
Total costs and expenses
|
260,894 | 163,688 | 667,155 | 563,685 | ||||||||||||
|
INCOME BEFORE INCOME TAXES
|
241,280 | 317,518 | 398,725 | 349,742 | ||||||||||||
|
INCOME TAX EXPENSE:
|
||||||||||||||||
|
Current
|
1,109 | 1,565 | 2,535 | 3,615 | ||||||||||||
|
Deferred
|
89,320 | 112,804 | 146,893 | 123,564 | ||||||||||||
|
Total income tax expense
|
90,429 | 114,369 | 149,428 | 127,179 | ||||||||||||
|
NET INCOME
|
150,851 | 203,149 | 249,297 | 222,563 | ||||||||||||
|
Net loss attributable to noncontrolling interest
|
31 | - | 55 | - | ||||||||||||
|
NET INCOME AVAILABLE TO SHAREHOLDERS
|
150,882 | 203,149 | 249,352 | 222,563 | ||||||||||||
|
Preferred stock dividends
|
(270 | ) | (269 | ) | (539 | ) | (539 | ) | ||||||||
|
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
|
$ | 150,612 | $ | 202,880 | $ | 248,813 | $ | 222,024 | ||||||||
|
EARNINGS PER COMMON SHARE:
|
||||||||||||||||
|
Basic
|
$ | 1.28 | $ | 1.73 | $ | 2.12 | $ | 1.89 | ||||||||
|
Diluted
|
$ | 1.27 | $ | 1.71 | $ | 2.10 | $ | 1.87 | ||||||||
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
||||||||||||||||
|
Basic
|
117,622 | 117,373 | 117,569 | 117,308 | ||||||||||||
|
Diluted
|
118,853 | 118,659 | 118,889 | 118,707 | ||||||||||||
19
WHITING PETROLEUM CORPORATION
Reconciliation of Net Income Available to Common Shareholders to
Adjusted Net Income Available to Common Shareholders
(In thousands, except for per share data)
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
|
June 30,
|
June 30,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
Net Income Available to Common Shareholders
|
$ | 150,612 | $ | 202,880 | $ | 248,813 | $ | 222,024 | ||||||||
|
Adjustments Net of Tax:
|
||||||||||||||||
|
Amortization of Deferred Gain on Sale
|
(5,560 | ) | (2,284 | ) | (7,906 | ) | (4,414 | ) | ||||||||
|
(Gain) Loss on Sale of Properties
|
227 | (785 | ) | 227 | (781 | ) | ||||||||||
|
Impairment Expense
|
8,998 | 4,993 | 20,149 | 9,827 | ||||||||||||
|
One-time Charge Under Production Participation Plan Related to Trust II Offering
|
- | - | 5,928 | - | ||||||||||||
|
Unrealized Derivative Gains
|
(67,470 | ) | (84,527 | ) | (58,378 | ) | (5,453 | ) | ||||||||
|
Adjusted Net Income (1)
|
$ | 86,807 | $ | 120,277 | $ | 208,833 | $ | 221,203 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Basic
|
$ | 0.74 | $ | 1.02 | $ | 1.78 | $ | 1.89 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Diluted
|
$ | 0.73 | $ | 1.02 | $ | 1.76 | $ | 1.87 | ||||||||
|
(1)
|
Adjusted Net Income Available to Common Shareholders is a non-GAAP financial measure. Management believes it provides useful information to investors for analysis of Whiting’s fundamental business on a recurring basis. In addition, management believes that Adjusted Net Income Available to Common Shareholders is widely used by professional research analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted Net Income Available for Common Shareholders should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under US GAAP and may not be comparable to other similarly titled measures of other companies.
|
20
WHITING PETROLEUM CORPORATION
Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow
(In thousands)
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
|
June 30,
|
June 30,
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
Net cash provided by operating activities
|
$ | 282,193 | $ | 374,163 | $ | 635,185 | $ | 588,218 | ||||||||
|
Exploration
|
13,510 | 12,367 | 23,254 | 26,966 | ||||||||||||
|
Exploratory dry hole costs
|
(4 | ) | (1,395 | ) | (255 | ) | (4,297 | ) | ||||||||
|
Changes in working capital
|
15,095 | (71,586 | ) | 4,785 | (12,988 | ) | ||||||||||
|
Preferred stock dividends paid
|
(270 | ) | (269 | ) | (539 | ) | (539 | ) | ||||||||
|
Discretionary cash flow (1)
|
$ | 310,524 | $ | 313,280 | $ | 662,430 | $ | 597,360 | ||||||||
|
(1)
|
Discretionary cash flow is computed as net income plus exploration and impairment costs, depreciation, depletion and amortization, deferred income taxes, non-cash interest costs, non-cash compensation plan charges, non-cash losses on mark-to-market derivatives and other non-current items less the gain on sale of properties, amortization of deferred gain on sale, non-cash gains on mark-to-market derivatives, and preferred stock dividends paid. The non-GAAP measure of discretionary cash flow is presented because management believes it provides useful information to investors for analysis of the Company’s ability to internally fund acquisitions, exploration and development. Discretionary cash flow should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under GAAP and may not be comparable to other similarly titled measures of other companies.
|
21