Attached files
| file | filename |
|---|---|
| 8-K - WHITING PETROLEUM FORM 8-K, DATED JULY 24, 2013 - WHITING PETROLEUM CORP | form8-k.htm |
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Company contact:
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John B. Kelso, Director of Investor Relations
|
|
303.837.1661 or john.kelso@whiting.com
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Whiting Petroleum Corporation Announces
Second Quarter 2013 Financial and Operating Results
Record Q2 2013 Production of 93,380 BOE/d Up 4.8% over Q1 2013
Q2 2013 Net Income Available to Common Shareholders of $134.7 Million
or $1.14 per Diluted Share and Adjusted Net Income of $121.3 Million or
$1.02 per Diluted Share
Q2 2013 Discretionary Cash Flow Totals a Record $440.9 Million
Niobrara Well in DJ Basin Completed Flowing 1,069 BOE/d
DENVER – July 24, 2013 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the second quarter of 2013 totaled 8.5 million barrels of oil equivalent (MMBOE), 87% crude oil/natural gas liquids (NGLs). Second quarter 2013 production equals 93,380 barrels of oil equivalent per day (BOE/d) representing a 4.8% increase over the first quarter of 2013. Second quarter production was up 15.7% over the second quarter 2012 average of 80,700 BOE/d and up 18.3% excluding the production associated with the Postle field assets which were sold on July 15, 2013.
Success in several areas contributed to production for the second quarter exceeding the high end of guidance issued in our April 24, 2013 first quarter results press release. In the Williston Basin, at our Western Williston area, production grew 231% year-over-year. We modified our completion design at our Missouri Breaks prospect and have been pleased with recent wells we placed on production. At our Redtail prospect in the DJ Basin, we implemented a new completion design and have been experiencing very strong and consistent results. We also continued to see increased production at our North Ward Estes EOR project where several phases of the CO2 flood are continuing to respond.
Despite the sale of our Postle assets, which accounted for approximately 7,560 BOE per day of production in the second quarter, our new 2013 guidance of 33.8 MMBOE (92,700 BOE/d) remains within the range of our prior guidance issued in our April 24, 2013 results press release. We are increasing our capital budget to $2.5 billion from $2.2 billion.
James J. Volker, Whiting’s Chairman and CEO, commented, “With the sale of our Postle assets, we have the liquidity to accelerate development of our high rate of return Williston Basin Bakken and DJ Basin Niobrara assets. Our revised 2013 production growth guidance equates to a 12% increase over 2012 levels and a 19% increase excluding the production associated with the Postle assets. In the third quarter we anticipate replacing nearly all of the production from the Postle assets sale, which generated $837 million in net sale proceeds, while increasing our capital budget by only $300 million. We believe this demonstrates the potential of our new, streamlined portfolio and the validity of our asset rationalization strategy.”
Mr. Volker added, “With the Postle sale proceeds, we expect to capitalize on the potential of our DJ Basin Redtail Niobrara area. Our most recent wells have benefited from longer laterals and larger sand volumes. We believe our completion practices translate into higher EURs and greater returns on capital. We are moving into development mode in this area with the recent arrival of a second pad capable rig and a third rig contracted to arrive in October of this year. This approximate 88,000 net acre lease position with a large amount of estimated original oil in place (59 MMBOE in the Niobrara “B” and “A” per 960-acre spacing unit) affords us the opportunity to enhance recovery by drilling on tighter spacing. Consequently, Redtail has the potential for a 33% increase to our current estimate of 2,400 gross drilling locations.”
2
Operating and Financial Results
The following tables summarize the second quarter and first six months operating and financial results for 2013 and 2012:
| Three Months Ended June 30, | |||||||||||
|
2013
|
2012
|
Change
|
|||||||||
|
Production (MBOE/d) (1)
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93.38 | 80.70 | +16% | ||||||||
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Discretionary Cash Flow-MM (2)
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$ | 440.9 | $ | 310.5 | +42% | ||||||
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Realized Price ($/BOE)
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$ | 75.88 | $ | 66.13 | +15% | ||||||
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Total Revenues-MM
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$ | 663.6 | $ | 502.2 | +32% | ||||||
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Net Income Available to Common Shareholders-MM (3)
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$ | 134.7 | $ | 150.6 | (11%) | ||||||
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Per Basic Share
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$ | 1.14 | $ | 1.28 | (11%) | ||||||
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Per Diluted Share
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$ | 1.14 | $ | 1.27 | (10%) | ||||||
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Adjusted Net Income Available to Common Shareholders-MM (4)
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$ | 121.3 | $ | 86.2 | +41% | ||||||
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Per Basic Share
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$ | 1.03 | $ | 0.73 | +41% | ||||||
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Per Diluted Share
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$ | 1.02 | $ | 0.73 | +40% | ||||||
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(1)
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The production attributable to the Postle field, which was sold on July 15, 2013, was 7.56 MBOE/d for the three months ended June 30, 2013 and 8.15 MBOE/d for the three months ended June 30, 2012.
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(2)
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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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(3)
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For the three months ended June 30, 2013, net income available to common shareholders included $36.8 million of pre-tax, non-cash hedging gains or $0.20 per basic share and $0.19 per diluted share after tax. For the three months ended June 30, 2012, net income available to common shareholders included $107.9 million of pre-tax, non-cash hedging gains or $0.57 per basic and diluted share after tax.
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(4)
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A reconciliation of adjusted net income available to common shareholders to net income available to common shareholders is included later in this news release.
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| Six Months Ended June 30, | |||||||||||
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2013
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2012
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Change
|
|||||||||
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Production (MBOE/d) (1)
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91.27 | 80.72 | +13% | ||||||||
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Discretionary Cash Flow-MM (2)
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$ | 841.9 | $ | 662.4 | +27% | ||||||
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Realized Price ($/BOE)
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$ | 75.34 | $ | 70.15 | + 7% | ||||||
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Total Revenues-MM
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$ | 1,276.9 | $ | 1,065.9 | +20% | ||||||
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Net Income Available to Common Shareholders-MM (3)
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$ | 220.7 | $ | 248.8 | (11%) | ||||||
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Per Basic Share
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$ | 1.87 | $ | 2.12 | (12%) | ||||||
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Per Diluted Share
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$ | 1.86 | $ | 2.10 | (11%) | ||||||
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Adjusted Net Income Available to Common Shareholders-MM (4)
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$ | 233.0 | $ | 208.8 | +12% | ||||||
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Per Basic Share
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$ | 1.98 | $ | 1.78 | +11% | ||||||
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Per Diluted Share
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$ | 1.96 | $ | 1.76 | +11% | ||||||
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(1)
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The production attributable to the Postle field, which was sold on July 15, 2013, was 7.62 MBOE/d for the six months ended June 30, 2013 and 8.23 MBOE/d for the six months ended June 30, 2012.
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(2)
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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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(3)
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For the six months ended June 30, 2013, net income available to common shareholders included $10.6 million of pre-tax, non-cash hedging gains or $0.06 per basic and diluted share after tax. For the six months ended June 30, 2012, net income available to common shareholders included $93.4 million of pre-tax, non-cash hedging gains or $0.50 per basic share and $0.49 per diluted share after tax.
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(4)
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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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3
2013 Capital Budget
We have increased our 2013 capital budget to $2.5 billion from $2.2 billion. Our revised 2013 capital budget is currently allocated among our major development areas as indicated in the table below:
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2013 CAPEX (MM)
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Gross Wells
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Net Wells
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% of Total
|
||||||||||
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Northern Rockies
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$ | 1,303 | 247 | 167 | 52% | ||||||||
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EOR
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213 |
NA(1)
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NA(1)
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8% | |||||||||
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Permian
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75 | 7 | 7 | 3% | |||||||||
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Central Rockies
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166 | 43 | 32 | 7% | |||||||||
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Gulf Coast
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25 | 3 | 3 | 1% | |||||||||
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Non-Operated
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200 | 8% | |||||||||||
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Land
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138 | 6% | |||||||||||
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Exploration Expense (2)
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85 | 3% | |||||||||||
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Facilities (3)
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145 | 6% | |||||||||||
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Well Work, Misc. Costs, Other
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150 | 6% | |||||||||||
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Total Budget
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$ | 2,500 | 300 | 209 | 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 and 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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Includes capital reduction from Postle sale.
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The following table provides a breakdown of our $300 million budget increase:
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Breakdown of 2013 CAPEX Increase
(MM)
|
|||
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New Drilling in Northern Rockies
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$ | 161 | |
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New Drilling in Permian Basin
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75 | ||
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Non-Operated Drilling
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36 | ||
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New Drilling at Redtail (1)
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30 | ||
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Land
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30 | ||
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New Drilling in Gulf Coast
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25 | ||
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Exploration Expense
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3 | ||
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Downward Adjustments (2)
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(60 | ) | |
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Total Increase
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$ | 300 | |
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(1)
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A third rig is scheduled to arrive at Redtail in the fourth quarter. Therefore, a larger capex impact is anticipated in 2014.
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(2)
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Consists of $33 million downward adjustment for facilities and $27 million downward adjustment for EOR projects due to the sale of the Postle field assets.
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4
Operations Update
Core Development Areas
Bakken and Three Forks Development
In the Williston Basin, we control 1,096,506 gross (697,259 net) acres that target the Middle Bakken, Three Forks and Pronghorn Sand formations. Our average acreage cost in this area is $549 per net acre.
Western Williston Basin
The Western Williston Basin includes our Hidden Bench, Tarpon, Missouri Breaks and Cassandra prospects. These areas represent a total of 171,408 gross (106,952 net) acres. Production from the Western Williston Basin averaged 9,385 BOE/d in the second quarter of 2013, which represented a 44% increase over the 6,520 BOE/d average rate in the first quarter of 2013.
Missouri Breaks Prospect. We hold 84,213 gross (57,526 net) acres in the Missouri Breaks prospect, located in Richland County, Montana and McKenzie County, North Dakota. We have implemented a new completion design in our Missouri Breaks area that utilizes cemented liners and higher sand volumes. The new frac design appears to significantly improve production rates. We recently completed the Weber 24-30-1H flowing at a rate of 1,164 BOE/d using our new completion design. This well offset the Mullin 21-24-1H, which tested at a rate of 481 BOE/d and was completed using our prior frac design, an uncemented liner with sliding sleeve technology.
Southern Williston Basin
The Southern Williston Basin encompasses our Pronghorn and Lewis & Clark prospects, which encompass a total of 395,441 gross (262,630 net) acres. Production from the Southern Williston averaged 13,325 BOE/d, relatively flat with first quarter 2013 production and up 30% year-over-year. We have been shifting to pad drilling in the Pronghorn area in the first half of 2013 and have generated a backlog of uncompleted wells. As of quarter end, we had 13 wells being completed or waiting on completion at our Pronghorn prospect.
Sanish Field Area
Whiting’s net production from the Sanish field area averaged 36,315 BOE per day in the second quarter of 2013 compared to 35,805 BOE/d in the first quarter 2013. The increase was in part attributable to a higher density drilling program at the Parshall field. We have initiated our higher density pilot project in the Sanish field. If successful, this could add 191 gross well locations.
5
Denver Basin: Redtail Niobrara Area
We hold a total of approximately 121,000 gross (88,000 net) acres in our Redtail area, located in the Denver Julesberg Basin in Weld County, Colorado. Our Redtail acreage produces from the Niobrara “B” zone and is also prospective in the Niobrara “A” and “C” zones as well as the Codell formation.
Highlighting recent drilling results at Redtail was the completion of the Razor 33-2813H, which flowed 966 barrels of oil and 620 Mcf of gas (1,069 BOE) per day from the Niobrara “B” zone on July 9, 2013. The well’s 6,047-foot lateral was fracture stimulated in a total of 32 stages using our new frac design. Whiting holds a 73.4% working interest and a 58.7% net revenue interest in the Razor well, which was drilled on a 960-acre spacing unit. We have also applied this new frac design to our 640-acre spacing unit wells with positive results. The Razor 25-2514H flowed 593 barrels of oil and 255 Mcf of gas (636 BOE) per day from the Niobrara “B” zone on June 30, 2013. The well’s 3,716-foot lateral was fracture stimulated in a total of 18 stages. Whiting holds an 87.5% working interest and a 74.8% net revenue interest in the well. Production results from our most recent six wells using this new completion design are consistent with a 400+ MBOE type curve.
We currently have two drilling rigs running at Redtail. We plan to add a third rig in October 2013. Our development plan for the Redtail prospect is to drill eight wells per spacing unit to the Niobrara “B” zone and four wells in each spacing unit to the Niobrara “A” zone. We estimate that we have more than 2,400 gross locations and 1,200 net locations at our Redtail prospect on this development pattern. We plan to test tighter spacing in the Niobrara “A” / “B” reservoir system, with the potential to drill up to 16 wells per spacing unit versus our current 12-well plan.
Enhanced Oil Recovery
North Ward Estes Field. Net production from our North Ward Estes field averaged 9,275 BOE/d, a 9% increase over the 8,545 BOE/d in the first quarter of 2013. Whiting is injecting approximately 350 MMcf of CO2 per day into the field, of which about 63% is recycled gas.
Operated Drilling Rig Count
As of July 15, 2013, 25 operated drilling rigs were active on our properties. The breakdown of our operated rigs as of July 15, 2013 was as follows:
|
Region
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Drilling Rigs | |
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Northern Rockies
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20
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|
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Permian Basin
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1
|
|
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Central Rockies
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2
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|
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Gulf Coast
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1
|
|
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EOR Project:
|
||
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North Ward Estes
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1
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Total
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25
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6
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended June 30, 2013 and 2012:
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Three Months Ended
|
|||||||||||
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June 30,
|
|||||||||||
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Production
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2013
|
2012
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Change
|
||||||||
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Oil (MMBbl)
|
6.70 | 5.58 | 20% | ||||||||
|
NGLs (MMBbl)
|
0.69 | 0.70 | (1%) | ||||||||
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Natural gas (Bcf)
|
6.62 | 6.38 | 4% | ||||||||
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Total equivalent (MMBOE)
|
8.50 | 7.34 | 16% | ||||||||
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Average Sales Price
|
|||||||||||
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Oil (per Bbl):
|
|||||||||||
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Price received
|
$ | 89.15 | $ | 79.92 | 12% | ||||||
|
Effect of crude oil hedging
|
(1.05 | )(1) | (1.35 | ) | |||||||
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Realized price
|
$ | 88.10 | $ | 78.57 | 12% | ||||||
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NYMEX oil (per Bbl)
|
$ | 94.23 | $ | 93.51 | 1% | ||||||
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NGLs (per Bbl):
|
|||||||||||
|
Realized price
|
$ | 37.80 | $ | 37.45 | 1% | ||||||
|
Natural gas (per Mcf):
|
|||||||||||
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Price received
|
$ | 4.27 | $ | 3.25 | 31% | ||||||
|
Effect of natural gas hedging
|
- | 0.06 | |||||||||
|
Realized price
|
$ | 4.27 | $ | 3.31 | 29% | ||||||
|
NYMEX natural gas (per Mcf)
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$ | 4.10 | $ | 2.21 | 86% | ||||||
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(1)
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Whiting realized pre-tax cash settlement losses of $7.0 million on its crude oil hedges during the second quarter of 2013. A summary of Whiting’s outstanding hedges is included later in this news release.
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7
Second Quarter and First Half 2013 Costs and Margins
A summary of production, cash revenues and cash costs on a per BOE basis is as follows:
|
Per BOE, Except Production
|
||||||||||||||||
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Three Months Ended
|
Six Months Ended
|
|||||||||||||||
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June 30,
|
June 30,
|
|||||||||||||||
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2013
|
2012
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2013
|
2012
|
|||||||||||||
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Production (MMBOE)
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8.50 | 7.34 | 16.52 | 14.69 | ||||||||||||
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Sales price, net of hedging
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$ | 75.88 | $ | 66.13 | $ | 75.34 | $ | 70.15 | ||||||||
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Lease operating expense
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12.37 | 12.19 | 12.41 | 12.54 | ||||||||||||
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Production tax
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6.33 | 5.55 | 6.36 | 5.81 | ||||||||||||
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General & administrative
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3.44 | 3.43 | 3.52 | 4.06 | ||||||||||||
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Exploration
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2.86 | 1.84 | 2.62 | 1.58 | ||||||||||||
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Cash interest expense
|
2.42 | 2.12 | 2.40 | 2.16 | ||||||||||||
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Cash income tax expense (benefit)
|
(0.30 | ) | 0.15 | (0.13 | ) | 0.17 | ||||||||||
| $ | 48.76 | $ | 40.85 | $ | 48.16 | $ | 43.83 | |||||||||
Second Quarter and First Half 2013 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, 2013:
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Gross/Net Wells Completed
|
||||||||||||
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Total New
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% Success
|
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)
|
||||||||
| Q2 13 | 112 / 61.0 | 2 / 1.9 | 114 / 62.9 | 98% / 97% | $ | 663.2 | (1) | |||||
| 6M 13 | 194 / 99.0 | 3 / 2.9 | 197 / 101.9 | 98% / 97% | $ | 1,232.5 | ||||||
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(1)
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Includes $77 million for land and $43 million for facilities.
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Outlook for Third Quarter and Full-Year 2013
The following table provides guidance for the third quarter and full-year 2013 based on current forecasts, including Whiting’s full-year 2013 capital budget of $2,500.0 million:
| Guidance | ||||||||||||||||||||
| Third Quarter | Full-Year | |||||||||||||||||||
| 2013 | 2013 | |||||||||||||||||||
|
Production (MMBOE)
|
8.30 | - | 8.70 | 33.50 | - | 34.10 | ||||||||||||||
|
Lease operating expense per BOE
|
$ | 12.00 | - | $ | 12.50 | $ | 12.15 | - | $ | 12.45 | ||||||||||
|
General and admin. expense per BOE(1)
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$ | 6.25 | - | $ | 6.65 | $ | 4.10 | - | $ | 4.50 | ||||||||||
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Interest expense per BOE
|
$ | 2.40 | - | $ | 2.60 | $ | 2.50 | - | $ | 2.70 | ||||||||||
|
Depr., depletion and amort. per BOE
|
$ | 26.25 | - | $ | 27.25 | $ | 26.00 | - | $ | 27.00 | ||||||||||
|
Prod. taxes (% of production revenue)
|
8.6% | - | 8.8% | 8.5% | - | 8.7% | ||||||||||||||
|
Oil price differentials to NYMEX per Bbl(2)
|
( | $ | 6.50 | ) | - | ( | $ | 7.50 | ) | ( | $ | 6.00 | ) | - | ( | $ | 6.50 | ) | ||
|
Gas price premium to NYMEX per Mcf(3)
|
$ | 0.10 | - | $ | 0.40 | $ | 0.10 | - | $ | 0.40 | ||||||||||
|
(1)
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Includes a $21.7 million charge under the Whiting Production Participation Plan related to the Postle sale.
|
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(2)
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Does not include the effect of NGLs.
|
|
(3)
|
Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release.
|
8
Hedges and Fixed Price Natural Gas Contracts
The following summarizes Whiting’s crude oil hedges as of July 15, 2013:
|
Weighted Average
|
As a Percentage of
|
|||||||
|
Derivative
|
Hedge
|
Contracted Volume
|
NYMEX Price
|
June 2013
|
||||
|
Instrument
|
Period
|
(Bbls per Month)
|
(per Bbl)
|
Oil Production
|
||||
|
Three-way Collars(1)
|
2013
|
|||||||
|
Q3
|
1,040,000
|
$ 71.25 - $ 85.63 - $ 113.95
|
45.8%
|
|||||
|
Q4
|
1,040,000
|
$ 71.25 - $ 85.63 - $ 113.95
|
45.8%
|
|||||
|
2014
|
||||||||
|
Q1
|
800,000
|
$ 71.50 - $ 85.00 - $ 101.91
|
35.2%
|
|||||
|
Q2
|
800,000
|
$ 71.50 - $ 85.00 - $ 101.91
|
35.2%
|
|||||
|
Q3
|
800,000
|
$ 71.50 - $ 85.00 - $ 101.91
|
35.2%
|
|||||
|
Q4
|
800,000
|
$ 71.50 - $ 85.00 - $ 101.91
|
35.2%
|
|||||
|
Collars
|
2013
|
|||||||
|
Q3
|
294,450
|
$ 48.16 - $ 90.70
|
13.0%
|
|||||
|
Oct
|
294,340
|
$ 48.15 - $ 90.69
|
13.0%
|
|||||
|
Nov
|
194,340
|
$ 47.96 - $ 85.90
|
8.6%
|
|||||
|
Dec
|
4,340
|
$ 80.00 - $ 122.50
|
0.2%
|
|||||
|
2014
|
||||||||
|
Q1
|
4,250
|
$ 80.00 - $ 122.50
|
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)
|
A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.
|
Whiting also has the following fixed-price natural gas contracts in place as of July 15, 2013:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
Contracted Price
|
June 2013
|
|||
|
Period
|
(MMBtu per Month)
|
(per MMBtu)
|
Gas Production
|
|||
|
2013
|
||||||
|
Q3
|
368,000
|
$5.47
|
16.7%
|
|||
|
Q4
|
368,000
|
$5.47
|
16.7%
|
|||
|
2014
|
||||||
|
Q1
|
330,000
|
$5.49
|
14.9%
|
|||
|
Q2
|
333,667
|
$5.49
|
15.1%
|
|||
|
Q3
|
337,333
|
$5.49
|
15.3%
|
|||
|
Q4
|
337,333
|
$5.49
|
15.3%
|
9
Selected Operating and Financial Statistics
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
Selected operating statistics
|
||||||||||||||||
|
Production
|
||||||||||||||||
|
Oil, MBbl
|
6,701 | 5,577 | 12,951 | 11,159 | ||||||||||||
|
NGLs, MBbl
|
694 | 703 | 1,404 | 1,367 | ||||||||||||
|
Natural gas, MMcf
|
6,617 | 6,383 | 12,988 | 12,987 | ||||||||||||
|
Oil equivalents, MBOE
|
8,498 | 7,344 | 16,520 | 14,691 | ||||||||||||
|
Average Prices
|
||||||||||||||||
|
Oil per Bbl (excludes hedging)
|
$ | 89.15 | $ | 79.92 | $ | 88.65 | $ | 85.22 | ||||||||
|
NGLs per Bbl
|
$ | 37.80 | $ | 37.45 | $ | 40.20 | $ | 41.73 | ||||||||
|
Natural gas per Mcf (excludes hedging)
|
$ | 4.27 | $ | 3.25 | $ | 4.04 | $ | 3.35 | ||||||||
|
Per BOE Data
|
||||||||||||||||
|
Sales price (including hedging)
|
$ | 75.88 | $ | 66.13 | $ | 75.34 | $ | 70.15 | ||||||||
|
Lease operating
|
$ | 12.37 | $ | 12.19 | $ | 12.41 | $ | 12.54 | ||||||||
|
Production taxes
|
$ | 6.33 | $ | 5.55 | $ | 6.36 | $ | 5.81 | ||||||||
|
Depreciation, depletion and amortization
|
$ | 26.29 | $ | 21.87 | $ | 25.70 | $ | 21.56 | ||||||||
|
General and administrative
|
$ | 3.44 | $ | 3.43 | $ | 3.52 | $ | 4.06 | (1) | |||||||
|
Selected Financial Data
|
||||||||||||||||
|
(In thousands, except per share data)
|
||||||||||||||||
|
Total revenues and other income
|
$ | 663,569 | $ | 502,174 | $ | 1,276,940 | $ | 1,065,880 | ||||||||
|
Total costs and expenses
|
$ | 455,598 | $ | 260,894 | $ | 931,205 | $ | 667,155 | ||||||||
|
Net income available to common shareholders
|
$ | 134,687 | $ | 150,612 | $ | 220,681 | $ | 248,813 | ||||||||
|
Earnings per common share, basic
|
$ | 1.14 | $ | 1.28 | $ | 1.87 | $ | 2.12 | ||||||||
|
Earnings per common share, diluted
|
$ | 1.14 | $ | 1.27 | $ | 1.86 | $ | 2.10 | ||||||||
|
Average shares outstanding, basic
|
117,930 | 117,622 | 117,859 | 117,569 | ||||||||||||
|
Average shares outstanding, diluted
|
118,901 | 118,853 | 118,929 | 118,889 | ||||||||||||
|
Net cash provided by operating activities
|
$ | 442,617 | $ | 282,193 | $ | 740,231 | $ | 635,185 | ||||||||
|
Net cash used in investing activities
|
$ | (574,590 | ) | $ | (464,883 | ) | $ | (1,203,081 | ) | $ | (677,935 | ) | ||||
|
Net cash provided by financing activities
|
$ | 147,103 | $ | 179,672 | $ | 441,362 | $ | 33,746 | ||||||||
|
(1)
|
For the six months ended June 30, 2012, the cost includes the effect of a charge under our Production Participation Plan related to the Whiting USA Trust II divestiture of $0.59 per BOE.
|
10
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, 2013, to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
|
June 30,
2013
|
December 31,
2012
|
|||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 23,312 | $ | 44,800 | ||||
|
Accounts receivable trade, net
|
345,792 | 318,265 | ||||||
|
Prepaid expenses and other
|
26,011 | 21,347 | ||||||
|
Assets held for sale (1)
|
701,701 | - | ||||||
|
Total current assets
|
1,096,816 | 384,412 | ||||||
|
Property and equipment:
|
||||||||
|
Oil and gas properties, successful efforts method:
|
||||||||
|
Proved properties
|
9,021,657 | 8,849,515 | ||||||
|
Unproved properties
|
381,653 | 362,483 | ||||||
|
Other property and equipment
|
169,549 | 141,738 | ||||||
|
Total property and equipment
|
9,572,859 | 9,353,736 | ||||||
|
Less accumulated depreciation, depletion and amortization
|
(2,691,827 | ) | (2,590,203 | ) | ||||
|
Total property and equipment, net
|
6,881,032 | 6,763,533 | ||||||
|
Debt issuance costs
|
27,276 | 28,748 | ||||||
|
Other long-term assets
|
112,586 | 95,726 | ||||||
|
TOTAL ASSETS
|
$ | 8,117,710 | $ | 7,272,419 | ||||
|
(1)
|
Represents primarily proved property costs related to the Postle property divestiture.
|
11
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share data)
|
June 30,
2013
|
December 31,
2012
|
|||||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Current portion of long-term debt
|
$ | 250,000 | $ | - | ||||
|
Accounts payable trade
|
105,899 | 131,370 | ||||||
|
Accrued capital expenditures
|
104,803 | 110,663 | ||||||
|
Accrued liabilities and other
|
149,064 | 180,622 | ||||||
|
Revenues and royalties payable
|
160,653 | 149,692 | ||||||
|
Deposit received on properties held for sale
|
85,980 | - | ||||||
|
Taxes payable
|
44,777 | 33,283 | ||||||
|
Derivative liabilities
|
9,262 | 21,955 | ||||||
|
Deferred income taxes
|
9,803 | 9,394 | ||||||
|
Liabilities related to assets held for sale
|
8,616 | - | ||||||
|
Total current liabilities
|
928,857 | 636,979 | ||||||
|
Long-term debt
|
2,000,000 | 1,800,000 | ||||||
|
Deferred income taxes
|
1,190,146 | 1,063,681 | ||||||
|
Derivative liabilities
|
857 | 1,678 | ||||||
|
Production Participation Plan liability
|
106,613 | 94,483 | ||||||
|
Asset retirement obligations
|
89,675 | 86,179 | ||||||
|
Deferred gain on sale
|
95,139 | 110,395 | ||||||
|
Other long-term liabilities
|
26,072 | 25,852 | ||||||
|
Total liabilities
|
4,437,359 | 3,819,247 | ||||||
|
Commitments and contingencies
|
||||||||
|
Equity:
|
||||||||
|
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, no shares authorized, issued or outstanding as of June 30, 2013 and 172,391 shares issued and outstanding as of December 31, 2012
|
- | - | ||||||
|
Common stock, $0.001 par value, 300,000,000 shares authorized; 120,134,157 issued and 118,654,184 outstanding as of June 30, 2013, 118,582,477 issued and 117,631,451 outstanding as of December 31, 2012
|
120 | 119 | ||||||
|
Additional paid-in capital
|
1,572,835 | 1,566,717 | ||||||
|
Accumulated other comprehensive loss
|
(826 | ) | (1,236 | ) | ||||
|
Retained earnings
|
2,100,069 | 1,879,388 | ||||||
|
Total Whiting shareholders’ equity
|
3,672,198 | 3,444,988 | ||||||
|
Noncontrolling interest
|
8,153 | 8,184 | ||||||
|
Total equity
|
3,680,351 | 3,453,172 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 8,117,710 | $ | 7,272,419 | ||||
12
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
REVENUES AND OTHER INCOME:
|
||||||||||||||||
|
Oil, NGL and natural gas sales
|
$ | 651,868 | $ | 492,756 | $ | 1,256,982 | $ | 1,051,453 | ||||||||
|
Gain (loss) on hedging activities
|
(437 | ) | 759 | (648 | ) | 1,886 | ||||||||||
|
Amortization of deferred gain on sale
|
7,954 | 8,892 | 15,930 | 12,645 | ||||||||||||
|
Gain (loss) on sale of properties
|
3,387 | (362 | ) | 3,432 | (362 | ) | ||||||||||
|
Interest income and other
|
797 | 129 | 1,244 | 258 | ||||||||||||
|
Total revenues and other income
|
663,569 | 502,174 | 1,276,940 | 1,065,880 | ||||||||||||
|
COSTS AND EXPENSES:
|
||||||||||||||||
|
Lease operating
|
105,080 | 89,504 | 204,958 | 184,294 | ||||||||||||
|
Production taxes
|
53,814 | 40,763 | 105,085 | 85,374 | ||||||||||||
|
Depreciation, depletion and amortization
|
223,446 | 160,589 | 424,605 | 316,709 | ||||||||||||
|
Exploration and impairment
|
43,393 | 27,902 | 80,673 | 55,480 | ||||||||||||
|
General and administrative
|
29,213 | 25,209 | 58,098 | 59,577 | ||||||||||||
|
Interest expense
|
23,121 | 17,905 | 44,591 | 36,361 | ||||||||||||
|
Change in Production Participation Plan liability
|
7,723 | (953 | ) | 12,130 | (18 | ) | ||||||||||
|
Commodity derivative (gain) loss, net
|
(30,192 | ) | (100,025 | ) | 1,065 | (70,622 | ) | |||||||||
|
Total costs and expenses
|
455,598 | 260,894 | 931,205 | 667,155 | ||||||||||||
|
INCOME BEFORE INCOME TAXES
|
207,971 | 241,280 | 345,735 | 398,725 | ||||||||||||
|
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||||||
|
Current
|
(2,511 | ) | 1,109 | (2,089 | ) | 2,535 | ||||||||||
|
Deferred
|
75,538 | 89,320 | 126,636 | 146,893 | ||||||||||||
|
Total income tax expense
|
73,027 | 90,429 | 124,547 | 149,428 | ||||||||||||
|
NET INCOME
|
134,944 | 150,851 | 221,188 | 249,297 | ||||||||||||
|
Net loss attributable to noncontrolling interest
|
12 | 31 | 31 | 55 | ||||||||||||
|
NET INCOME AVAILABLE TO SHAREHOLDERS
|
134,956 | 150,882 | 221,219 | 249,352 | ||||||||||||
|
Preferred stock dividends
|
(269 | ) | (270 | ) | (538 | ) | (539 | ) | ||||||||
|
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
|
$ | 134,687 | $ | 150,612 | $ | 220,681 | $ | 248,813 | ||||||||
|
EARNINGS PER COMMON SHARE:
|
||||||||||||||||
|
Basic
|
$ | 1.14 | $ | 1.28 | $ | 1.87 | $ | 2.12 | ||||||||
|
Diluted
|
$ | 1.14 | $ | 1.27 | $ | 1.86 | $ | 2.10 | ||||||||
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
||||||||||||||||
|
Basic
|
117,930 | 117,622 | 117,859 | 117,569 | ||||||||||||
|
Diluted
|
118,901 | 118,853 | 118,929 | 118,889 | ||||||||||||
13
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,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
Net Income Available to Common Shareholders
|
$ | 134,687 | $ | 150,612 | $ | 220,681 | $ | 248,813 | ||||||||
|
Adjustments Net of Tax:
|
||||||||||||||||
|
Amortization of Deferred Gain on Sale
|
(5,002 | ) | (5,560 | ) | (10,017 | ) | (7,906 | ) | ||||||||
|
(Gain) Loss on Sale of Properties
|
(2,130 | ) | 227 | (2,158 | ) | 227 | ||||||||||
|
Impairment Expense
|
11,979 | 8,998 | 23,557 | 20,149 | ||||||||||||
|
Charge Under Production Participation Plan Related to Trust II Offering
|
- | - | - | 5,928 | ||||||||||||
|
Change in Production Participation Plan Liability
|
4,856 | (596 | ) | 7,627 | (12 | ) | ||||||||||
|
Unrealized Derivative Gains
|
(23,126 | ) | (67,470 | ) | (6,674 | ) | (58,378 | ) | ||||||||
|
Adjusted Net Income (1)
|
$ | 121,264 | $ | 86,211 | $ | 233,016 | $ | 208,821 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Basic
|
$ | 1.03 | $ | 0.73 | $ | 1.98 | $ | 1.78 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Diluted
|
$ | 1.02 | $ | 0.73 | $ | 1.96 | $ | 1.76 | ||||||||
|
(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 U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
|
14
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,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
Net cash provided by operating activities
|
$ | 442,617 | $ | 282,193 | $ | 740,231 | $ | 635,185 | ||||||||
|
Exploration
|
24,343 | 13,510 | 43,209 | 23,254 | ||||||||||||
|
Exploratory dry hole costs
|
(11,628 | ) | (4 | ) | (11,628 | ) | (255 | ) | ||||||||
|
Changes in working capital
|
(14,191 | ) | 15,095 | 70,668 | 4,785 | |||||||||||
|
Preferred stock dividends paid
|
(269 | ) | (270 | ) | (538 | ) | (539 | ) | ||||||||
|
Discretionary cash flow (1)
|
$ | 440,872 | $ | 310,524 | $ | 841,942 | $ | 662,430 | ||||||||
|
(1)
|
Discretionary cash flow is a non-GAAP measure. 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 U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
|
15
Conference Call
The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, July 25, 2013 at 11:00 a.m. EDT (10:00 a.m. CDT, 9:00 a.m. MDT) to discuss Whiting’s second quarter 2013 financial and operating results. Please call (877) 415-3183 (U.S./Canada) or (857) 244-7326 (International) to be connected to the call and enter the pass code 32363164. Access to a live internet broadcast will be available at http://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 25, 2013.
A telephonic replay will be available beginning approximately two hours after the call on Thursday, July 25, 2013 and continuing through Thursday, August 1, 2013. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 35627250. You may also access a web archive at http://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 crude 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 field in Texas. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit http://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.
These risks and uncertainties include, but are not limited to: declines in oil, NGL 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; 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 and the risks related thereto; 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, 2012. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.
16