Attached files
| file | filename |
|---|---|
| 8-K - WHITING PETROLEUM FORM 8-K, DATED OCTOBER 23, 2013 - WHITING PETROLEUM CORP | form8-k.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
Third Quarter 2013 Financial and Operating Results
Q3 2013 Production Totals 8.53 MMBOE
Q3 2013 Net Income Available to Common Shareholders of $204.1 Million
or $1.71 per Diluted Share and Adjusted Net Income of $153.2 Million or
$1.28 per Diluted Share
Q3 2013 Discretionary Cash Flow Totals a Record $450.5 Million
Sells a Portion of Its Big Tex Assets for $150.1 Million
Two Higher Density Wells at Pronghorn Completed Flowing
1,482 BOE/D and 1,254 BOE/D
DENVER – October 23, 2013 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the third quarter of 2013 totaled 8.533 million barrels of oil equivalent (MMBOE), of which 87% was crude oil/natural gas liquids (NGLs). Despite the sale of our Postle field assets, which accounted for approximately 7,560 barrels of oil equivalent per day (BOE/d) of production in the second quarter, third quarter 2013 production came to 92,750 BOE/d compared to 93,380 BOE/d in the second quarter of 2013. Third quarter production was up 12% over the third quarter 2012 average of 82,615 BOE/d and up 23% excluding the production associated with the Postle field assets, which were sold on July 15, 2013.
Success in several areas contributed to strong third quarter production. We have applied the modified completion design that we employed at our Missouri Breaks prospect to other areas in the Williston Basin, including Hidden Bench, Lewis & Clark and Pronghorn, with encouraging results. At our Western Williston area, production increased 46% over the second quarter of 2013, driven by strong drill bit results. At our Redtail prospect in the DJ Basin, our new completion design continues to generate 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.
We recently entered into an agreement to sell 32,183 net acres and approximately 200 net BOE/d in our Big Tex prospect area in the Delaware Basin to a private buyer for total consideration of $150.1 million subject to closing and post-closing adjustments. Of the total net acres, 30,822 net acres are located in Pecos County, Texas and 1,361 net acres are located in Reeves County, Texas. The sale is subject to normal purchase price adjustments and is expected to close by October 31, 2013.
James J. Volker, Whiting’s Chairman and CEO, commented, “This is an exciting time for Whiting and our shareholders. During the third quarter, we added 17,282 net acres to our Hidden Bench and Missouri Breaks prospect areas and 32,419 net acres to our Redtail Niobrara prospect. Our new completion design using cemented liners and plug and perf technology is working throughout the Williston Basin. Initial results from our higher density drilling program at our Pronghorn prospect are very encouraging, and we expect results from our Sanish field and Hidden Bench prospect higher density drilling programs in the fourth quarter. We expect to add a third rig at our Redtail Niobrara prospect on November 4, 2013 and are in development mode with an estimated 3,394 future gross well locations.”
Mr. Volker added, “In the third quarter, we replaced nearly all of the production from the Postle assets sale, which generated $816.5 million in net sale proceeds. We recently issued $2.3 billion of senior notes, $1.1 billion of senior notes bearing an interest rate of 5.000% and maturing in 2019 and $1.2 billion of senior notes that bear an interest rate of 5.750% and mature in 2021. We used the net proceeds from the Postle assets sale and bond issuance to strengthen our financial position and put us in a position for sustained growth. The sale of a portion of our Big Tex assets for $150.1 million will further increase our liquidity to accelerate development of our high rate of return Williston Basin Bakken and DJ Basin Niobrara assets. In addition, the transaction will bring a new operator to the Big Tex area whose drilling we expect will help de-risk our remaining 41,173 net acres at Big Tex, which is composed of 30,846 net acres in Pecos County, Texas, 6,207 net acres in Reeves County, Texas and 4,120 net acres in Ward County, Texas.”
2
Operating and Financial Results
The following tables summarize the third quarter and first nine months operating and financial results for 2013 and 2012:
|
Three Months Ended
September 30,
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|||||||||
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2013
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2012
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Change
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|||||||
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Production (MBOE/d) (1)
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92.75 | 82.62 | +12% | ||||||
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Discretionary Cash Flow-MM (2)
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$ | 450.5 | $ | 343.4 | +31% | ||||
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Realized Price ($/BOE)
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$ | 81.21 | $ | 67.99 | +19% | ||||
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Total Revenues-MM
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$ | 831.0 | $ | 530.5 | +57% | ||||
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Net Income Available to Common Shareholders-MM (3)
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$ | 204.1 | $ | 82.9 | +146% | ||||
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Per Basic Share
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$ | 1.72 | $ | 0.70 | +146% | ||||
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Per Diluted Share
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$ | 1.71 | $ | 0.70 | +144% | ||||
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Adjusted Net Income Available to Common Shareholders-MM (4)
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$ | 153.2 | $ | 90.7 | +69% | ||||
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Per Basic Share
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$ | 1.29 | $ | 0.77 | +68% | ||||
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Per Diluted Share
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$ | 1.28 | $ | 0.77 | +66% | ||||
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(1)
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Production attributable to the Postle field, which was sold on July 15, 2013, was 113.1 MBOE for the three months ended September 30, 2013 (7.5 MBOE/d over 15 days) and 751.0 MBOE or 8.2 MBOE/d over 92 days for the three months ended September 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 September 30, 2013, net income available to common shareholders included $11.4 million of pre-tax, non-cash derivative losses or $0.06 per basic share and diluted share after tax. For the three months ended September 30, 2012, net income available to common shareholders included $1.6 million of pre-tax, non-cash hedging losses or $0.01 per basic and diluted share after tax.
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(4)
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A reconciliation of adjusted net income available to common shareholders to net income available to common shareholders is included later in this news release.
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Nine Months Ended
September 30,
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|||||||||
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2013
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2012
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Change
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|||||||
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Production (MBOE/d) (1)
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91.77 | 81.36 | +13% | ||||||
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Discretionary Cash Flow-MM (2)
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$ | 1,292.5 | $ | 1,005.8 | +29% | ||||
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Realized Price ($/BOE)
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$ | 77.34 | $ | 69.41 | +11% | ||||
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Total Revenues-MM
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$ | 2,107.9 | $ | 1,596.4 | +32% | ||||
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Net Income Available to Common Shareholders-MM (3)
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$ | 424.8 | $ | 331.7 | +28% | ||||
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Per Basic Share
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$ | 3.60 | $ | 2.82 | +28% | ||||
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Per Diluted Share
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$ | 3.56 | $ | 2.79 | +28% | ||||
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Adjusted Net Income Available to Common Shareholders-MM (4)
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$ | 386.2 | $ | 299.6 | +29% | ||||
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Per Basic Share
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$ | 3.27 | $ | 2.55 | +28% | ||||
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Per Diluted Share
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$ | 3.24 | $ | 2.53 | +28% | ||||
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(1)
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Production attributable to the Postle field, which was sold on July 15, 2013, was 1,492.3 MBOE for the nine months ended September 30, 2013 (7.6 MBOE/d over 196 days) and 2,248.6 MBOE or 8.2 MBOE/d over 274 days for the nine months ended September 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 nine months ended September 30, 2013, there was no significant impact to net income available to common shareholders related to non-cash derivative gains or losses. For the nine months ended September 30, 2012, net income available to common shareholders included $91.8 million of pre-tax, non-cash derivative gains or $0.49 per basic share and $0.48 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
Operations Update
Core Development Areas
Bakken and Three Forks Development
Western Williston Basin
The Western Williston Basin includes our Hidden Bench, Tarpon, Missouri Breaks and Cassandra prospects. During the third quarter, we acquired 39,310 gross (17,282 net) acres located in and around our acreage in the Missouri Breaks and Hidden Bench prospects. The properties include 13 operated 1,280-acre Bakken/Three Forks drilling spacing units with an average working interest of 58% and net revenue interest of 48%. 92% of the acreage is held by production. The acquisition brought our total acreage in the Western Williston Basin to 205,581 gross (120,309 net) acres. Production from the Western Williston Basin averaged 13,710 BOE/d in the third quarter of 2013, which represented a 46% increase over the 9,385 BOE/d average rate in the second quarter of 2013. The acquisition contributed approximately 25,000 BOE to our third quarter volumes after the September 20, 2013 closing date.
Missouri Breaks Prospect. We hold 99,584 gross (62,635 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. On August 24, 2013, we completed the Sundheim 21-27-1H flowing at an initial rate of 1,136 BOE/d using a cemented liner and our first slick water frac. Cumulative production from this well during its first 30 days of production totaled 16.7 MBOE, which was approximately 75% better than the offset well that was completed by another operator using different technology.
The last eight wells at Missouri Breaks that were completed using cemented liners and plug and perf technology had average first 30-day cumulative production of 14.4 MBOE, approximately 60% better than the previous 31 area wells completed using uncemented liners and sliding sleeves.
Hidden Bench Prospect. We hold 66,805 gross (37,459 net) acres in the Hidden Bench prospect, located in McKenzie County, North Dakota. We have also implemented a new completion design in our Hidden Bench area that utilizes cemented liners and higher sand volumes that has generated positive results. We recently completed the Eide 41-13-2H flowing at an initial rate of 3,795 BOE/d using a cemented liner and a plug and perf completion. An offset well, the Eide 41-13HR, was completed flowing 2,715 BOE/d. This well was completed using an uncemented liner and sliding sleeve technology. Both wells were completed on October 1, 2013.
4
Southern Williston Basin
The Southern Williston Basin spans our Pronghorn and Lewis & Clark prospects, which encompass a total of 395,490 gross (263,784 net) acres. Production from the Southern Williston averaged 14,160 BOE/d, up 6% over the 13,325 BOE/d rate in the second quarter of 2013 and up 16% year-over-year. We completed our first two higher density wells at Pronghorn with favorable results. The Privratsky 24-22PH HD was completed in the Pronghorn Sand on September 21, 2013 flowing 1,482 BOE/d. The Privratsky 14-22PH HD was completed in the Pronghorn Sand on September 18, 2013 flowing 1,254 BOE/d. Both wells were completed using cemented liners and plug and perf technology. We are testing the potential to drill six or seven wells per drilling spacing unit versus our prior plan for three wells per spacing unit.
Also at Pronghorn, we recently completed a three-well pad to test our new completion technique. The Obrigewitch 21-29PH was completed on September 12, 2013 using a cemented liner and plug and perf technology flowing 2,432 BOE/d from the Pronghorn Sand, approximately a 50% increase over two offsetting wells completed on the same pad using older technology.
At Lewis & Clark, we completed the Kjelstrup Federal 11-19-1PH on August 27, 2013 using a cemented liner and plug and perf technology flowing 1,348 BOE/d from the Pronghorn Sand, approximately 50% better than the offset well completed using an uncemented liner and sliding sleeve method.
Sanish Field Area
Whiting’s net production from the Sanish field area averaged 36,840 BOE/d in the third quarter of 2013. In this area, Whiting is participating in downspacing wells with the Parshall field operator. We have initiated our own higher density pilot project in the Sanish field and expect results in the fourth quarter of 2013. If successful, this could add 191 gross well locations.
Denver Basin: Redtail Niobrara Area
During the third quarter, we acquired 48,131 gross (32,419 net) acres at our Redtail Niobrara prospect, located in the Denver Julesberg Basin in Weld County, Colorado. The acquisition brought our total acreage at Redtail to 168,644 gross (119,978 net) acres. Our Redtail acreage currently produces from the Niobrara “B” zone and is also prospective in the Niobrara “A” and “C” zones as well as the Codell formation.
During the quarter, we completed two wells that bracket our Phase 1 acreage, which has 899 potential gross drilling locations, on the eastern and western sides. The Horsetail 18-0713H averaged 452 BOE/d over the first 30 days of production and the Wildhorse 04-0424H averaged 492 BOE/d over the first 60 days of production.
5
We expect to add a third rig to our Redtail drilling program on November 4, 2013. We currently plan to add a fourth rig in January 2014 and a fifth rig in June 2014. Our drilling has shifted to pad drilling. As of October 15, 2013, we had three wells flowing back and 10 wells waiting on completion. Our development plan for the Redtail prospect is to drill eight wells per spacing unit to the Niobrara “B” zone and eight wells in each spacing unit to the Niobrara “A” zone. We estimate that we have more than 3,300 gross locations and 1,650 net locations at our Redtail prospect on this development pattern.
Enhanced Oil Recovery - North Ward Estes Field
Net production from our North Ward Estes field averaged 9,610 BOE/d in the third quarter of 2013, a 4% increase over the 9,275 BOE/d in the second quarter of 2013. Whiting is injecting approximately 365 MMcf of CO2 per day into the field, of which about 67% is recycled gas.
Operated Drilling Rig Count
As of October 15, 2013, 23 operated drilling rigs were active on our properties. The breakdown of our operated rigs as of October 15, 2013 was as follows:
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Region
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Drilling Rigs | |
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Northern Rockies
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18 | |
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Permian Basin
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2 | |
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Central Rockies
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2 | |
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Other
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1 | |
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Total
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23 |
6
Other Financial and Operating Results
The following table summarizes the Company’s net production and commodity price realizations for the quarters ended September 30, 2013 and 2012:
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Three Months Ended
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September 30,
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Production
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2013
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2012
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Change
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||||||||
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Oil (MMBbl)
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6.74 | 5.86 | 15% | ||||||||
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NGLs (MMBbl)
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0.67 | 0.69 | (3%) | ||||||||
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Natural gas (Bcf)
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6.79 | 6.32 | 7% | ||||||||
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Total equivalent (MMBOE)
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8.53 | 7.60 | 12% | ||||||||
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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
|
$ | 97.69 | $ | 81.66 | 20% | ||||||
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Effect of crude oil hedging
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(2.01 | )(1) | (0.80 | ) | |||||||
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Realized price
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$ | 95.68 | $ | 80.86 | 18% | ||||||
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NYMEX oil (per Bbl)
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$ | 105.82 | $ | 92.19 | 15% | ||||||
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NGLs (per Bbl):
|
|||||||||||
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Realized price
|
$ | 35.78 | $ | 30.77 | 16% | ||||||
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Natural gas (per Mcf):
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|||||||||||
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Price received
|
$ | 3.64 | $ | 3.39 | 7% | ||||||
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Effect of natural gas hedging
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- | 0.05 | |||||||||
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Realized price
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$ | 3.64 | $ | 3.44 | 6% | ||||||
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NYMEX natural gas (per Mcf)
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$ | 3.58 | $ | 2.81 | 27% | ||||||
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(1)
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Whiting paid $13.6 million in pre-tax cash settlements on its crude oil hedges during the third quarter of 2013. A summary of Whiting’s outstanding hedges is included later in this news release.
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7
Third Quarter and First Nine Months 2013 Costs and Margins
A summary of production, cash revenues and cash costs on a per BOE basis is as follows:
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Per BOE, Except Production
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||||||||||||||||
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Three Months Ended
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Nine Months Ended
|
|||||||||||||||
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September 30,
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September 30,
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2013
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2012
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2013
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2012
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Production (MMBOE)
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8.53 | 7.60 | 25.05 | 22.29 | ||||||||||||
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Sales price, net of hedging
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$ | 81.21 | $ | 67.99 | $ | 77.34 | $ | 69.41 | ||||||||
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Lease operating expense
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12.79 | 12.35 | 12.54 | 12.48 | ||||||||||||
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Production tax
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7.17 | 5.73 | 6.64 | 5.78 | ||||||||||||
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General & administrative
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5.90 | 3.29 | 4.33 | 3.80 | ||||||||||||
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Exploration
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3.33 | 1.36 | 2.86 | 1.51 | ||||||||||||
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Cash interest expense
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2.59 | 2.15 | 2.47 | 2.16 | ||||||||||||
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Cash income tax expense (benefit)
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0.85 | (0.24 | ) | 0.20 | 0.03 | |||||||||||
| $ | 48.58 | $ | 43.35 | $ | 48.30 | $ | 43.65 | |||||||||
Third Quarter and First Nine Months 2013 Drilling and Expenditures Summary
The table below summarizes Whiting’s operated and non-operated drilling activity and capital expenditures for the three and nine months ended September 30, 2013:
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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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|||||||||||||||
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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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|||||||||||||
| Q3 13 | 120 / 57.2 | 3 / 2.9 | 123 / 60.1 | 98% / 95% | $ | 696.6 | (1) | ||||||||||
| 9M 13 | 314 / 157.9 | 6 / 5.8 | 320 / 163.7 | 98% / 96% | $ | 1,929.0 | |||||||||||
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(1)
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Includes $68 million for land and $45 million for facilities.
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Outlook for Fourth Quarter and Full-Year 2013
The following table provides guidance for the fourth quarter and full-year 2013 based on current forecasts, including Whiting’s full-year 2013 capital budget of $2,500.0 million:
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Guidance
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|||||||||||||||||||
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Fourth Quarter
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Full-Year | ||||||||||||||||||
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2013
|
2013 | ||||||||||||||||||
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Production (MMBOE)
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8.80 | - | 9.20 | 33.90 | - | 34.30 | |||||||||||||
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Lease operating expense per BOE(1)
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$ | 12.50 | - | $ | 13.00 | $ | 12.40 | - | $ | 12.80 | |||||||||
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General and admin. expense per BOE(2)
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$ | 3.40 | - | $ | 3.80 | $ | 4.00 | - | $ | 4.20 | |||||||||
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Interest expense per BOE
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$ | 4.70 | - | $ | 4.90 | $ | 3.20 | - | $ | 3.40 | |||||||||
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Depr., depletion and amort. per BOE
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$ | 25.25 | - | $ | 26.25 | $ | 25.50 | - | $ | 26.00 | |||||||||
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Prod. taxes (% of production revenue)
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8.6% | - | 8.8% | 8.5% | - | 8.6% | |||||||||||||
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Oil price differentials to NYMEX per Bbl(3)
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( | $ | 8.50 | ) | - | ( | $ | 9.50 | ) | ( | $ | 6.80 | ) | - | ( | $ | 7.40 | ) | |
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Gas price premium to NYMEX per Mcf(4)
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$ | 0.00 | - | $ | 0.20 | $ | 0.15 | - | $ | 0.35 | |||||||||
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(1)
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The increase in LOE reflects the payout of our oil gathering system at Robinson Lake and should be offset by a commensurate increase in our realized oil price.
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(2)
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Full-year guidance includes a $21.7 million charge under the Whiting Production Participation Plan related to the Postle sale.
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(3)
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Does not include the effect of NGLs.
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(4)
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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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8
Hedges and Fixed Price Natural Gas Contracts
The following summarizes Whiting’s crude oil hedges as of October 1, 2013:
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Weighted Average
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As a Percentage of
|
|||||||
|
Derivative
|
Hedge
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Contracted Volume
|
NYMEX Price
|
September 2013
|
||||
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Instrument
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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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Three-way collars(1)
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2013
|
|||||||
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Q4
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1,040,000
|
$ 71.25 - $ 85.63 - $ 113.95
|
47.5%
|
|||||
|
2014
|
||||||||
|
Q1
|
1,200,000
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$ 71.00 - $ 85.00 - $ 103.56
|
54.9%
|
|||||
|
Q2
|
1,200,000
|
$ 71.00 - $ 85.00 - $ 103.56
|
54.9%
|
|||||
|
Q3
|
1,200,000
|
$ 71.00 - $ 85.00 - $ 103.56
|
54.9%
|
|||||
|
Q4
|
1,200,000
|
$ 71.00 - $ 85.00 - $ 103.56
|
54.9%
|
|||||
|
Collars
|
2013
|
|||||||
|
Oct
|
294,340
|
$ 48.15 - $ 90.69
|
13.5%
|
|||||
|
Nov
|
194,340
|
$ 47.96 - $ 85.90
|
8.9%
|
|||||
|
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 October 1, 2013:
|
Weighted Average
|
As a Percentage of
|
|||||
|
Hedge
|
Contracted Volume
|
Contracted Price
|
September 2013
|
|||
|
Period
|
(MMBtu per Month)
|
(per MMBtu)
|
Gas Production
|
|||
|
2013
|
||||||
|
Q4
|
368,000
|
$5.47
|
16.3%
|
|||
|
2014
|
||||||
|
Q1
|
330,000
|
$5.49
|
14.6%
|
|||
|
Q2
|
333,667
|
$5.49
|
14.8%
|
|||
|
Q3
|
337,333
|
$5.49
|
14.9%
|
|||
|
Q4
|
337,333
|
$5.49
|
14.9%
|
9
Selected Operating and Financial Statistics
|
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
Selected operating statistics:
|
||||||||||||||||
|
Production
|
||||||||||||||||
|
Oil, MBbl
|
6,736 | 5,861 | 19,686 | 17,020 | ||||||||||||
|
NGLs, MBbl
|
666 | 687 | 2,070 | 2,055 | ||||||||||||
|
Natural gas, MMcf
|
6,789 | 6,318 | 19,777 | 19,305 | ||||||||||||
|
Oil equivalents, MBOE
|
8,533 | 7,601 | 25,053 | 22,292 | ||||||||||||
|
Average prices
|
||||||||||||||||
|
Oil per Bbl (excludes hedging)
|
$ | 97.69 | $ | 81.66 | $ | 91.74 | $ | 83.99 | ||||||||
|
NGLs per Bbl
|
$ | 35.78 | $ | 30.77 | $ | 38.78 | $ | 38.06 | ||||||||
|
Natural gas per Mcf (excludes hedging)
|
$ | 3.64 | $ | 3.39 | $ | 3.90 | $ | 3.36 | ||||||||
|
Per BOE data
|
||||||||||||||||
|
Sales price (including hedging)
|
$ | 81.21 | $ | 67.99 | $ | 77.34 | $ | 69.41 | ||||||||
|
Lease operating
|
$ | 12.79 | $ | 12.35 | $ | 12.54 | $ | 12.48 | ||||||||
|
Production taxes
|
$ | 7.17 | $ | 5.73 | $ | 6.64 | $ | 5.78 | ||||||||
|
Depreciation, depletion and amortization
|
$ | 25.73 | $ | 23.63 | $ | 25.71 | $ | 22.26 | ||||||||
|
General and administrative
|
$ | 5.90 | (1) | $ | 3.29 | $ | 4.33 | (1) | $ | 3.80 | (2) | |||||
|
Selected financial data:
|
||||||||||||||||
|
(In thousands, except per share data)
|
||||||||||||||||
|
Total revenues and other income
|
$ | 830,985 | $ | 530,482 | $ | 2,107,925 | $ | 1,596,363 | ||||||||
|
Total costs and expenses
|
$ | 525,698 | $ | 397,253 | $ | 1,456,903 | $ | 1,064,409 | ||||||||
|
Net income available to common shareholders
|
$ | 204,101 | $ | 82,865 | $ | 424,782 | $ | 331,678 | ||||||||
|
Earnings per common share, basic
|
$ | 1.72 | $ | 0.70 | $ | 3.60 | $ | 2.82 | ||||||||
|
Earnings per common share, diluted
|
$ | 1.71 | $ | 0.70 | $ | 3.56 | $ | 2.79 | ||||||||
|
Average shares outstanding, basic
|
118,654 | 117,631 | 118,127 | 117,590 | ||||||||||||
|
Average shares outstanding, diluted
|
119,507 | 118,924 | 119,511 | 118,968 | ||||||||||||
|
Net cash provided by operating activities
|
$ | 513,896 | $ | 382,760 | $ | 1,254,127 | $ | 1,017,945 | ||||||||
|
Net cash used in investing activities
|
$ | (138,674 | ) | $ | (543,223 | ) | $ | (1,341,755 | ) | $ | (1,221,158 | ) | ||||
|
Net cash provided by financing activities
|
$ | 627,045 | $ | 179,731 | $ | 1,068,407 | $ | 213,477 | ||||||||
|
(1)
|
For the three and nine months ended September 30, 2013, the cost includes the effect of a charge under our Production Participation Plan related to the sale of the Postle Properties of $2.54 per BOE and $0.87 per BOE, respectively.
|
|
(2)
|
For the nine months ended September 30, 2012, the cost includes the effect of a charge under our Production Participation Plan related to the Whiting USA Trust II divestiture of $0.39 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 September 30, 2013, to be filed with the Securities and Exchange Commission.
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands)
|
September 30,
2013
|
December 31, 2012
|
|||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 1,025,579 | $ | 44,800 | ||||
|
Accounts receivable trade, net
|
361,512 | 318,265 | ||||||
|
Prepaid expenses and other
|
13,723 | 21,347 | ||||||
|
Total current assets
|
1,400,814 | 384,412 | ||||||
|
Property and equipment:
|
||||||||
|
Oil and gas properties, successful efforts method:
|
||||||||
|
Proved properties
|
9,880,963 | 8,849,515 | ||||||
|
Unproved properties
|
415,748 | 362,483 | ||||||
|
Other property and equipment
|
176,516 | 141,738 | ||||||
|
Total property and equipment
|
10,473,227 | 9,353,736 | ||||||
|
Less accumulated depreciation, depletion and amortization
|
(2,907,055 | ) | (2,590,203 | ) | ||||
|
Total property and equipment, net
|
7,566,172 | 6,763,533 | ||||||
|
Debt issuance costs
|
51,830 | 28,748 | ||||||
|
Other long-term assets
|
108,157 | 95,726 | ||||||
|
TOTAL ASSETS
|
$ | 9,126,973 | $ | 7,272,419 | ||||
11
WHITING PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share data)
|
September 30,
2013
|
December 31, 2012
|
|||||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Current portion of long-term debt
|
$ | 250,000 | $ | - | ||||
|
Accounts payable trade
|
92,092 | 131,370 | ||||||
|
Accrued capital expenditures
|
158,813 | 110,663 | ||||||
|
Accrued liabilities and other
|
200,262 | 180,622 | ||||||
|
Revenues and royalties payable
|
195,377 | 149,692 | ||||||
|
Taxes payable
|
61,735 | 33,283 | ||||||
|
Derivative liabilities
|
20,164 | 21,955 | ||||||
|
Deferred income taxes
|
9,993 | 9,394 | ||||||
|
Total current liabilities
|
988,436 | 636,979 | ||||||
|
Long-term debt
|
2,653,991 | 1,800,000 | ||||||
|
Deferred income taxes
|
1,284,178 | 1,063,681 | ||||||
|
Derivative liabilities
|
499 | 1,678 | ||||||
|
Production Participation Plan liability
|
95,815 | 94,483 | ||||||
|
Asset retirement obligations
|
99,059 | 86,179 | ||||||
|
Deferred gain on sale
|
88,238 | 110,395 | ||||||
|
Other long-term liabilities
|
26,697 | 25,852 | ||||||
|
Total liabilities
|
5,236,913 | 3,819,247 | ||||||
|
Commitments and contingencies
|
||||||||
|
Equity:
|
||||||||
|
Preferred stock, $0.001 par value, 5,000,000 authorized, 6.25% convertible perpetual preferred stock, no shares authorized, issued or outstanding as of September 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; 120,106,602 issued and 118,654,184 outstanding as of September 30, 2013, 118,582,477 issued and 117,631,451 outstanding as of December 31, 2012
|
120 | 119 | ||||||
|
Additional paid-in capital
|
1,578,033 | 1,566,717 | ||||||
|
Accumulated other comprehensive loss
|
(406 | ) | (1,236 | ) | ||||
|
Retained earnings
|
2,304,170 | 1,879,388 | ||||||
|
Total Whiting shareholders’ equity
|
3,881,917 | 3,444,988 | ||||||
|
Noncontrolling interest
|
8,143 | 8,184 | ||||||
|
Total equity
|
3,890,060 | 3,453,172 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 9,126,973 | $ | 7,272,419 | ||||
12
WHITING PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(In thousands, except per share data)
|
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
REVENUES AND OTHER INCOME:
|
||||||||||||||||
|
Oil, NGL and natural gas sales
|
$ | 706,543 | $ | 521,195 | $ | 1,963,525 | $ | 1,572,648 | ||||||||
|
Gain (loss) on hedging activities
|
(665 | ) | 398 | (1,313 | ) | 2,285 | ||||||||||
|
Amortization of deferred gain on sale
|
7,750 | 8,636 | 23,680 | 21,281 | ||||||||||||
|
Gain (loss) on sale of properties
|
116,274 | 99 | 119,706 | (263 | ) | |||||||||||
|
Interest income and other
|
1,083 | 154 | 2,327 | 412 | ||||||||||||
|
Total revenues and other income
|
830,985 | 530,482 | 2,107,925 | 1,596,363 | ||||||||||||
|
COSTS AND EXPENSES:
|
||||||||||||||||
|
Lease operating
|
109,106 | 93,859 | 314,064 | 278,153 | ||||||||||||
|
Production taxes
|
61,143 | 43,519 | 166,228 | 128,893 | ||||||||||||
|
Depreciation, depletion and amortization
|
219,530 | 179,587 | 644,135 | 496,296 | ||||||||||||
|
Exploration and impairment
|
47,092 | 23,882 | 127,765 | 79,362 | ||||||||||||
|
General and administrative
|
50,368 | 25,034 | 108,466 | 84,611 | ||||||||||||
|
Interest expense
|
24,988 | 18,734 | 69,579 | 55,095 | ||||||||||||
|
Change in Production Participation Plan liability
|
(10,798 | ) | 6,217 | 1,332 | 6,199 | |||||||||||
|
Commodity derivative (gain) loss, net
|
24,269 | 6,421 | 25,334 | (64,200 | ) | |||||||||||
|
Total costs and expenses
|
525,698 | 397,253 | 1,456,903 | 1,064,409 | ||||||||||||
|
INCOME BEFORE INCOME TAXES
|
305,287 | 133,229 | 651,022 | 531,954 | ||||||||||||
|
INCOME TAX EXPENSE (BENEFIT):
|
||||||||||||||||
|
Current
|
7,220 | (1,859 | ) | 5,131 | 676 | |||||||||||
|
Deferred
|
93,976 | 51,975 | 220,612 | 198,868 | ||||||||||||
|
Total income tax expense
|
101,196 | 50,116 | 225,743 | 199,544 | ||||||||||||
|
NET INCOME
|
204,091 | 83,113 | 425,279 | 332,410 | ||||||||||||
|
Net loss attributable to noncontrolling interest
|
10 | 21 | 41 | 76 | ||||||||||||
|
NET INCOME AVAILABLE TO SHAREHOLDERS
|
204,101 | 83,134 | 425,320 | 332,486 | ||||||||||||
|
Preferred stock dividends
|
- | (269 | ) | (538 | ) | (808 | ) | |||||||||
|
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
|
$ | 204,101 | $ | 82,865 | $ | 424,782 | $ | 331,678 | ||||||||
|
EARNINGS PER COMMON SHARE:
|
||||||||||||||||
|
Basic
|
$ | 1.72 | $ | 0.70 | $ | 3.60 | $ | 2.82 | ||||||||
|
Diluted
|
$ | 1.71 | $ | 0.70 | $ | 3.56 | $ | 2.79 | ||||||||
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
||||||||||||||||
|
Basic
|
118,654 | 117,631 | 118,127 | 117,590 | ||||||||||||
|
Diluted
|
119,507 | 118,924 | 119,511 | 118,968 | ||||||||||||
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
|
Nine Months Ended
|
|||||||||||||||
|
September 30,
|
September 30,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
Net Income Available to Common Shareholders
|
$ | 204,101 | $ | 82,865 | $ | 424,782 | $ | 331,678 | ||||||||
|
Adjustments Net of Tax:
|
||||||||||||||||
|
Amortization of Deferred Gain on Sale
|
(4,882 | ) | (5,387 | ) | (14,918 | ) | (13,298 | ) | ||||||||
|
(Gain) Loss on Sale of Properties
|
(73,252 | ) | (62 | ) | (75,415 | ) | 164 | |||||||||
|
Impairment Expense
|
11,760 | 8,449 | 35,362 | 28,601 | ||||||||||||
|
Charge Under Production Participation Plan Related to Sale of Postle Properties
|
15,078 | - | 15,078 | - | ||||||||||||
|
Charge Under Production Participation Plan Related to Trust II Offering
|
- | - | - | 5,924 | ||||||||||||
|
Change in Production Participation Plan Liability
|
(6,803 | ) | 3,878 | 839 | 3,873 | |||||||||||
|
Total measure of derivative (gain) loss reported under U.S. GAAP
|
15,709 | 3,944 | 16,788 | (40,866 | ) | |||||||||||
|
Total net cash settlements paid on commodity derivatives during the period
|
(8,556 | ) | (2,942 | ) | (16,321 | ) | (16,475 | ) | ||||||||
|
Adjusted Net Income (1)
|
$ | 153,155 | $ | 90,745 | $ | 386,195 | $ | 299,601 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Basic
|
$ | 1.29 | $ | 0.77 | $ | 3.27 | $ | 2.55 | ||||||||
|
Adjusted Net Income Available to Common Shareholders per Share, Diluted
|
$ | 1.28 | $ | 0.77 | $ | 3.24 | $ | 2.53 | ||||||||
|
(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
|
Nine Months Ended
|
|||||||||||||||
|
September 30,
|
September 30,
|
|||||||||||||||
|
2013
|
2012
|
2013
|
2012
|
|||||||||||||
|
Net cash provided by operating activities
|
$ | 513,896 | $ | 382,760 | $ | 1,254,127 | $ | 1,017,945 | ||||||||
|
Exploration
|
28,426 | 10,338 | 71,635 | 33,592 | ||||||||||||
|
Exploratory dry hole costs
|
(9,522 | ) | (1,885 | ) | (21,150 | ) | (2,140 | ) | ||||||||
|
Changes in working capital
|
(82,282 | ) | (47,590 | ) | (11,614 | ) | (42,805 | ) | ||||||||
|
Preferred stock dividends paid
|
- | (269 | ) | (538 | ) | (808 | ) | |||||||||
|
Discretionary cash flow (1)
|
$ | 450,518 | $ | 343,354 | $ | 1,292,460 | $ | 1,005,784 | ||||||||
|
(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, October 24, 2013 at 11:00 a.m. EDT (10:00 a.m. CDT, 9:00 a.m. MDT) to discuss Whiting’s third quarter 2013 financial and operating results. Please call (866) 515-2914 (U.S./Canada) or (617) 399-5128 (International) to be connected to the call and enter the pass code 55172667. 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 October 24, 2013.
A telephonic replay will be available beginning approximately two hours after the call on Thursday, October 24, 2013 and continuing through Thursday, October 31, 2013. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 90153869. 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, Michigan, Gulf Coast and Mid-Continent 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 section 21E of the Securities Exchange Act of 1934. 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 final prospectus supplement dated September 9, 2013. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.
16