WHITING PETROLEUM CORP - FORM 8-K - EX-99 - PRESS RELEASE OF WHITING PETROLEUM CORP, DATED NOVEMBER 2, 2011

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8-K - WHITING PETROLEUM CORPORATION FORM 8-K, DATED NOVEMBER 2, 2011 - WHITING PETROLEUM CORP	form8-l.htm

Company contact:	John B. Kelso, Director of Investor Relations
	303.837.1661 or john.kelso@whiting.com

Whiting Petroleum Corporation Announces Third Quarter 2011 Financial and Operating Results

Whiting’s Q3 2011 Production Reaches a Record 70,675 BOE/D,

Up 10% Over Q2 2011 Total of 64,120 BOE/D

New Discovery at Tarpon Prospect Flows at Williston Basin Bakken Record Initial Rate of 7,009 BOE/D (4,815 BO/D and 13,163 MCF/D) on Full 24-Hour Test

Successful Drilling Program Has Significantly De-Risked (1)

Future Williston Basin Drilling

Company Reports Q3 2011 Net Income Available to Common Shareholders of $206.0 Million or $1.74 per Diluted Share and Adjusted Net Income of

$112.9 Million or $0.95 per Diluted Share

Q3 2011 Discretionary Cash Flow Totals a Record $316.5 Million

DENVER – November 2, 2011 – Whiting Petroleum Corporation’s (NYSE: WLL) production in the third quarter of 2011 totaled a record 6.50 million barrels of oil equivalent (MMBOE), 83% oil/natural gas liquids and 17% natural gas. The daily average production rate was 70,675 barrels of oil equivalent (BOE), an increase of 10% over the 64,120 BOE per day rate in the second quarter of 2011 and a 7% increase over the 66,120 BOE average daily rate in the third quarter of 2010.

James J. Volker, Whiting’s Chairman and CEO, commented, “We generated a 10% production increase over the second quarter of 2011 and expect another good increase in the fourth quarter. Our well economics continue to remain robust. From January 2009 through September 30, 2011, we completed 115 Bakken wells with an average first six months production of 97,000 BOE. This average is 13,000 BOE higher than the second ranked Bakken operator and 50,000 BOE better than the average of the next 20 operators. We are currently drilling and completing wells in the Sanish field for approximately $6.0 million. Outside of Sanish, in other North Dakota areas, our completed well costs are currently running between $6.0 and $8.0 million and declining as we move into development mode. Our average lease cost in the Williston Basin is $421 per net acre. We hold 683,000 net acres in the Bakken/Three Forks Hydrocarbon System that we believe will provide increased production and reserve additions for years to come.”

(1)	Please refer to the definition of De-Risked found later in this release.

Operating and Financial Results

The following tables summarize the third quarter and first nine months operating and financial results for 2011 and 2010.

	Three Months Ended September 30,
	2011	2010	Change
Production (MMBOE/MBOEPD)	6.50/70.67	6.08/66.12	7%
Discretionary Cash Flow-MM$ (1)	$ 316.5	$ 229.5	38%
Total Revenues-MM$	$ 487.6	$ 373.7	30%
Net Income available to Shareholders-MM$	$ 206.0	$ 5.6	3,579%
Per Basic share	$ 1.75	$ 0.06	2,817%
Per Diluted share	$ 1.74	$ 0.06	2,800%
Adjusted Net Income Available to common Shareholders-MM$ (2)	$ 112.9	$ 71.6	58%
Per Basic share	$ 0.96	$ 0.70	37%
Per Diluted share	$ 0.95	$ 0.65	46%

	Nine Months Ended September 30,
	2011	2010	Change
Production (MMBOE/MBOEPD)	18.28/66.95	17.35/63.55	5%
Discretionary Cash Flow-MM$ (1)	$ 913.9	$ 672.2	36%
Total Revenues-MM$	$1,401.0	$1,102.6	27%
Net Income available to Shareholders-MM$	$ 428.0	$ 206.8	107%
Per Basic share	$ 3.65	$ 2.02	81%
Per Diluted share	$ 3.62	$ 2.00	81%
Adjusted Net Income Available to common Shareholders-MM$ (2)	$ 332.9	$ 206.3	61%
Per Basic share	$ 2.84	$ 2.02	41%
Per Diluted share	$ 2.81	$ 1.88	49%

(1) A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.

(2) A reconciliation of adjusted net income available to common shareholders to net income available to common shareholders is included later in this news release.

Operations Update

Core Development Areas

Bakken and Three Forks Development

Lewis & Clark/Pronghorn Prospects. Whiting’s net production from the Lewis & Clark/Pronghorn prospects averaged 3,960 BOE per day in the third quarter of 2011, up 50% from the 2,640 BOE per day average in the second quarter of 2011. From July 15 through October 22, 2011, Whiting completed 12 new wells at Lewis & Clark/Pronghorn, bringing the total number of producing operated Pronghorn Sand(1) / Three Forks wells to 38. As of October 22, 2011, there were 11 operated wells being completed or awaiting completion and seven wells were being drilled. We currently have seven drilling rigs operating in these prospects, and we expect to have eight rigs working by year-end 2011.

Since our update on September 26, 2011, we completed the following three Pronghorn Sand/Three Forks wells at Lewis & Clark/Pronghorn:

Sub-Area	County	Well Name	WI	NRI	IP (BOE/d) 24 Hour Test (2)
Pronghorn	Stark	Pronghorn Federal 34-11TFH	100.0%	80.0%	1,645
Pronghorn	Stark	Pronghorn Federal 21-14TFH	55.9%	44.7%	1,849
Demores	Billings	Demores Federal 31-10TFH	100.0%	80.0%	789

Averages			85.3%	68.2%	1,428

The following table summarizes our results to date at Lewis & Clark/Pronghorn:

	Avg WI %	Avg NRI %	Avg IP BOE/d 24-hr Test	Avg 1st 30 Day	Avg 1st 60 Day	Avg 1st 90 Day
No. of Wells(3)	33	33	33	29	23	21
Averages	77%	62%	1,192	523	404	387

(1)	The North Dakota Industrial commission (NDIC) recently renamed the Sanish Sand the Pronghorn Sand.

(2)	Excludes the Wolski 44-23H, which was completed in the Scallion formation pumping 188 BOE per day.

(3)	Excludes the 5 delineation wells outside the reservoir boundary.

NOTE: A list of all Lewis & Clark/Pronghorn wells completed inception to date is included in our current corporate presentation, which is available on our website.

We own 384,658 gross (255,905 net) acres in the Lewis & Clark/Pronghorn prospects, which is three and a half times the area of Sanish field. Please see the map in our corporate presentation. Based on our drilling activities to date across Lewis & Clark/Pronghorn, we believe that currently 52% of our total acreage is drillable and de-risked (46% at Lewis & Clark and 59% at Pronghorn). The following table summarizes the total and de-risked acreage at Lewis & Clark and Pronghorn.

Lewis & Clark Acreage		Pronghorn Acreage
Total Gross	216,240	Total Gross	168,418
Total Net	139,551	Total Net	116,354
De-Risked Gross	100,041	De-Risked Gross	99,405
De-Risked Net	64,193	De-Risked Net	68,649

We believe we can drill two Pronghorn Sand/Three Forks wells per 1,280-acre spacing unit at Lewis & Clark and three Pronghorn Sand/Three Forks wells per 1,280-acre unit at Pronghorn. The following tables show the number of total and de-risked drilling locations at Lewis & Clark/Pronghorn.

Lewis & Clark Locations		Pronghorn Locations
Total Potential	338	Total Potential	395
De-Risked to Date	156	De-Risked to Date	233

Based on production to date at Lewis & Clark/Pronghorn, Hidden Bench, Tarpon, and Cassandra, we believe that our wells on these prospects will have typical Estimated Ultimate Recoveries (EURs) in the 350,000 to 600,000 BOE range.

Hidden Bench Prospect. Whiting’s net production from the Hidden Bench prospect averaged 855 BOE per day in the third quarter of 2011. We currently hold 59,734 gross (29,334 net) acres in the prospect, which is located in McKenzie County, North Dakota. Through October 22, 2011, Whiting completed five wells in the Middle Bakken on the prospect. As of October 22, 2011, we had two operated wells waiting on completion and two rigs drilling in the area. Based on our drilling to date, we believe 100% of the prospect is now drillable for the Middle Bakken and de-risked. We estimate we can drill at least two Middle Bakken wells per 1,280-acre spacing unit at Hidden Bench. This equates to 93 gross de-risked Middle Bakken locations. We have not yet tested the Three Forks at Hidden Bench. Please see the Hidden Bench map in our corporate presentation.

Tarpon Prospect. Whiting has set a new initial production record for all Bakken wells drilled in the Williston Basin. The Tarpon Federal 21-4H well was completed in the Middle Bakken (after a 30 stage sliding sleeve frac job) flowing 4,815 barrels of oil and 13,163 Mcf of gas (7,009 BOE) per day on October 17, 2011. The Company owns a 56% working interest and a 45% net revenue interest in the Tarpon well. Whiting drilling engineers also set a new Tarpon Prospect area record by drilling this well to total depth in 13.3 days. We expect the completed well cost to be $6.35 million. Whiting holds 8,125 gross (6,265 net) acres at the Tarpon prospect, which is located in McKenzie County, North Dakota. Whiting has controlling interests in four 1,280-acre Tarpon prospect spacing units. We have the potential to drill a total of 12 Middle Bakken and eight Three Forks wells in these units. Based on our drilling to date, we believe 100% of the prospect is now drillable for the Middle Bakken and de-risked. Please see the Tarpon map in our corporate presentation.

Cassandra Prospect. Whiting currently holds 30,664 gross (14,483 net) acres in Cassandra and has controlling interests in 12 1,280-acre spacing units. We have drilled four wells to date in 2011 with IP’s that averaged 878 BOE per day. Based on our drilling and other operators drilling to date, we believe 100% of the prospect is now drillable for the Middle Bakken and de-risked. We have the potential to drill a total of 24 operated Middle Bakken wells and participate in 24 non-operated wells in Cassandra. Please see the Cassandra map in our corporate presentation.

Missouri Breaks Prospect. We plan to spud our first well in Missouri Breaks in the fourth quarter of 2011. Whiting currently holds 58,200 gross (40,250 net) acres in the prospect and has controlling interests in 46 1,280-acre spacing units. Missouri Breaks is located in Richland County, Montana.

Sanish Field. During the third quarter, Whiting completed 28 gross operated wells. Subsequent to the quarter we have completed seven more gross operated wells. We currently have 17 wells waiting on completion and eight wells being drilled. The following table summarizes the Company’s operated and non-operated net production from the Sanish and Parshall fields in the third quarter and in September 2011:

Operated and Non-operated Net Production for Sanish and Parshall Fields (In BOE)
	Nine Months Ended September 30, 2011				September 2011
	Parshall	Sanish	Total		Parshall	Sanish	Total
Whiting Operated	16,167	2,031,369	2,047,536		3,979	666,135	670,114
Non-Operated	279,743	181,247	460,990		87,229	59,111	146,340
	295,910	2,212,616	2,508,526		91,208	725,246	816,454

Daily BOE	3,215	24,050	27,265	(1)	3,040	24,175	27,215	(2)

(1)	Up from 24,350 in the second quarter 2011.

(2)	Up from 23,760 in June 2011.

Robinson Lake Gas Plant. As of October 22, 2011, the plant was processing 43.5 MMcf of gas per day (gross). Currently, there is inlet compression in place to process 60 MMcf per day. Compression can be added to 90 MMcf per day as the processing demand increases. Whiting owns a 50% interest in the plant.

Belfield Gas Processing Plant. Whiting continues construction on the 30 MMcf per day gas processing plant located south of Belfield, North Dakota. Steady plant operation is scheduled for January 2012. Gas gathering construction is progressing on schedule. The South Heart Substation, which will supply power to the plant, is currently scheduled to be completed in mid-November 2011. Our Bakken Express project came on-line in late August, allowing us to truck natural gas until the plant and gathering system are completed.

Belfield Oil Terminal. Construction continues on the Belfield oil terminal in our Lewis & Clark prospect area. Construction of a seven mile oil transmission line from Whiting’s Belfield oil terminal to the Bridger Pipeline interconnect is expected to start in the fourth quarter of 2011. We estimate that the completion of this terminal will reduce transportation costs by $2.00 – $3.00 per barrel.

Service Availability. During the third quarter of 2011, we had three full-time dedicated frac crews working in the Williston Basin and reduced the number of operated wells waiting on completion from 44 on July 15, 2011 to 26 on October 22, 2011. Based on our current drilling rig count of 18 rigs working in the Williston Basin, a typical inventory of wells waiting on completion is 20 to 25 wells. In anticipation of winter weather delays, we plan to add a fourth frac crew before year-end 2011.

EOR Projects

North Ward Estes Field. Production from our North Ward Estes field averaged 8,440 BOE per day in the third quarter of 2011. This average rate represented a 4% increase from the 8,125 net daily rate in the second quarter of 2011.

As we reported in our news release on June 8, 2011, we were experiencing under-deliveries of CO2 contract quantities from our North Ward Estes field CO2 supplier. For most of July 2011, our daily CO2 deliveries were approximately 122 MMcf. Since September 1, 2011, we have been receiving our full contract quantities of 134 MMcf of CO2 per day. Whiting is currently injecting approximately 290 MMcf of CO2 per day into the field, of which about 54% is recycled gas.

Postle Field. In the third quarter of 2011, the Postle field produced at an average net rate of 7,980 BOE per day, a 1% decrease from the 8,095 BOE per day rate in the second quarter 2011. Production rates are expected to be approximately 8,000 BOE per day through year end. Whiting is currently injecting 120 MMcf of CO2 per day into the field, of which approximately 65% is recycled gas.

Other Development Areas

Delaware Basin: Big Tex Play “Wolfbone”. The Wolfbone play consists of a 2,000 to 3,000-foot vertical section of Permian age interbedded carbonate and organic rich siltstone at a depth of 5,700 to 9,500 feet in Pecos, Reeves and Ward counties, Texas. Targets include the Brushy Canyon, Bone Spring, and Wolfcamp horizons. Currently, Whiting has a lease position consisting of 121,771 gross (89,852 net) acres.

Whiting has moved from vertical wells in the Big Tex area to horizontals in this play. We have drilled four horizontals with two rigs currently drilling horizontal wells to test several different objectives. Our first Bone Spring horizontal well, the Bissett 9701H, was drilled with a 3,645-foot lateral and was completed on July 4, 2011 with 18 frac stages. Over the first 30 days, this well averaged 336 BOE per day. We believe this well proved up at least eight development wells, in which we hold a 100% working interest. We have completed two other horizontal wells; the Chilton 5601H fraced with 13 stages in the Bone Spring and the Lizzy 402H fraced with 17 stages in the Brushy Canyon. We are now placing these wells on pump.

Redtail Niobrara Prospect. The Redtail prospect targets the Niobrara “B” zone in the Denver Basin, in Weld County, Colorado. Whiting controls 104,425 gross (76,065 net) acres in the play. The Wild Horse 16-13H, our first well drilled on a northeast azimuth, is currently producing 328 BOE per day. The last well in the initial 2010-2011 five-well program, the Two Mile Creek 22-13H, has been completed with an initial production rate of 216 BOE per day. This well was also drilled on a northeast azimuth.

Based on the results of the Wild Horse and Two Mile Creek wells and utilizing newly acquired 3D, Whiting is currently planning and permitting a second round of drilling. The new program will consist of two north-south oriented 7,000-foot laterals drilled in 960-acre spacing units and two 4,000-foot northeast oriented laterals in 640-acre units. Drill depths within this area range from 5,500 to 6,500 feet with completed well costs of $4.0 million for shorter laterals and $5.5 million for longer laterals. We spudded the first well in late October.

Operated Drilling and Workover Rig Count

As of October 22, 2011, 27 operated drilling rigs and 63 operated workover rigs were active on our properties. We were also participating in the drilling of four non-operated wells, all in North Dakota.

The breakdown of our operated rigs as of October 22, 2011 was as follows:

Region	Drilling	Workover
Northern Rockies
Sanish Field	9	14
Lewis & Clark/Pronghorn	7	6
Hidden Bench	2	0
Tarpon	1	0
Central Rockies
Redtail Prospect	1	0
Other	1	0
EOR Projects
Postle	1	4
North Ward Estes	2	30
Permian
Big Tex	2	1
Other	1	6
Mid-Continent	0	2
Totals	27	63

In the third quarter, we had an average of 12 service units working in our Sanish field. By November 1, 2011, we had increased this number to a total of 26 service units. These service units will be used to reduce the 66 wells in Sanish awaiting service work. The lower number of service units in the third quarter limited our production increase. We expect to reduce the number of shut-in wells awaiting service work in Sanish field to approximately 20 by year-end 2011.

Capital Budget Increased from $1.6 Billion to $1.7 Billion

Whiting increased its 2011 capital budget from $1.6 billion to $1.7 billion. The following table provides a breakdown of our budget increase.

2011 Budget Increase by Category (in millions)
Non-Operated drilling (40 gross, 5 net wells)	$	41
Operated Drilling (4 gross, 4 net, 1 re-entry well)(1)		20
Land		17
Facilities		5
Q3 Temporary use of ceramic proppant (2)		17
Total	$	100

(1)	Consists of 1 Big Tex well, 1 Big Island well, and 2 Exploration wells.
(2)	Consists of 20 net wells where ceramic proppant was used due to a temporary sand shortage at a cost of $850K per well.

Borrowing Base Increased from $1.1 Billion to $1.5 Billion

On October 12, 2011, Whiting entered into an amendment with its banking syndicate to increase the borrowing base under its Credit Agreement from $1.1 billion to $1.5 billion until May 1, 2012, the next redetermination date of the Credit Agreement. No other terms of the Credit Agreement were changed.

Prospective Eagle Ford Acreage Sold for $66.4 Million, $12,542 per Net Acre

During the third quarter, Whiting sold approximately 3,532 net leasehold acres prospective for oil and gas production from the Eagle Ford formation in Karnes, Live Oak and Dewitt Counties, Texas for a total cash consideration of $66.4 million before closing adjustments. The transaction, which was effective July 1, 2011, closed on September 29, 2011. Whiting used the net proceeds from the property sale to reduce the amount drawn under its Credit Agreement.

The non-core acreage sold is located in Kawitt, Nordheim and Three Rivers Fields, which produce from the Speary, Edwards, Wilcox and Eagle Ford formations. Recent net daily production was approximately 4.0 MMcfe from 33 producing wells. The property sale also included 16 shut-in and temporarily abandoned wells. The estimated proved net reserves associated with the producing properties were 1.1 MMBOE. Whiting valued the existing production in the transaction at $22.1 million net of plugging liabilities and the acreage at $44.3 million net of the production value, or approximately $12,542 per net acre.

Other Financial and Operating Results

The following table summarizes the Company’s net production and commodity price realizations for the quarters ended September 30, 2011 and 2010:

	Three Months Ended September 30,
Production	2011			2010			Change
Oil and NGLs (MMBbls)		5.37			4.94		9%
Natural gas (Bcf)		6.81			6.88		(1%)
Total equivalent (MMBOE)		6.50			6.08		7%

Average Sales Price
Oil and NGLs (per Bbl):
Price received	$	80.96		$	67.02		21%
Effect of crude oil hedging (1)		(0.35	)		(0.92	)
Realized price	$	80.61		$	66.10		22%

Natural gas (per Mcf):
Price received	$	5.00		$	5.00		0%
Effect of natural gas hedging (1)		0.02			0.02
Realized price	$	5.02		$	5.02		0%

(1)	Whiting realized pre-tax cash settlement losses of $1.9 million on its crude oil hedges and gains of $0.2 million on its natural gas hedges during the third quarter of 2011. A summary of Whiting’s outstanding hedges is included later in this news release.

Third Quarter and First Nine Months 2011 Costs and Margins

A summary of production, cash revenues and cash costs on a per BOE basis are as follows:

	Per BOE, Except Production
	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2011		2010			2011		2010
Production (MMBOE)		6.50		6.08			18.28		17.35

Sales price, net of hedging	$	71.80	$	59.32		$	73.45	$	60.70
Lease operating expense		11.94		11.34			12.20		11.39
Production tax		5.31		4.31			5.49		4.46
General & administrative		3.56		3.20			3.42		2.80
Exploration		1.45		1.01			1.99		1.49
Cash interest expense		2.16		1.94			2.16		2.15
Cash income tax expense (benefit)		0.15		(0.03	)		0.25		0.37
	$	47.23	$	37.55		$	47.94	$	38.04

During the third quarter, the company-wide differential for crude oil/NGLs compared to NYMEX was $8.85 per barrel, which compared to $10.05 per barrel in the second quarter of 2011. We expect our company-wide oil price differential to average between $9.00 and $10.00 during the fourth quarter of 2011. Within the Bakken, Whiting’s operated production had a differential of approximately $8.00 per barrel in October 2011.

The company-wide basis differential for natural gas compared to NYMEX in the third quarter was at a premium of $0.80 per Mcf, which compared to a premium of $0.62 per Mcf in the second quarter of 2011. We expect our natural gas to sell at a premium price of between $0.70 and $1.00 during the fourth quarter of 2011.

Third Quarter and First Nine Months 2011 Drilling Summary

The table below summarizes Whiting’s operated and non-operated drilling activity and exploration and development costs incurred for the three and nine months ended September 30, 2011:

	Gross/Net Wells Completed				Expl. & Dev. Cost
	Producing	Non-Producing	Total New Drilling	% Success Rate	(in MM)(2)
Q3 11	96 / 43.4	0 / 0	96 / 43.4	100% / 100%	$503.6
9M 11	202 / 91.7	5 / 4.2 (1)	207 / 95.9	98% / 96%	$1,316.7

(1)

Includes one exploratory dry hole and one development dry hole for shallow Wilcox at Greenbranch field in McMullen Co., TX, one re-entry mechanical failure exploratory well at the Big Tex prospect, Pecos Co., TX, one exploratory Niobrara dry hole in Carbon Co., WY and one non-op development Red River oil test in Richland Co., MT.

(2)	Includes $60.4 million and $179.7 million of acreage acquisition costs for the three and nine months ended September 30, 2011, respectively.

Outlook for Fourth Quarter and Full-Year 2011

The following table provides guidance for the fourth quarter and full-year 2011 based on current forecasts, including Whiting’s full-year 2011 capital budget of $1,700.0 million:

	Guidance
	Fourth Quarter 2011	Full-Year 2011
Production (MMBOE)	6.85 - 7.25	25.15 - 25.55
Lease operating expense per BOE	$11.40 - $11.70	$11.90 - $12.10
General and admin. expense per BOE	$ 3.45 - $ 3.65	$ 3.35 - $ 3.55
Interest expense per BOE	$ 2.30 - $ 2.50	$ 2.35 - $ 2.55
Depr., depletion and amort. per BOE	$19.00 - $19.40	$18.60 - $19.00
Prod. taxes (% of production revenue)	7.6% - 7.9%	7.3% - 7.6%
Oil price differentials to NYMEX per Bbl	$ 9.00 - $10.00	$ 9.50 - $10.50
Gas price premium to NYMEX per Mcf (1)	$ 0.70 - $ 1.00	$ 0.60 - $ 0.90

(1)	Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release.

Oil and Gas Hedges

The following summarizes Whiting’s crude oil hedges as of October 21, 2011:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	NYMEX Price Collar Range	September 2011
Period	(Bbls per Month)	(per Bbl)	Oil Production
2011
Q4	904,255	$61.00 - $98.31	51.1%

2012
Q1	759,054	$61.91 - $105.49	42.9%
Q2	758,850	$61.91 - $105.49	42.9%
Q3	758,650	$61.90 - $105.48	42.9%
Q4	758,477	$61.90 - $105.47	42.8%

2013
Q1	290,000	$47.67 - $90.21	16.4%
Q2	290,000	$47.67 - $90.21	16.4%
Q3	290,000	$47.67 - $90.21	16.4%
Oct	290,000	$47.67 - $90.21	16.4%
Nov	190,000	$47.22 - $85.06	10.7%

The following summarizes Whiting Petroleum Corporation’s natural gas hedges as of October 21, 2011:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	NYMEX Price Collar Range	September 2011
Period	(MMBtu per Month)	(per MMBtu)	Gas Production
2011
Q4	34,554	$7.00 - $14.25	1.6%

2012
Q1	33,381	$7.00 - $15.55	1.5%
Q2	32,477	$6.00 - $13.60	1.5%
Q3	31,502	$6.00 - $14.45	1.4%
Q4	30,640	$7.00 – $13.40	1.4%

Whiting also has the following fixed-price natural gas contracts in place as of October 21, 2011:

		Weighted Average	As a Percentage of
Hedge	Contracted Volume	Contracted Price	September 2011
Period	(MMBtu per Month)	(per MMBtu)	Gas Production
2011
Q4	772,460	$5.30	34.7%

2012
Q1	577,127	$5.30	26.0%
Q2	461,460	$5.41	20.8%
Q3	465,794	$5.41	20.9%
Q4	398,667	$5.46	17.9%

2013
Q1	360,000	$5.47	16.2%
Q2	364,000	$5.47	16.4%
Q3	368,000	$5.47	16.5%
Q4	368,000	$5.47	16.5%

2014
Q1	330,000	$5.49	14.8%
Q2	333,667	$5.49	15.0%
Q3	337,333	$5.49	15.2%
Q4	337,333	$5.49	15.2%

Selected Operating and Financial Statistics

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Selected operating statistics
Production
Oil and NGLs, MBbl		5,368			4,937			14,928			14,004
Natural gas, MMcf		6,807			6,879			20,096			20,068
Oil equivalents, MBOE		6,502			6,083			18,277			17,349
Average Prices
Oil per Bbl (excludes hedging)	$	80.96		$	67.02		$	84.95		$	69.10
Natural gas per Mcf (excludes hedging)	$	5.00		$	5.00		$	4.98		$	5.05
Per BOE Data
Sales price (including hedging)	$	71.80		$	59.32		$	73.45		$	60.70
Lease operating	$	11.94		$	11.34		$	12.20		$	11.39
Production taxes	$	5.31		$	4.31		$	5.49		$	4.46
Depreciation, depletion and amortization	$	18.90		$	16.06		$	18.65		$	16.71
General and administrative	$	3.56		$	3.20		$	3.42		$	2.80
Selected Financial Data
(In thousands, except per share data)
Total revenues and other income	$	487,557		$	373,734		$	1,400,985		$	1,102,631
Total costs and expenses	$	155,183		$	279,315		$	718,869		$	666,228
Net income available to common shareholders	$	205,966		$	5,612		$	427,990		$	206,759
Earnings per common share, basic (1)	$	1.75		$	0.06		$	3.65		$	2.02
Earnings per common share, diluted (1)	$	1.74		$	0.06		$	3.62		$	2.00

Average shares outstanding, basic (1)		117,381			104,296			117,333			102,712
Average shares outstanding, diluted (1)		118,539			104,907			118,572			104,192
Net cash provided by operating activities	$	275,536		$	280,134		$	863,754		$	720,267
Net cash used in investing activities	$	(420,267	)	$	(277,942	)	$	(1,266,880	)	$	(568,078	)
Net cash provided by (used in) financing activities	$	139,730		$	(14,502	)	$	390,262		$	(160,938	)

(1)	All share and per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011.

Conference Call

The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, November 3, 2011 at 11:00 a.m. EDT (10:00 a.m. CDT, 9:00 a.m. MDT) to discuss Whiting’s third quarter 2011 financial and operating results. Please call (800) 638-5495 (U.S./Canada) or (617) 614-3946 (International) and enter the pass code 36864873 to be connected to the call. Access to a live Internet broadcast will be available at www.whiting.com by clicking on the “Investor Relations” box on the menu and then on the link titled “Webcasts.” Slides for the conference call will be available on this website beginning at 11:00 a.m. (EDT) on November 3, 2011.

A telephonic replay will be available beginning approximately two hours after the call on Thursday, November 3, 2011 and continuing through Thursday, November 10, 2011. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 64578544. 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 acquires, exploits, develops and explores for crude oil, natural gas and natural gas liquids primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States. The Company’s largest projects are in the Bakken and Three Forks plays in North Dakota and its Enhanced Oil Recovery fields in Oklahoma and Texas. The Company trades publicly under the symbol WLL on the New York Stock Exchange. For further information, please visit www.whiting.com.

Forward-Looking Statements

This news release contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this news release, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

These risks and uncertainties include, but are not limited to: declines in oil or natural gas prices; impacts of the global recession and tight credit markets; our level of success in exploitation, exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures, including our ability to obtain CO2; 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 regulatory 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; 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, 2010. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.

Definition of De-Risked

“De-Risked” core development acreage and related well locations in the Williston Basin refers to acreage and locations that the Company believes the relative geological risks related to recovery have been reduced as a result of drilling operations to date. However, only a small portion of such acreage and locations has been attributed proved undeveloped reserves and ultimate recovery from such acreage and locations remains subject to all the recovery risks applicable to other acreage.

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, 2011.

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands)

	September 30, 2011			December 31, 2010
ASSETS

Current assets:
Cash and cash equivalents	$	6,088		$	18,952
Accounts receivable trade, net		230,942			199,713
Prepaid expenses and other		31,540			14,878
Total current assets		268,570			233,543

Property and equipment:
Oil and gas properties, successful efforts method:
Proved properties		6,724,836			5,661,619
Unproved properties		362,963			226,336
Other property and equipment		144,158			98,092
Total property and equipment		7,231,957			5,986,047
Less accumulated depreciation, depletion and amortization		(1,961,365	)		(1,630,824	)
Total property and equipment, net		5,270,592			4,355,223

Debt issuance costs		31,782			34,226

Other long term assets		76,562			25,785

TOTAL ASSETS	$	5,647,506		$	4,648,777

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share data)

	September 30, 2011		December 31, 2010
LIABILITIES AND EQUITY

Current liabilities:
Accounts payable trade	$	30,389	$	35,016
Accrued capital expenditures		112,526		84,789
Accrued liabilities and other		133,752		153,062
Revenues and royalties payable		104,185		82,124
Taxes payable		34,139		30,291
Derivative liabilities		20,682		69,375
Deferred income taxes		2,713		4,548
Total current liabilities		438,386		459,205
Long-term debt		1,200,000		800,000
Deferred income taxes		786,932		539,071
Derivative liabilities		31,424		95,256
Production Participation Plan liability		84,584		81,524
Asset retirement obligations		82,842		76,994
Deferred gain on sale		32,618		41,460
Other long-term liabilities		26,669		23,952
Total liabilities		2,683,455		2,117,462
Commitments and contingencies
Equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, 172,400 shares issued and outstanding as of September 30, 2011 and 172,500 shares issued and outstanding as of December 31, 2010, aggregate liquidation preference of $17,240,000 at September 30, 2011		-		-
Common stock, $0.001 par value, 300,000,000 shares authorized; 118,109,058 issued and 117,380,843 outstanding as of September 30, 2011, 117,967,876 issued and 117,098,506 outstanding as of December 31, 2010 (1)		118		59
Additional paid-in capital		1,550,800		1,549,822
Accumulated other comprehensive income		1,144		5,768
Retained earnings		1,403,656		975,666
Total Whiting shareholders’ equity		2,955,718		2,531,315
Noncontrolling interest		8,333		-
Total equity		2,964,051		2,531,315

TOTAL LIABILITIES AND EQUITY	$	5,647,506	$	4,648,777

(1)	All common share amounts (except par value and par value per share amounts) as of December 31, 2010 have been retroactively restated to reflect the Company’s two-for-one stock split in February 2011.

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(In thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
REVENUES AND OTHER INCOME:
Oil and natural gas sales	$	468,573		$	365,239		$	1,368,121		$	1,068,961
Gain on hedging activities		1,871			4,383			7,326			19,641
Amortization of deferred gain on sale		3,518			3,854			10,455			11,613
Gain on sale of properties		13,505			-			14,732			1,918
Interest income and other		90			258			351			498
Total revenues and other income		487,557			373,734			1,400,985			1,102,631
COSTS AND EXPENSES:
Lease operating		77,630			69,001			222,937			197,586
Production taxes		34,510			26,193			100,412			77,341
Depreciation, depletion and amortization		122,890			97,704			340,868			289,836
Exploration and impairment		18,918			10,500			61,326			37,915
General and administrative		23,144			19,480			62,470			48,516
Interest expense		16,130			14,579			45,867			45,903
Loss on early extinguishment of debt		-			6,235			-			6,235
Change in Production Participation Plan liability		853			3,858			3,060			9,550
Commodity derivative (gain) loss, net		(138,892	)		31,765			(118,071	)		(46,654	)
Total costs and expenses		155,183			279,315			718,869			666,228
INCOME BEFORE INCOME TAXES		332,374			94,419			682,116			436,403
INCOME TAX EXPENSE (BENEFIT):
Current		975			(170	)		4,590			6,468
Deferred		125,164			36,057			248,728			159,475
Total income tax expense (benefit)		126,139			35,887			253,318			165,943
NET INCOME		206,235			58,532			428,798			270,460
Preferred stock dividends		(269	)		(52,920	)		(808	)		(63,701	)
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	205,966		$	5,612		$	427,990		$	206,759
EARNINGS PER COMMON SHARE (1):
BASIC	$	1.75		$	0.06		$	3.65		$	2.02
DILUTED	$	1.74		$	0.06		$	3.62		$	2.00
WEIGHTED AVERAGE SHARES OUTSTANDING (1):
BASIC		117,381			104,296			117,333			102,712
DILUTED		118,539			104,907			118,572			104,192

(1)	All share and per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011.

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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net Income Available to Common Shareholders	$	205,966		$	5,612		$	427,990		$	206,759
Cash Premium on Induced Conversion		-			47,529			-			47,529
Adjustments Net of Tax:
Amortization of Deferred Gain on Sale		(2,183	)		(2,390	)		(6,572	)		(7,197	)
Gain on Sale of Properties		(8,379	)		-			(9,261	)		(1,189	)
Impairment Expense		5,881			2,699			15,666			7,471
Loss on Early Extinguishment of Debt		-			3,866			-			3,866
Unrealized Derivative (Gains) Losses		(88,406	)		14,275			(94,953	)		(50,951	)
Adjusted Net Income (1)	$	112,879		$	71,591		$	332,870		$	206,288

Adjusted Net Income Available to Common Shareholders per Share, Basic (2)	$	0.96		$	0.70		$	2.84		$	2.02
Adjusted Net Income Available to Common Shareholders per Share, Diluted (2)	$	0.95		$	0.65		$	2.81		$	1.88

(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 GAAP and may not be comparable to other similarly titled measures of other companies.

(2)	All share and per share amounts have been retroactively restated for the 2010 periods to reflect the Company’s two-for-one stock split in February 2011.

WHITING PETROLEUM CORPORATION

Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow

(In thousands)

	Three Months Ended September 30,
	2011			2010
Net cash provided by operating activities	$	275,536		$	280,134
Exploration		9,440			6,146
Exploratory dry hole costs		(417	)		(199	)
Changes in working capital		32,246			(51,238	)
Preferred stock dividends paid		(269	)		(5,391	)
Discretionary cash flow (1)	$	316,536		$	229,452

	Nine Months Ended September 30,
	2011			2010
Net cash provided by operating activities	$	863,754		$	720,267
Exploration		36,406			25,861
Exploratory dry hole costs		(4,714	)		(2,796	)
Changes in working capital		19,258			(54,990	)
Preferred stock dividends paid		(808	)		(16,172	)
Discretionary cash flow (1)	$	913,896		$	672,170

(1)

Discretionary cash flow is computed as net income plus exploration and impairment costs, depreciation, depletion and amortization, deferred income taxes, non-cash interest costs, loss on early extinguishment of debt, non-cash compensation plan charges, non-cash losses on mark-to-market derivatives and other non-current items less the gain on sale of properties, amortization of deferred gain on sale, non-cash gains on mark-to-market derivatives, and preferred stock dividends paid, not including the preferred stock inducement premium. The non-GAAP measure of discretionary cash flow is presented because management believes it provides useful information to investors for analysis of the Company’s ability to internally fund acquisitions, exploration and development. Discretionary cash flow should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, cash flow or liquidity measures under GAAP and may not be comparable to other similarly titled measures of other companies.

WHITING PETROLEUM CORP - FORM 8-K - EX-99 - PRESS RELEASE OF WHITING PETROLEUM CORP, DATED NOVEMBER 2, 2011 - November 2, 2011

Attached files

WHITING PETROLEUM CORP Reports