Whiting Petroleum Corporation Announces Fourth Quarter and Full-Year 2012 Financial and Operating Re

Whiting Petroleum Corporation Announces Fourth Quarter and Full-Year 2012 Financial and Operating Results

Record Production of 30.21 MMBOE (82,540 BOE/d) in 2012 Up 22% Over 24.78 MMBOE (67,890 BOE/d) in 2011

Proved Reserves Increase 10% to a Record 378.8 MMBOE; Adding Back 10.6 MMBOE Conveyed to Trust - Proved Reserves Up 13%; Company Achieves 246% Reserve Replacement


Q4 2012 Net Income Available to Common Shareholders of $81.4 Million or $0.69 per Diluted Share and Adjusted Net Income of $97.9 Million or $0.83 per Diluted Share

Q4 2012 Discretionary Cash Flow Totals a Record $381.7 Million

2013 Capital Budget of $2.2 Billion; Year-Over-Year Production Growth Guidance of +12% to +16%

Tarpon Prospect Well in North Dakota Tests 6,879 BOE/d

DENVER--(BUSINESS WIRE)-- Whiting Petroleum Corporation's production in the fourth quarter of 2012 totaled 7.917 million barrels of oil equivalent (MMBOE), of which 86% were crude oil/natural gas liquids (NGLs). This fourth quarter 2012 production total equates to a daily average production rate of 86,055 barrels of oil equivalent (BOE), representing a 22% increase over the fourth quarter 2011 average daily rate of 70,685 BOE per day and a 4% increase over the third quarter 2012 average daily rate of 82,615 BOE per day.

Production in 2012 totaled a record 30.21 MMBOE or 82,540 BOE per day. This represents a 22% increase over total production of 24.78 MMBOE or 67,890 BOE per day in 2011. Adding back the 4,500 BOE per day of production that was conveyed to Whiting USA Trust II in March 2012, our production in 2012 was up 28% over 2011.

James J. Volker, Whiting's Chairman and CEO, commented, "2012 was a record year for Whiting Petroleum, and we are off to a great start in 2013.The development of the fields we discovered in 2011 such as Pronghorn, Hidden Bench, Tarpon and Redtail generated excellent results in 2012.In the wake of this development, we posted records in production, proved reserves and discretionary cash flow.According to the December 2012 Oil and Gas Production Report published by the North Dakota State Industrial Commission, Department of Minerals, Oil and Gas Division, Whiting was the number one oil producer in North Dakota at 66,155.7 barrels per day."

Mr. Volker continued, "For the foreseeable future, our objective is to generate double-digit production growth while spending close to our discretionary cash flow.Our 2013 capital budget of $2.2 billion is expected to yield year-over-year production growth in the 12% to 16% range."

We believe the following factors will lead to a strong year in 2013 for Whiting and our shareholders:

Optimization programs that should lead to efficient, low-cost drilling and completion operations;

Higher density pilot projects at Sanish, Pronghorn and Hidden Bench;

Solid cash flow and balance sheet;

Strong Bakken oil prices as differentials improve;

The emergence of our Redtail prospect as a major resource play.

Operating and Financial Results

The following table summarizes the fourth quarter operating and financial results for 2012 and 2011:

Three Months Ended December 31,

2012

2011

Change

Production (MBOE/d)

86.06

70.69

22

%

Discretionary Cash Flow-MM$ (1)

381.7

328.8

16

%

Realized Price ($/BOE)

71.09

75.07

(5

) %

Total Revenues-MM$

577.1

498.6

16

%

Net Income Available to Common Shareholders-MM$

81.4

62.6

30

%

Per Basic Share

$0.69

$0.54

28

%

Per Diluted Share

$0.69

$0.53

30

%

Adjusted Net Income Available to Common Shareholders-MM$ (2)

97.9

124.5

(21

) %

Per Basic Share

$0.83

$1.06

(22

) %

Per Diluted Share

$0.83

$1.05

(21

) %

Twelve Months Ended December 31,

2012

2011

Change

Production (MBOE/d)

82.54

67.89

22

%

Discretionary Cash Flow-MM$ (1)

1,387.5

1,242.7

12

%

Realized Price ($/BOE)

69.85

73.88

(5

) %

Total Revenues-MM$

2,173.5

1,899.6

14

%

Net Income Available to Common Shareholders-MM$

413.1

490.6

(16

) %

Per Basic Share

$3.51

$4.18

(16

) %

Per Diluted Share

$3.48

$4.14

(16

) %

Adjusted Net Income Available to Common Shareholders-MM$ (2)

393.5

456.2

(14

) %

Per Basic Share

$3.35

$3.89

(14

) %

Per Diluted Share

$3.31

$3.85

(14

) %

(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.

Proved Reserves at December 31, 2012

As of December 31, 2012, Whiting had estimated proved reserves of 378.8 MMBOE, of which 64% were classified as proved developed. These estimated proved reserves had a pre-tax PV10% value of $7,283.9 million, of which approximately 99% came from properties located in Whiting's Rocky Mountain, Permian Basin and Mid-Continent core areas.

The following is a summary of Whiting's changes in quantities of proved oil and gas reserves for the year ended December 31, 2012:

Oil

(MBbl)

NGLs

(MBbl)

Natural

Gas

(MMcf)

Total

(MBOE)

Balance - December 31, 2011

260,144

37,609

284,975

345,249

Extensions and discoveries

68,134

6,526

40,915

81,479

Sales of minerals in place

(7,960

)

(320

)

(13,987

)

(10,611

)

Production

(23,139

)

(2,766

)

(25,827

)

(30,209

)

Revisions to previous estimates

4,106

(951

)

(61,812

)

(7,148

)

Balance - December 31, 2012

301,285

40,098

224,264

378,760

Whiting's proved reserves of 378.8 MMBOE represented a 10% increase over the 345.2 MMBOE of proved reserves at year-end 2011, which equates to 246% reserve replacement (81,479 MBOE extensions and discoveries less 7,148 MBOE revisions equals 74,331 MBOE in net reserves added; 74,331 MBOE divided by 30,209 MBOE production = 246% reserve replacement). Adding back the 10.6 MMBOE that was conveyed to Whiting USA Trust II, our proved reserves were up 13%. An estimated 81.5 MMBOE of proved reserves were added through exploration and development activities. This represents a 68% increase over the 48.6 MMBOE of proved reserves that were added from exploration and development in 2011.

Most of the proved reserve additions during 2012 came from the Company's Bakken and Three Forks development in the Williston Basin of North Dakota and Montana. Whiting booked an estimated 66.4 MMBOE of new Bakken and Three Forks proved reserves, bringing its total proved reserves in the Northern Rockies to 165.1 MMBOE at year-end 2012. Of this 165.1 MMBOE, 67% were proved developed and 33% were proved undeveloped.

Probable and Possible Reserves at December 31, 2012

At year-end 2012, Whiting's probable reserves were estimated to be 115.2 MMBOE and our possible reserves were estimated to be 171.2 MMBOE, for a total of 286.3 MMBOE. The year-end 2012 estimated pre-tax PV10% for our probable and possible reserves was $2,621.4 million.

As with our proved reserves, 100% of Whiting's probable and possible reserve estimates were independently engineered by Cawley, Gillespie & Associates, Inc. Please refer to "Disclosure Regarding Reserves and Resources" later in this news release for information on probable and possible reserves.

The following table summarizes our proved, probable and possible reserves:

3P Reserves(1)

Pre-Tax

Natural

PV10%

Oil

NGLS

Gas

Total

%

Value

% of

(MMBbl)

(MMBbl)

(Bcf)

(MMBOE)

Oil

(In MM)

Total

Proved

301.3

40.1

224.3

378.8

80%

$7,284(2)

73%

Probable

85.0

11.9

109.6

115.2

74%

$1,262(3)

13%

Possible

123.2

21.9

156.4

171.2

72%

$1,359(3)

14%

(1)

Oil and gas reserve quantities and related discounted future net cash flows have been derived from oil and gas prices calculated using an average of the first-day-of-the month NYMEX price for each month within the 12 months ended December 31, 2012, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $94.71/Bbl and $2.76/MMBtu.

(2)

Pre-tax PV10% of Proved reserves may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable US GAAP financial measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. As of December 31, 2012, our discounted future income taxes were $1,876.9 million and our standardized measure of after-tax discounted future net cash flows was $5,407.0 million. We believe pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our pre-tax PV10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our proved oil and natural gas reserves.

(3)

Pre-tax PV10% of probable or possible reserves represent the present value of estimated future revenues to be generated from the production of probable or possible reserves, calculated net of estimated lease operating expenses, production taxes and future development costs, using costs as of the date of estimation without future escalation and using 12-month average prices, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or future income taxes and discounted using an annual discount rate of 10%. With respect to pre-tax PV10% amounts for probable or possible reserves, there do not exist any directly comparable US GAAP measures, and such amounts do not purport to present the fair value of our probable and possible reserves.

Potential Future Drilling Locations

Based on independent engineering and internal estimates, Whiting projects it has a total of 9,661 gross (4,503.2 net) potential future drilling locations. These consist of 7,556 gross (3,623.3 net) primary locations identified in our reserve database and 2,105 gross (879.9 net) prospective locations supported by successful exploration drilling or extensive geoscience. Of these gross locations, 50% are located in our Williston Basin Bakken/Three Forks plays and 25% are located in our Redtail Niobrara play.

The following table summarizes our potential gross and net drilling locations by core area:

Identified Primary Locations

Northern Rockies

Gross

Net

Wells per Spacing Unit

Southern Williston (Lewis & Clark; Pronghorn)

1,104

410.2

3 Pronghorn Sand / 1280

Western Williston(1) (Cassandra; Hidden Bench; Tarpon; Missouri Breaks)

1,174

380.5

4 Middle BKN; 3 Upper TFK / 1280

Sanish (Sanish; Parshall) (2)

260

118.1

3.5 Middle BKN; 3 Upper TFK / 1280

Other (3)

588

340.3

Total

3,126

1,249.1

Central Rockies

Redtail Niobrara

2,420

1,215.7

8 Nio "B"; 4 Nio "A" / 640 - 960

Other (4)

958

654.1

Total

3,378

1,869.8

Gulf Coast

131

98.1

Mid-Cont

41

33.7

Permian Basin(5)

817

319.3

Michigan

63

53.3

Total Primary Inventory

7,556

3,623.3

Identified Prospective Locations

Williston Basin

Williston Basin New Objectives

Gross

Net

Wells per Spacing Unit

Missouri Breaks Upper Three Forks

321

102.8

3 Upper TFK / 1280

Hidden Bench Lower Bakken Silt / Higher Density Pilot

556

161.9

4 BKN Silt; 4 Middle BKN per 1280

Cassandra Lower Three Forks

120

40.0

4 Lower TFK per 1280

Tarpon Lower Three Forks

40

15.0

3 Lower TFK per 1280

Total

1,037

319.7

Williston Basin Higher Density Locations

Pronghorn Sand Higher Density

453

167.3

3 Add'l Pronghorn Sand / 1280

Sanish Higher Density and Infill

191

175.9

3 Add'l Middle BKN / 1280

Total

644

343.2

Williston Basin Total Prospective Locations

1,681

662.9

Permian Basin

Big Tex Horizontal

424

217.0

6 Upper Wolfcamp / 640

Total Prospective Inventory

2,105

879.9

Total Potential Locations(6)

9,661

4,503.2

(1)

Tarpon primary development on 3 Middle BKN; 2 Upper TKS due to high natural fracturing. Excludes Upper TFK at Missouri Breaks.

(2)

Cross unit boundary wells at Sanish result in an average of 3.5 wells per spacing unit. Parshall was developed on 640-acre spacing units and there is no Three Forks.

(3)

Various fields in North Dakota and Montana, including Big Island, Starbuck, Big Stick and others.

(4)

Various fields in Colorado, Wyoming and Utah including Sulphur Creek, Fontenelle, Nitchie Gulch, Flat Rock and others.

(5)

Various fields in Texas and New Mexico including Jo-Mill, West Jo-Mill, Garza, Signal Peak and others.

(6)

Locations include both 3P reserves and Resource Potential.

2012 Capital Expenditures

Whiting's capital expenditures totaled $2,112 million in 2012 or approximately $212 million above its $1,900 million capital budget. The increase was due to a higher level of both operated and non-operated drilling activity. In total, we completed 192.9 net wells versus a projected 160 net wells.

2013 Capital Budget

Our 2013 capital budget is $2,200 million, which we expect to fund substantially with net cash provided by our operating activities, borrowings under our credit facility and certain oil and gas property divestitures. Whiting expects to invest $1,914 million of the 2013 capital budget in exploration and development activity, $108 million for land, and $178 million for facilities. Based on this level of capital spending, we forecast production of 33.8 MMBOE - 35.0 MMBOE for 2013, an increase of 12% - 16% over our 2012 production of 30.2 MMBOE.

Our 2013 capital budget is currently allocated among our major development areas as indicated in the table below:

2013

CAPEX

Gross

Net

(MM)

Wells

Wells

% of Total

Northern Rockies

$1,142

219

148

52%

EOR

240

NA(2)

NA(2)

11%

Central Rockie