Whiting Petroleum Corporation Announces Fourth Quarter And Full-Year 2013 Financial And Operating Results

Whiting Petroleum Corporation’s (NYSE: WLL) production in the fourth quarter of 2013 totaled 9.289 million barrels of oil equivalent (MMBOE), of which 87% were crude oil/natural gas liquids (NGLs). This fourth quarter 2013 production total equates to an average production rate of 100,965 barrels of oil equivalent per day (BOE/d), representing a 17% increase over the fourth quarter 2012 average rate of 86,055 BOE/d and a 9% increase over the third quarter 2013 average rate of 92,750 BOE/d.

Production in 2013 totaled a record 34.34 MMBOE or 94,090 BOE/d. This represents a 14% increase over total production of 30.21 MMBOE or 82,540 BOE/d in 2012. Excluding production associated with the Postle/Northeast Hardesty sale, our production in 2013 was up 21% over 2012. (1)

James J. Volker, Whiting’s Chairman and CEO, commented, “Our tenth year as a public company was a record year for Whiting Petroleum. With full-scale development underway at such fields as Pronghorn, Hidden Bench and Missouri Breaks, we generated excellent results in 2013. In the wake of this development, we posted records in production, proved reserves and discretionary cash flow. Entering our second decade as a public company, we are a leading operator in two of the hottest plays in North America, the Bakken in North Dakota and Montana and the Niobrara in northeastern Colorado. We believe these plays set the stage for another ten years of growth.”

Mr. Volker continued, “For the foreseeable future, our objective is to generate double-digit production growth while maintaining a healthy balance sheet. Our 2014 capital budget of $2.7 billion is expected to yield year-over-year production growth in the 17% to 19% range.”

We believe the following factors will lead to a strong year in 2014 for Whiting:

● A solid cash flow outlook and a strong balance sheet;

● Rapid development is underway at our Redtail Niobrara field with over 3,300 potential drilling locations; three rigs running now and a fourth scheduled for August;

● Full-scale implementation of our new completion design in the Williston Basin where early results indicate productivity increases of 30% to 100%;

● Additional higher density drilling across our Williston Basin acreage; and

● Optimization programs that should lead to efficient, low-cost drilling and completion operations.
(1)   34.34 MMBOE total production in 2013 less 1.49 MMBOE production attributable to the Postle/Northeast Hardesty assets equals 32.85 MMBOE. This equates to 90,000 BOE/d over 365 days. 30.21 MMBOE total production in 2012 less 2.97 MMBOE production attributable to the Postle/Northeast Hardesty assets equals 27.24 MMBOE. This equates to 74,426 BOE/d over 366 days. This translates into a 21% increase in 2013 adjusted production over 2012 adjusted production.
 

Operating and Financial Results

The following table summarizes the fourth quarter operating and financial results for 2013 and 2012:

Three Months Ended December 31,
    2013     2012   Change
Production (MBOE/d) 100.96 86.06 +17 %
Discretionary Cash Flow-MM$ (1) 457.6 381.7 +20 %
Realized Price ($/BOE) 75.18 71.09 + 6 %
Total Revenues-MM$ 720.5 577.1 +25 %
Net Income (Loss) Available to Common Shareholders-MM$ (2) (3) (59.3 ) 81.4 (173 )%
Per Basic Share $ (0.50 ) $ 0.69 (172 )%
Per Diluted Share $ (0.50 ) $ 0.69 (172 )%
Adjusted Net Income Available to Common Shareholders-MM$ (4) 104.8 102.7 +2 %
Per Basic Share $ 0.88 $ 0.87 +1 %
Per Diluted Share $ 0.88 $ 0.87 +1 %
(1)   A reconciliation of net cash provided by operating activities to discretionary cash flow is included later in this news release.
(2) For the three months ended December 31, 2013, net income (loss) available to common shareholders included $21.6 million of pre-tax, non-cash derivative gains or $0.11 per basic and diluted share after tax. For the three months ended December 31, 2012, net income available to common shareholders included $24.0 million of pre-tax, non-cash hedging gains or $0.13 per basic and diluted share after tax.
(3) For the three months ended December 31, 2013, this amount includes $267.1 million in non-cash pre-tax impairment charges for the partial write-down of primarily proved natural gas properties, mainly in the Rocky Mountain region and Michigan. For the three months ended December 31, 2012, this amount includes $46.9 million in non-cash pre-tax impairment charges for the partial write-down of proved properties, mainly in the Rocky Mountain region.
(4) A reconciliation of net income (loss) available to common shareholders to adjusted net income available to common shareholders is included later in this news release.
 
 

Twelve Months Ended December 31,
    2013     2012     Change
Production (MBOE/d) (1) 94.09 82.54 +14 %
Discretionary Cash Flow-MM$ (2) 1,750.0 1,387.5 +26 %
Realized Price ($/BOE) 76.76 69.85 +10 %
Total Revenues-MM$ 2,828.4 2,173.5 +30 %
Net Income Available to Common Shareholders-MM$ (3) (4) 365.5 413.1 (12)%
Per Basic Share $3.09 $3.51 (12)%
Per Diluted Share $3.06 $3.48 (12)%
Adjusted Net Income Available to Common Shareholders-MM$ (5) 490.9 402.2 +22 %
Per Basic Share $4.15 $3.42 +21 %
Per Diluted Share $4.11 $3.39 +21 %
(1)   Production attributable to the Postle field, which was sold on July 15, 2013, was 1,492.3 MBOE for the twelve months ended December 31, 2013 (7.6 MBOE/d over 196 days) and 2,968.0 MBOE or 8.1 MBOE/d over 366 days for the year ended December 31, 2012.
(2) A reconciliation of net cash provided by operating activities to discretionary cash flow is included later in this news release.
(3) For the year ended December 31, 2013, net income available to common shareholders included $20.8 million of pre-tax, non-cash derivative gains or $0.11 per basic and diluted share after tax. For the year ended December 31, 2012, net income available to common shareholders included $115.7 million of pre-tax, non-cash derivative gains or $0.62 per basic share and $0.61 per diluted share after tax.
(4) For the twelve months ended December 31, 2013, this amount includes $267.1 million in non-cash pre-tax impairment charges for the partial write-down of primarily proved natural gas properties, mainly in the Rocky Mountain region and Michigan. For the twelve months ended December 31, 2012, this amount includes $46.9 million in non-cash pre-tax impairment charges for the partial write-down of proved properties, mainly in the Rocky Mountain region.
(5) A reconciliation of net income available to common shareholders to adjusted net income available to common shareholders is included later in this news release.
 

Proved Reserves at December 31, 2013

As of December 31, 2013, Whiting had estimated proved reserves of 438.5 MMBOE, of which 58% were classified as proved developed. These estimated proved reserves had a pre-tax PV10% value of $8,994.0 million, using SEC NYMEX prices of $96.78 per barrel of oil and $3.67 per Mcf of gas. This represents an increase of 23% over the December 31, 2012 value of $7,283.9 million, which used SEC NYMEX prices of $94.71 per barrel of oil and $2.76 per Mcf of gas.

The following is a summary of Whiting’s changes in quantities of proved oil and gas reserves for the year ended December 31, 2013:

    Oil

(MBbl)
    NGLs

(MBbl)
    Natural

Gas

(MMcf)
    Total

(MBOE)
Balance – December 31, 2012 301,285 40,098 224,264 378,760
Extensions and discoveries 88,293 9,830 63,893 108,772
Sales of minerals in place (36,992 ) (4,777 ) (12,411 ) (43,838 )
Acquisitions 14,543 1,311 7,751 17,146
Production (27,035 ) (2,821 ) (26,917 ) (34,342 )
Revisions to previous estimates 7,327   1,228   20,934   12,044  
Balance – December 31, 2013 347,421   44,869   277,514   438,542  
 

Whiting’s proved reserves of 438.5 MMBOE represented a 16% increase over the 378.8 MMBOE of proved reserves at year-end 2012. Excluding from both 2012 and 2013 the reserves associated with the 2013 Postle/Northeast Hardesty sale, proved reserves increased 31%. (1)

The 59.8 MMBOE increase in proved reserves translates into 402% reserve replacement. (2) Excluding acquisitions of 17.1 MMBOE, it equates to 352% organic reserve replacement. (3) An estimated 108.8 MMBOE of proved reserves were added through exploration and development activities. This represents a 34% increase over the 81.5 MMBOE of proved reserves that were added from exploration and development in 2012.

Significant proved reserve additions during 2013 came from the Company’s Redtail Niobrara field in northeastern Colorado. Whiting booked an estimated 65.9 MMBOE of Niobrara proved reserves at Redtail during 2013.
(1)   378,760 MBOE total company proved reserves as of year-end 2012 less 45,065 MBOE proved reserves as of year-end 2012 sold in the Postle/Northeast Hardesty sale transaction equals 333,695 MBOE. 438,542 MBOE total company proved reserves as of year-end 2013 represents a 31% increase over the adjusted year-end 2012 total.
(2) 108,772 MBOE extensions and discoveries plus 17,146 MBOE acquisitions plus 12,044 MBOE revisions to previous estimates equals 137,962 MBOE reserves added; 137,962 MBOE divided by 34,342 MBOE production equals 402% reserve replacement.
(3) 108,772 MBOE extensions and discoveries plus 12,044 MBOE revisions to previous estimates equals 120,816 MBOE reserves added; 120,816 MBOE divided by 34,342 MBOE production equals 352% organic reserve replacement.
 

Probable and Possible Reserves at December 31, 2013

At year-end 2013, Whiting’s probable reserves were estimated to be 176.2 MMBOE and our possible reserves were estimated to be 189.1 MMBOE, for a total of 365.3 MMBOE. This represents an increase of 28% over the 286.3 MMBOE in 2012. The year-end 2013 estimated pre-tax PV10% for our probable and possible reserves was $3,619.3 million, an increase of 38% over the $2,621.4 million in 2012.

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)

Oil(MMBbl)
   

NGLS(MMBbl)
   

NaturalGas(Bcf)
   

Total(MMBOE)
   

%Oil
   

Pre-TaxPV10%Value(In MM)
   

% ofTotal
 
Proved 347.4 44.9 277.5 438.5 79% $8,994(2) 71%
Probable 109.3 22.3 267.6 176.2 62% $1,863(3) 15%
Possible 137.2 24.6 163.8 189.1 73% $1,756(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, 2013, pursuant to current SEC and FASB guidelines. The NYMEX prices used were $96.78/Bbl and $3.67/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, 2013, our discounted future income taxes were $2,400.1 million and our standardized measure of after-tax discounted future net cash flows was $6,593.9 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 does 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, as of year-end 2013 Whiting projects it has a total of 14,230 gross (7,479 net) potential future drilling locations, increases of 47% and 66% over our 2012 gross and net totals, respectively. Of this total, 10,643 gross (4,564 net) locations are identified as primary locations, which have been validated by drilling results. This represents a 41% increase in gross primary total locations and a 26% increase in net primary total locations relative to year-end 2012.

In our core Northern Rockies area, our gross and net estimated primary well counts were 4,331 and 1,665, increases of 39% and 33%, respectively, over year-end 2012. In our core Central Rockies area, our gross and net estimated primary well counts were 5,226 and 2,374, increases of 55% and 27%, respectively, over year-end 2012.

The following table summarizes our potential gross and net drilling locations by area:
YEAR-END 2013 IDENTIFIED PRIMARY LOCATIONS
      Gross Wells     Net Wells
NORTHERN ROCKIES            
Western Williston (Cassandra; Hidden Bench; Tarpon; Missouri Breaks)     2,065     661
Southern Williston (Lewis & Clark; Pronghorn) 1,286 492
Sanish (Sanish; Parshall) 387 186
Other(1)     593     326
NORTHERN ROCKIES TOTAL     4,331     1,665
CENTRAL ROCKIES
Redtail Niobrara 3,310 1,654
Other(2)     1,916     720
CENTRAL ROCKIES TOTAL     5,226     2,374
PERMIAN(3)     962     422
OTHER(4)     124     103
PRIMARY TOTAL     10,643     4,564
 
YEAR-END 2013 IDENTIFIED PROSPECTIVE LOCATIONS
      Gross Wells     Net Wells
ROCKIES EXPLORATION(5)     2,457     1,971
OTHER EXPLORATION(6)     1,130     944
PROSPECTIVE TOTAL     3,587     2,915
             
GRAND TOTAL POTENTIAL LOCATIONS(7)     14,230     7,479

(1)
 

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

(2)

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

(3)

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

(4)

Other primarily includes oil and gas properties in Arkansas, Louisiana, Michigan, Oklahoma and Texas.

(5)

Includes Utah.

(6)

Includes Michigan and Louisiana.

(7)

Locations include both 3P reserves and resource potential. Please refer to the “Disclosure Regarding Reserves and

Resources” later in this news release for information on probable and possible reserves and resource potential.
 

2013 Capital Expenditures

Whiting’s capital expenditures totaled $2,675 million in 2013. In total, we completed 229.2 net wells versus a projected 209.0 net wells.

2014 Capital Budget

Our 2014 capital budget is $2,700 million, which we expect to fund substantially with net cash provided by our operating activities, cash on hand and nominal borrowings under our credit facility. Whiting expects to invest $2,433 million of the 2014 capital budget in exploration and development activity, $116 million for land, and $151 million for facilities. Based on this level of capital spending, we forecast production of 40.20 MMBOE – 40.80 MMBOE for 2014, an increase of 17% - 19% over our 2013 production of 34.34 MMBOE.

Our 2014 capital budget is currently allocated among our major development areas as indicated in the table below:
   

2014CAPEX(MM)
   

GrossWells
   

NetWells
    % of Total
Northern Rockies $ 1,101 199 137.2 41%
Central Rockies 575 120 104.9 21%
EOR Project 203 NA(3) NA(3) 7%
Libby Ranch CO2 Develop. (1) 56 2%
Other Exploration Drilling 44 9 7.3 2%
Non-Operated 232 8%
Land 116 4%
Facilities 151 6%
Exploration Expense (2) 72 3%
Well Work, Misc. Costs, Other 150     6%
Total Budget $ 2,700 328 249.4 100%
(1)   For development of CO2 prospect at Bravo Dome in northeastern New Mexico.
(2) Comprised primarily of exploration salaries, lease delay rentals and seismic activities.
(3) This multi-year CO2 project involves many re-entries, workovers and conversions. Therefore, it is budgeted on a project basis not a well basis.
 

Operations Update

Core Development Areas

Bakken and Three Forks Development

In 2013, we experienced significant productivity increases as we moved into development drilling mode in new fields in the Southern and Western Williston Basin. We are using our new completion design with cemented liners and plug and perf technology to enhance productivity throughout the Williston Basin. Initial results from our higher density drilling programs across our Bakken acreage base have been positive.

Western Williston Basin

The Western Williston Basin includes our Hidden Bench, Tarpon, Missouri Breaks and Cassandra fields. These areas represent a total of 204,198 gross (121,909 net) acres. Production from the Western Williston Basin averaged 17,790 BOE/d in the fourth quarter of 2013, which represented a 30% increase over the 13,710 BOE/d average rate in the third quarter of 2013.

Hidden Bench Field. We experienced favorable results from our new completion design and tested higher density drilling at the Mork Trust Unit, located in McKenzie County, North Dakota. The Mork Trust 21-17-2H and the Mork Trust 21-17-3H were completed at an average rate of 2,643 BOE/d on November 30, 2013 from the Bakken. These wells were infill wells testing an eight well per spacing unit pattern in the Middle Bakken formation. Both wells, which were completed using cemented liners and plug and perf technology, were fracture stimulated in 30 stages with four entry points per stage. Three offsetting wells were completed at an average rate of 1,727 BOE/d on November 30, November 30 and December 1, 2013, respectively. These wells, which were completed with uncemented liners and sliding sleeve technology, were fraced in 30 stages with one entry point per stage. The wells completed using our new completion design had average initial production rates that were 53% better than the wells completed with our previous completion design.

Missouri Breaks Field. We hold 98,601 gross (64,277 net) acres in the Missouri Breaks field, located in Richland County, Montana and McKenzie County, North Dakota. We have experienced improved results with our new completion design in the Missouri Breaks area. We have completed nine wells using our new cemented liner completion method that have more than 90 days of production history. For these wells, 30-day, 60-day and 90-day average rates have been 75%, 57% and 52% greater than the average rates for the 31 wells completed with our old sliding sleeve technology in the Missouri Breaks area.

Southern Williston Basin

The Southern Williston Basin encompasses our Pronghorn and Lewis & Clark fields, which encompass a total of 392,483 gross (263,376 net) acres. Fourth quarter 2013 production from this region averaged 15,065 BOE/d. This daily rate represents a 6% increase over the 14,160 BOE/d rate in the third quarter of 2013.

Pronghorn Field. We continue to generate favorable results from our new completion technique at our Pronghorn field, which is located primarily in Stark and Billings counties, North Dakota. The Obrigewitch 21-29PH produced 50.8 MBOE during its first 60 days of production ending on November 11, 2013. The well, which was completed in the Pronghorn Sand using a cemented liner and plug and perf technology, was fraced in 40 stages with three entry points per stage. An offsetting well, the Obrigewitch 41-29PH, produced 40.0 MBOE during its first 60 days of production ending on November 8, 2013. This well, which was completed with an uncemented liner and sliding sleeves, was fracture stimulated in 30 stages with one entry point per stage.

Sanish Field Area

Whiting’s net production from the Sanish field area, which includes our 21% working interest in the Parshall field, averaged 40,370 BOE/d in the fourth quarter of 2013, an increase of 10% over the third quarter 2013 average of 36,840 BOE/d. Whiting continues to generate strong results from the field. Highlighting recent results were the completion of two higher density wells. These wells were infill wells testing an eight well per spacing unit pattern in the Middle Bakken formation. The Uran 43-17H was completed in the Middle Bakken on January 17, 2014 flowing 1,451 BOE/d, while the Uran 43-17-2H was completed in the Middle Bakken on January 19, 2014 flowing 1,252 BOE/d. These rates compare favorably with the original wells that tested 955 BOE/d and 623 BOE/d on May 27, 2012 and October 25, 2011, respectively. Both infill wells were completed with our new completion design that consisted of 40 stages and three entry points per stage versus the original two wells that were completed with 25 to 30 stages and only one entry point per stage.

Other Development Areas

Denver Basin: Redtail Niobrara Field. We hold a total of 169,677 gross (122,278 net) acres in our Redtail field, located in the Denver Julesberg Basin in Weld County, Colorado, where we have the potential to drill 3,310 gross (1,653.8 net) wells based on a 16-well per drilling spacing unit pattern. Whiting estimates the total resource potential for Redtail to be 492.4 MMBOE net to Whiting. As of February 1, 2014, net production from the Redtail field was running at approximately 5,100 BOE/d, up 58% from its fourth quarter 2013 average of 3,230 BOE/d.

We recently completed drilling operations on two four-well pads. Our 27L pad is targeting the Niobrara “B” zone while our 27K pad is testing both the Niobrara “B” and “A” zones. Both pads are located in our Razor area and are testing a 16-well per 960-acre drilling spacing unit pattern. Initial results from both pads are encouraging with early results from both “B” and “A” zone wells tracking our typical 400 MBOE type curve.

In the second quarter of 2014, we plan to drill a 960-acre spacing unit on a 32-well pattern. If successful, our potential drilling locations would increase to more than 6,600 gross wells. Our 30F pad, located in our Horsetail area, will test the Niobrara “A”, “B” and “C” zones. Together these three zones have an estimated 70 MMBOE of original oil in place per 960-acre spacing unit.

Typifying the production performance of a Redtail Niobrara well is the Horsetail 18-0713H. This well was completed on August 23, 2013. The Horsetail well posted a 30-day average rate of 452 BOE/d, a 60-day average rate of 458 BOE/d and a 90-day average rate of 531 BOE/d. This well’s estimated ultimate recovery is calculated to be approximately 570 MBOE gross. It was drilled on a 960-acre spacing unit and utilized a large fracture stimulation and plug and perf completion technology.

EOR Project

North Ward Estes Field. Net production from our North Ward Estes field averaged 9,755 BOE/d in the fourth quarter of 2013, up 2% over the third quarter 2013 rate of 9,610 BOE/d. One of the largest phases at North Ward Estes (Phase 5) is pressuring up with CO 2, and we are beginning to see a production response. Whiting is currently injecting approximately 397 MMcf/d of CO 2 into the field, of which about 68% is recycled gas.

Midstream Assets

Robinson Lake Gas Plant. As of February 1, 2013, our gas plant at Robinson Lake was processing 85 MMcf/d of gas (gross). We added compression in 2013 that brought the plant’s inlet capacity to 90 MMcf/d, and we have the ability to increase to 110 MMcf/d in the future. Whiting owns a 50% interest in the plant.

Belfield Gas Processing Plant. The Belfield gas plant was processing 17 MMcf/d of gas (gross) as of February 1, 2013. Currently, there is inlet compression in place to process 35 MMcf/d. Whiting owns 50% of the Belfield plant.

Redtail Gas Processing Plant. We expect the Redtail gas plant to begin processing gas in early 2014. Initial inlet capacity will be 15 MMcf/d of gas. We expect this capacity to expand to 60 MMcf/d by the first quarter of 2015.

Operated Drilling Rig Count

As of February 1, 2014, 23 operated drilling rigs were active on our properties. The breakdown of our operated rigs as of February 1, 2014 was as follows:
     

Region
   

Northern Rockies
17
Central Rockies 3
Other 1
North Ward Estes EOR Project  

2
 
Total   23  
 

Other Financial and Operating Results

The following table summarizes the Company’s net production and commodity price realizations for the quarters ended December 31, 2013 and 2012:
    Three Months Ended    
December 31,

Production
2013     2012 Change
Oil (MMBbl) 7.35 6.12 20 %
NGLs (MMBbl) 0.75 0.71 6 %
Natural gas (Bcf) 7.14 6.52 9 %
Total equivalent (MMBOE) 9.29 7.92 17 %
 

Average sales price
Oil (per Bbl):
Price received $ 86.77 $ 83.50 4 %
Effect of crude oil hedging   (0.64 )(1)   (0.41 )
Realized price $ 86.13   $ 83.09   4 %
NYMEX oil (per Bbl) $ 97.50   $ 88.20   11 %
 
NGLs (per Bbl):
Realized price $ 44.89   $ 43.10   4 %
 
Natural gas (per Mcf):
Price received $ 4.44 $ 3.60 23 %
Effect of natural gas hedging   -     0.05  
Realized price $ 4.44   $ 3.65   22 %
NYMEX natural gas (per Mcf) $ 3.60   $ 3.41   6 %
(1)   Whiting paid $4.7 million in pre-tax cash settlements on its crude oil hedges during the fourth quarter of 2013. A summary of Whiting’s outstanding hedges is included later in this news release.
 

Fourth Quarter and Full-Year 2013 Costs and Margins

A summary of production, cash revenues and cash costs on a per BOE basis is as follows:
    Per BOE, Except Production
Three Months Ended     Twelve Months Ended
December 31, December 31,
2013     2012 2013     2012
Production (MMBOE) 9.29 7.92 34.34 30.21
 
Sales price, net of hedging $ 75.18 $ 71.09 $ 76.76 $ 69.85
Lease operating expense 12.51 12.41 12.53 12.46
Production tax 6.37 5.40 6.56 5.68
General & administrative 3.18 3.03 4.02 3.59
Exploration 2.49 3.22 2.76 1.96
Cash interest expense 4.17 2.23 2.93 2.17
Cash income tax expense (benefit)   (0.45 )   (0.17 )   0.03   (0.02 )
$ 46.91   $ 44.97   $ 47.93 $ 44.01  
 

Fourth Quarter and Full-Year 2013 Drilling and Expenditures Summary

The table below summarizes Whiting’s operated and non-operated drilling activity and capital expenditures for the three and twelve months ended December 31, 2013:
    Gross/Net Wells Completed    
        Total New     % Success CAPEX
Producing Non-Producing Drilling Rate (in MM)
Q4 13 105 / 62.8 3 / 2.7 108 / 65.5 97% / 96% $ 746.2 (1)
12M 13 419 / 220.7 9 / 8.5 428 / 229.2 98% / 96% $ 2,675.2(2)
(1)   Includes $42 million for land and $42 million for facilities.
(2) Includes $202 million for land and $168 million for facilities.
 

Outlook for First Quarter and Full-Year 2014

The following table provides guidance for the first quarter and full-year 2014 based on current forecasts, including Whiting’s full-year 2014 capital budget of $2,700.0 million.
    Guidance
First Quarter     Full-Year
2014 2014
Production (MMBOE) (1) 8.90 - 9.10 40.20 - 40.80
Lease operating expense per BOE $ 12.75 - $ 13.25 $ 12.30 - $ 12.70
General and admin. expense per BOE $ 3.30 - $ 3.70 $ 3.20 - $ 3.50
Interest expense per BOE $ 4.60 - $ 5.00 $ 3.80 - $ 4.20
Depr., depletion and amort. per BOE $ 25.75 - $ 26.75 $ 25.50 - $ 26.10
Prod. taxes (% of production revenue) 8.4% - 8.6% 8.5% - 8.7%
Oil price differentials to NYMEX per Bbl(2) ($ 9.00) - ($11.00) ($ 8.00) - ($10.00)
Gas price premium to NYMEX per Mcf(3) $ 0.30 - $ 0.70 $ 0.30 - $ 0.70
(1)   First quarter guidance reflects estimated weather related impacts, which slows completion operations on new wells and existing production operations.
(2) Does not include the effect of NGLs.
(3) Includes the effect of Whiting’s fixed-price gas contracts. Please refer to fixed-price gas contracts later in this news release.
 

Commodity Derivative Contracts

The following summarizes Whiting’s crude oil hedges as of February 6, 2014:
            Weighted Average     As a Percentage of
Derivative Hedge Contracted Volume NYMEX Price December 2013
Instrument Period (Bbls per Month) (per Bbl) Oil Production
 
Three-way collars(1) 2014
January 1,200,000 $ 71.00 - $ 85.00 - $ 103.56 49.0%
February 1,280,000 $ 70.94 - $ 85.00 - $ 103.34 52.3%
March 1,280,000 $ 70.94 - $ 85.00 - $ 103.34 52.3%
Q2 1,280,000 $ 70.94 - $ 85.00 - $ 103.34 52.3%
Q3 1,280,000 $ 70.94 - $ 85.00 - $ 103.34 52.3%
Q4 1,280,000 $ 70.94 - $ 85.00 - $ 103.34 52.3%

Collars

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.
 

The following summarizes Whiting’s fixed-price natural gas contracts as of February 6, 2014:
        Weighted Average     As a Percentage of
Hedge Contracted Volume Contracted Price December 2013
Period (MMBtu per Month) (per MMBtu) Gas Production
 
2014
Q1 330,000 $5.49 13.6%
Q2 333,667 $5.49 13.8%
Q3 337,333 $5.49 14.0%
Q4 337,333 $5.49 14.0%
 

Whiting also has the following fixed-differential crude oil sales contracts in place as of February 6, 2014:
      Differential   As a Percentage of
Contracted Volume from NYMEX December 2013
Commodity Period (Bbls per Month) (per Bbl) Oil Production
 
Crude Oil 2015 760,417 $4.75 31.1%
Crude Oil 2016 915,000 $4.75 37.4%
Crude Oil 2017 1,064,583 $4.75 43.5%
Crude Oil 2018 1,216,667 $4.75 49.7%
Crude Oil 2019 1,368,750 $4.75 55.9%
 
       

Selected Operating and Financial Statistics
 
Three Months Ended

December 31,
Twelve Months Ended

December 31,
2013     2012 2013     2012
Selected operating statistics:
Production
Oil, MBbl 7,348 6,119 27,035 23,139
NGLs, MBbl 751 711 2,821 2,766
Natural gas, MMcf 7,138 6,522 26,915 25,827
Oil equivalents, MBOE 9,289 7,917 34,342 30,209
Average prices
Oil per Bbl (excludes hedging) $ 86.77 $ 83.50 $ 90.39 $ 83.86
NGLs per Bbl $ 44.89 $ 43.10 $ 40.41 $ 39.36
Natural gas per Mcf (excludes hedging) $ 4.44 $ 3.60 $ 4.04 $ 3.42
Per BOE data
Sales price (including hedging) $ 75.18 $ 71.09 $ 76.76 $ 69.85
Lease operating $ 12.51 $ 12.41 $ 12.53 $ 12.46
Production taxes $ 6.37 $ 5.40 $ 6.56 $ 5.68
Depreciation, depletion and amortization $ 26.63 $ 23.80 $ 25.96 $ 22.67
General and administrative $ 3.18 $ 3.03 $ 4.02((1 )) $ 3.59((2 ))
Selected financial data:

(In thousands, except per share data)
Total revenues and other income $ 720,460 $ 577,090 $ 2,828,385 $ 2,173,452
Total costs and expenses $ 799,611 $ 447,033 $ 2,256,514 $ 1,511,441
Net income (loss) available to common shareholders $ (59,265 ) $ 81,434 $ 365,517 $ 413,112
Earnings (loss) per common share, basic $ (0.50 ) $ 0.69 $ 3.09 $ 3.51
Earnings (loss) per common share, diluted $ (0.50 ) $ 0.69 $ 3.06 $ 3.48

Average shares outstanding, basic
118,656 117,631 118,260 117,601
Average shares outstanding, diluted 118,656 118,992 119,588 119,028
Net cash provided by operating activities $ 490,618 $ 383,270 $ 1,744,745 $ 1,401,215
Net cash used in investing activities $ (560,744 ) $ (559,160 ) $ (1,902,499 ) $ (1,780,318 )
Net cash provided by (used in) financing activities $ (255,993 ) $ 194,615 $ 812,414 $ 408,092
(1)   For the twelve months ended December 31, 2013, the cost includes the effect of a charge under our Production Participation Plan related to the sale of the Postle Properties of $0.63 per BOE.
(2) For the twelve months ended December 21, 2012, the cost includes the effect of a charge under our Production Participation Plan related to the Whiting USA Trust II divestiture of $0.28 per BOE.
 

SELECTED FINANCIAL DATA

For further information and discussion on the selected financial data below, please refer to Whiting Petroleum Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013, to be filed with the Securities and Exchange Commission.
   

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands)
 
December 31
2013   2012
ASSETS
 
Current assets:
Cash and cash equivalents $ 699,460 $ 44,800
Accounts receivable trade, net 341,177 318,265
Prepaid expenses and other   28,981     21,347  
Total current assets   1,069,618     384,412  

Property and equipment:
Oil and gas properties, successful efforts method 10,065,150 9,211,998
Other property and equipment   206,385     141,738  
Total property and equipment 10,271,535 9,353,736
Less accumulated depreciation, depletion and amortization   (2,676,490 )   (2,590,203 )
Total property and equipment, net 7,595,045 6,763,533

Debt issuance costs
48,530 28,748

Other long-term assets
  120,277     95,726  

TOTAL ASSETS
$ 8,833,470   $ 7,272,419  
 
   

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)
 
December 31,
  2013       2012  
LIABILITIES AND EQUITY
 
Current liabilities:
Accounts payable trade 107,692 131,370
Accrued capital expenditures 158,739 110,663
Accrued liabilities and other 214,109 170,207
Revenues and royalties payable 198,558 149,692
Taxes payable 50,052 33,283
Accrued interest 44,405 10,415
Derivative liabilities 3,482 21,955
Deferred income taxes   648   9,394  
Total current liabilities 777,685 636,979
Long-term debt 2,653,834 1,800,000
Deferred income taxes 1,278,030 1,063,681
Derivative liabilities - 1,678
Production Participation Plan liability 87,503 94,483
Asset retirement obligations 116,442 86,179
Deferred gain on sale 79,065 110,395
Other long-term liabilities   4,212   25,852  
Total liabilities   4,996,771   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 December 31,  2013 and 172,391 shares issued and outstanding as of  December 31, 2012
- -

Common stock, $0.001 par value, 300,000,000 shares  authorized; 120,101,555 issued and 118,657,245  outstanding as of December 31, 2013, 118,582,477  issued and 117,631,451 outstanding as of December 31,  2012
120 119
Additional paid-in capital 1,583,542 1,566,717
Accumulated other comprehensive loss - (1,236 )
Retained earnings   2,244,905   1,879,388  
Total Whiting shareholders’ equity 3,828,567 3,444,988
Noncontrolling interest   8,132   8,184  
Total equity   3,836,699   3,453,172  

TOTAL LIABILITIES AND EQUITY
$ 8,833,470 $ 7,272,419  
 
       

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except per share data)
 
Three Months Ended

December 31,
Twelve Months Ended

December 31,
2013     2012 2013     2012
REVENUES AND OTHER INCOME:
Oil, NGL and natural gas sales $ 703,024 $ 565,066 $ 2,666,549 $ 2,137,714
Gain (loss) on hedging activities (645 ) 54 (1,958 ) 2,338
Amortization of deferred gain on sale 8,057 8,177 31,737 29,458
Gain on sale of properties 8,942 3,686 128,648 3,423
Interest income and other   1,082     107     3,409     519  
Total revenues and other income   720,460     577,090     2,828,385     2,173,452  
COSTS AND EXPENSES:
Lease operating 116,157 98,271 430,221 376,424
Production taxes 59,175 42,732 225,403 171,625
Depreciation, depletion and amortization 247,381 188,428 891,516 684,724
Exploration and impairment 325,445 87,610 453,210 166,972
General and administrative 29,528 23,962 137,994 108,573
Interest expense 43,357 20,115 112,936 75,210
Loss on early extinguishment of debt 4,412 - 4,412 -
Change in Production Participation Plan liability (8,312 ) 7,625 (6,980 ) 13,824
Commodity derivative (gain) loss, net   (17,532 )   (21,710 )   7,802     (85,911 )
Total costs and expenses   799,611     447,033     2,256,514     1,511,441  
INCOME (LOSS) BEFORE INCOME TAXES (79,151 ) 130,057 571,871 662,011
INCOME TAX EXPENSE (BENEFIT):
Current (4,145 ) (1,345 ) 986 (669 )
Deferred   (15,730 )   49,713     204,882     248,581  
Total income tax expense (benefit)   (19,875 )   48,368     205,868     247,912  
NET INCOME (LOSS) (59,276 ) 81,689 366,003 414,099
Net loss attributable to noncontrolling interest   11     14     52     90  
NET INCOME (LOSS) AVAILABLE TO SHAREHOLDERS (59,265 ) 81,703 366,055 414,189
Preferred stock dividends   -     (269 )   (538 )   (1,077 )
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS $ (59,265 ) $ 81,434   $ 365,517   $ 413,112  
EARNINGS (LOSS) PER COMMON SHARE:
Basic $ (0.50 ) $ 0.69   $ 3.09   $ 3.51  
Diluted $ (0.50 ) $ 0.69   $ 3.06   $ 3.48  
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic   118,656     117,631     118,260     117,601  
Diluted   118,656     118,992     119,588     119,028  
 
       

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 Twelve Months Ended
December 31, December 31,
  2013         2012     2013         2012  

Net income (loss) available to common  shareholders
$ (59,265 ) $ 81,434 $ 365,517 $ 413,112
Adjustments net of tax:
Amortization of deferred gain on sale (5,088 ) (5,136 ) (20,042 ) (18,427 )
Gain on sale of properties (5,647 ) (2,315 ) (81,241 ) (2,141 )
Impairment expense 190,918 38,996 226,365 67,465
Early extinguishment of debt 2,786 - 2,786 -

Charge under Production Participation Plan  related to sale of Postle properties
- - 15,114 -

Charge under Production Participation Plan  related to Trust II offering
- - - 5,930
Change in Production Participation Plan liability (5,249 ) 4,789 (4,408 ) 8,647

Total measure of derivative (gain) loss reported  under U.S. GAAP
(10,664 ) (13,460 ) 6,164 (54,312 )

Total net cash settlements paid on commodity  derivatives during the period
  (2,957 )   (1,596 )   (19,318 )   (18,081 )
Adjusted net income (1) $ 104,834   $ 102,712   $ 490,937   $ 402,193  

Adjusted net income available to common  shareholders per share, basic
$ 0.88   $ 0.87   $ 4.15   $ 3.42  

Adjusted net income available to common  shareholders per share, diluted
$ 0.88   $ 0.87   $ 4.11   $ 3.39  
(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.
 
       

WHITING PETROLEUM CORPORATION

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

(In thousands)
 
Three Months Ended Twelve Months Ended
December 31, December 31,
  2013         2012     2013         2012  
Net cash provided by operating activities $ 490,618 $ 383,270 $ 1,744,745 $ 1,401,215
Exploration 23,120 25,525 94,755 59,117
Exploratory dry hole costs (7,575 ) (16,288 ) (28,725 ) (18,428 )
Changes in working capital (48,610 ) (10,513 ) (60,224 ) (53,318 )
Preferred stock dividends paid   -     (269 )   (538 )   (1,077 )
Discretionary cash flow (1) $ 457,553   $ 381,725   $ 1,750,013   $ 1,387,509  
(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.
 

Conference Call

The Company’s management will host a conference call with investors, analysts and other interested parties on Thursday, February 27, 2014 at 11:00 a.m. EST (10:00 a.m. CST, 9:00 a.m. MST) to discuss Whiting’s fourth quarter and full-year 2013 financial and operating results. Please call (866) 515-2907 (U.S./Canada) or (617) 399-5121 (International) to be connected to the call and enter the pass code 67616842. 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. (EST) on February 27, 2014.

A telephonic replay will be available beginning approximately two hours after the call on Thursday, February 27, 2014 and continuing through Thursday, March 13, 2014. You may access this replay at (888) 286-8010 (U.S./Canada) or (617) 801-6888 (International) and entering the pass code 41371401. 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 and Permian Basin 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 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 CO 2 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; impacts to financial statements as a result of impairment write downs; 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2013. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release.

Disclosure Regarding Reserves and Resources

Whiting uses in this news release the terms proved, probable and possible reserves. Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.

Whiting uses in this news release the term “total resources,” which consists of contingent and prospective resources, which SEC rules prohibit in filings of U.S. registrants. Contingent resources are resources that are potentially recoverable but not yet considered mature enough for commercial development due to technological or business hurdles. For contingent resources to move into the reserves category, the key conditions, or contingencies, that prevented commercial development must be clarified and removed. Prospective resources are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added. For prospective resources to become classified as contingent resources, hydrocarbons must be discovered, the accumulations must be further evaluated and an estimate of quantities that would be recoverable under appropriate development projects prepared. Estimates of resources are by nature more uncertain than reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company.

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