Form S-1
Table of Contents

Registration No. 333-          

 


UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM S-1

REGISTRATION STATEMENT

Under

THE SECURITIES ACT OF 1933

 


 

Whiting Petroleum Holdings, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware   1311   20-0098515
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification No.)

 

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300

(303) 837-1661

(Address, including zip code, and telephone number, including area code,

of registrant’s principal executive offices)

 


 

James J. Volker

President and Chief Executive Officer

Whiting Petroleum Holdings, Inc.

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300

(303) 837-1661

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 


 

with copies to:

 

Benjamin F. Garmer, III, Esq.
Jay O. Rothman, Esq.
Foley & Lardner
777 East Wisconsin Avenue
Milwaukee, Wisconsin 53202
(414) 271-2400
  Kendor P. Jones, Esq.
Welborn Sullivan Meck & Tooley, P.C. 821 17th Street, Suite 500
Denver, Colorado 80202
(303) 830-2500
 

David P. Oelman, Esq.
Vinson & Elkins L.L.P.

2300 First City Tower

1001 Fannin

Houston, Texas 77002

(713) 758-2222

 


 

Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    ¨

 

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨ 

 

If this Form is a post-effective amendment filed pursuant to Rule 462(c) of the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

 

If this Form is a post-effective amendment filed pursuant to Rule 462(d) of the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

 

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.    ¨

 


 

CALCULATION OF REGISTRATION FEE


Title of Each Class of
Securities to be Registered
   Proposed Maximum
Aggregate Offering Price (1)
   Amount of
 Registration Fee

Common Stock, $0.001 par value

   $ 130,000,000.00    $ 10,517.00

(1)   Estimated in accordance with Rule 457(a) under the Securities Act of 1933 solely for purposes of calculating the registration fee.

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 



Table of Contents

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

Subject to Completion

Preliminary Prospectus Dated July 25, 2003

 

P R O S P E C T U S

 

Shares

 

LOGO

 

Whiting Petroleum Holdings, Inc.

Common Stock

 


 

This is our initial public offering. Alliant Energy Resources, Inc., the selling stockholder and a wholly-owned subsidiary of Alliant Energy Corporation, is selling all of the shares.

 

We expect the public offering price to be between $             and $             per share. Currently, no public market exists for the shares. We intend to apply to list the shares on the New York Stock Exchange under the symbol “WLL.”

 

Investing in our common stock involves risks that are described in the “Risk Factors” section beginning on page 11 of this prospectus.

 


 

     Per Share

   Total

Public offering price

   $      $  

Underwriting discount

   $      $  

Proceeds, before expenses, to selling stockholder

   $      $  

 

The underwriters may also purchase up to an additional              shares from the selling stockholder at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover overallotments.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

The shares will be ready for delivery on or about             , 2003.

 


 

Merrill Lynch & Co.                                A.G. Edwards & Sons, Inc.

 


 

The date of this prospectus is             , 2003.


Table of Contents

LOGO


Table of Contents

TABLE OF CONTENTS

 

     Page

Prospectus Summary

   1

Risk Factors

   11

Special Note Regarding Forward-Looking Statements

   21

Use of Proceeds

   22

Dividend Policy

   22

Capitalization

   23

Selected Historical Financial Information

   24

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   26

Business and Properties

   39

Management

   65

Stock Ownership of Management and Selling Stockholder

   70

Relationship with Alliant Energy Corporation

   72

Description of Capital Stock

   75

Shares Eligible for Future Sale

   77

Underwriting

   79

Legal Matters

   83

Experts

   83

Where You Can Find More Information

   83

Index to Financial Statements

   F-1

Glossary of Oil and Natural Gas Terms

   A-1

Report of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers

   B-1

Report of R.A. Lenser & Associates, Inc., Independent Petroleum Engineers

   C-1

Report of Ryder Scott Company, L.P., Independent Petroleum Engineers

   D-1

 


 

Unless the context otherwise requires, references in this prospectus to “Whiting,” “we,” “us,” “our” or “ours” refer to Whiting Petroleum Holdings, Inc., together with its only operating subsidiary, Whiting Petroleum Corporation. When the context requires, we refer to these entities separately. Whiting Petroleum Holdings, Inc. was only recently formed in connection with this offering and has no financial or operating history of its own. References in this prospectus to “Resources” or the “selling stockholder” refer to Alliant Energy Resources, Inc., our parent company and a wholly-owned subsidiary of Alliant Energy Corporation. References in this prospectus to “Alliant Energy” refer to Alliant Energy Corporation.

 

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted.

 

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PROSPECTUS SUMMARY

 

This summary highlights information contained elsewhere in this prospectus. You should read this entire prospectus carefully, including “Risk Factors” and our financial statements and the notes to those financial statements included elsewhere in this prospectus. We have provided definitions for the oil and natural gas terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” included in this prospectus. Unless otherwise indicated, the information contained in this prospectus assumes that the underwriters do not exercise their overallotment option.

 

About Our Company

 

We are engaged in oil and natural gas exploitation, acquisition and exploration activities primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan and Mid-Continent regions of the United States. Our focus is on maintaining a balanced portfolio of lower risk, long-lived oil and natural gas properties that provide stable cash flows to fund projects which we believe will generate an attractive rate of return.

 

Since our inception in 1980, we have built a strong asset base and achieved steady growth through both property acquisitions and exploitation activities. From January 1, 2000 through April 1, 2003, we increased our proved reserves from 194.1 Bcfe to 439.2 Bcfe, an average annual growth rate of 38.8%, at an average all-in finding cost of $1.00 per Mcfe. We spent approximately $165.4 million on capital projects during 2002, including $23.1 million for the drilling of 33 gross wells (24 successful completions and nine uneconomic wells) and $140.7 million for the acquisition of 157.4 Bcfe of proved reserves (estimated as of the date of acquisition). We expect to further develop these properties through drilling and enhanced recovery methods. We have budgeted approximately $98.0 million for capital expenditures in 2003, including $41.0 million for drilling and exploitation opportunities. We believe that our exploitation and acquisition expertise and our exploration inventory, together with our operating experience and efficient cost structure, provide us with substantial growth potential.

 

As of April 1, 2003, our estimated proved reserves had a pre-tax PV10% value of approximately $718.3 million, approximately 86.5% of which came from properties located in three states: Texas, North Dakota and Michigan. Approximately 61.2% of our proved reserves are classified as proved developed producing, or “PDP.” Approximately 8.1% of our proved reserves are classified as proved developed non-producing, or “PDNP,” and approximately 30.7% are classified as proved undeveloped, or “PUD.”

 

We have a balanced portfolio of oil and natural gas reserves, with approximately 51.5% of our proved reserves consisting of natural gas and approximately 48.5% consisting of oil. The following table summarizes our total net proved reserves and pre-tax PV10% value within our four core areas as of April 1, 2003, as well as our June 2003 average daily production.

 

     Proved Reserves

       

June 2003

Average Daily Production


 

Core Area


  

Oil

(MMbbl)


  

Natural

Gas

(Bcf)


  

Total

(Bcfe)


  

Pre-Tax PV
10% Value

(In thousands)


   MMcfe

   % Natural
Gas


 

Gulf Coast/Permian Basin

   5.0    87.7    117.9    $ 225,480    35.5    80 %

Rocky Mountains

   27.4    15.6    180.0      249,010    34.2    11 %

Michigan

   1.2    105.6    113.1      203,219    22.1    94 %

Mid-Continent

   1.3    13.8    21.8      30,452    6.4    68 %

Other

   0.5    3.7    6.4      10,100    3.1    70 %
    
  
  
  

  
  

Total

   35.4    226.4    439.2    $ 718,261    101.3    60 %
    
  
  
  

  
  

 

Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics. Our ratio of proved reserves to trailing 12 month production ending March 31, 2003 was approximately 11 years.

 

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Business Strategy

 

Our goal is to generate an attractive return on capital employed for all of our investment opportunities. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing acquisitions of additional properties that we believe have above-average exploitation and development potential. Specifically, we have focused, and plan to continue to focus, on the following:

 

Developing and Exploiting Existing Properties. We believe that there is significant value to be created by drilling the numerous identified undeveloped opportunities on our properties. We own interests in a total of 512,000 gross and 204,000 net developed acres and operate approximately 85.2% of the net pre-tax PV10% value of our PUD reserves. Over the past three years, we have invested $68.4 million to participate in the drilling of 124 gross and 45.1 net wells at an average cost of $552,000 per gross well. The majority of these wells have been developmental wells, and 81% were successful completions. We expect to spend approximately 50% of our internally generated cash flow during 2003 to add additional reserves and production through developing and exploiting existing core properties. As of April 1, 2003, we had identified a total of 196 drilling locations on our properties. We have participated in the drilling of 24 gross wells and 11.8 net wells during the six months ended June 30, 2003, and we plan to drill an additional 66 wells during the remainder of 2003. We believe our inventory of proved development drilling locations or major recompletion opportunities on our existing properties is sufficient to sustain this level of activity for approximately three years.

 

Pursuing Profitable Acquisitions. We will continue to pursue acquisitions of properties that we believe to have above-average exploitation and development potential. We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have a dedicated team of management and engineering and geoscience professionals who both identify and evaluate acquisition opportunities and manage those properties once acquired. From January 1, 2000 through December 31, 2002, we completed 41 acquisitions at an aggregate cost of approximately $332.7 million, representing approximately 369.6 Bcfe of proved reserves (at an average cost of $0.90 per Mcfe or $5.40 per Boe). During 2002, we acquired 157.4 Bcfe of proved reserves for an aggregate cost of $140.7 million and an average cost of $0.89 per Mcfe ($5.36 per Boe).

 

Focusing on High Return Operated and Non-Operated Properties. Based on our rate of return criteria, we have historically acquired operated as well as non-operated properties. We will continue to acquire both operated and non-operated interests to the extent they meet our return criteria. While we believe that a number of our competitors focus primarily, if not exclusively, on acquisitions of operated reserves, our track record demonstrates that equivalent and often greater returns can be achieved through the acquisition of non-operated interests. In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data that in some cases leads to further acquisitions in the same region, whether on an operated or non-operated basis.

 

Controlling Costs through Efficient Operation of Existing Properties. We operate approximately 58.4% of the pre-tax PV10% value of our reserves, which we believe enables us to better manage expenses, capital allocation and the decision-making processes related to our exploitation and exploration activities. For the year ended December 31, 2002, our lease operating expense per Mcfe averaged $0.93 and general and administrative costs averaged $0.34 per Mcfe produced, net of reimbursements.

 

Competitive Strengths

 

We believe that our key competitive strengths lie in our diversified asset base, our experienced management team and our commitment to efficient utilization of new technologies.

 

Diversified Asset Base. We have interests in 1,573 properties in 16 states across our four core geographical areas of the United States. This property base, as well as our continuing business strategy of

 

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acquiring and developing properties with above-average potential in our core operating areas, presents us with a large number of opportunities for successful development and exploitation.

 

Experienced Management Team. Our management team averages 26 years of experience in the oil and natural gas industry. Our personnel have extensive experience in each of our core geographical areas and in all of our operational disciplines. In addition, each of our acquisition professionals has at least 20 years of experience in the evaluation, acquisition and operational assimilation of oil and natural gas properties.

 

Commitment to Technology. In each of our core operating areas, we have accumulated detailed geologic and geophysical knowledge and have developed significant technical and operational expertise. In recent years, we have developed considerable expertise in conventional and 3-D seismic imaging and interpretation. Our technical team has access to approximately 571 square miles of 3-D seismic inventory, which we have assembled primarily over the past five years. A team with access to state-of-the-art geophysical/geological computer applications and hardware analyzes this information. Computer applications, such as the WellView® software system, enable us to quickly generate reports and schematics on our wells. In addition, our information systems enable us to update our production databases through daily uploads from hand-held computers in the field. This technology and expertise has greatly aided our pursuit of attractive development projects in our 386,000 gross undeveloped acres (188,000 net), located in North Dakota, Montana, Kansas and Texas.

 

Recent Development and Acquisition Activity

 

We have a capital budget of approximately $98.0 million for 2003, including $41.0 million for exploiting and drilling on our existing core properties and $57.0 million for the acquisition and subsequent development of additional oil and natural gas properties. During the six months ended June 30, 2003, we invested $16.7 million in our drilling projects. We have budgeted $24.3 million for drilling projects for the remainder of 2003.

 

Our major recent and ongoing acquisition and development projects include the following:

 

Williston Basin. The Williston Basin is the primary focus of our Rocky Mountains operations. We operate 45 fields in the North Dakota and Montana portions of the Williston Basin, with operated and non-operated interests in 916 wells and a 53% average working interest. As of April 1, 2003, our properties in the Williston Basin contained 173.7 Bcfe (6.8% natural gas) of net proved reserves with a net pre-tax PV10% value of $239.0 million. Our major development projects in the Williston Basin include the Big Stick (Madison) Unit, the North Elkhorn Ranch Unit and the Red Water (Bakken) field. We believe we have significant opportunities in the Bakken, Nisku and Mission Canyon Formations in the Golden Valley area of western North Dakota, as well as in several Red River Formation prospects in the Tolksdorf area of northern Richland County, Montana. We have drilled or participated in the drilling of seven wells in the Williston Basin during the first six months of 2003, six of which were successful, and we plan to drill an additional eleven wells during the remainder of the year.

 

Gulf Coast/Permian Basin. In the Gulf Coast/Permian Basin region, we have major operated development projects in the Stuart City Reef Trend and the Vicksburg Trend. In the Stuart City Reef Trend along the upper Texas Gulf Coast, we have interests in five fields that produce natural gas, primarily from the Edwards Limestone. We have operated and non-operated interests in 37 wells, with a 65% average working interest. As of April 1, 2003, our properties in the Stuart City Reef Trend contained 35.3 Bcfe (92% natural gas) of net proved reserves with a net pre-tax PV10% value of $49.4 million. We have significant ongoing development activity in the Yoakum, Word North and Kawitt fields. We have drilled two successful wells in 2003 and plan to drill an additional four wells during the remainder of the year.

 

In the Vicksburg Trend, we produce natural gas from the Vicksburg and Frio Formations in four fields located in Nueces and San Patricio Counties, Texas. We have significant ongoing operations in the Agua Dulce field, where we operate eleven wells with a 99.8% average working interest. As of April 1, 2003, our properties in this field contained 20.4 Bcfe (90.7% natural gas) of net proved reserves, with a net pre-tax

 

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PV10% value of $60.2 million. Our development plans in this field include a total of four wells this year, of which two successful wells have been drilled to date.

 

Michigan and Mid-Continent. In northern Michigan, we have proved reserves and development potential in 56 multi-well Antrim Shale natural gas development projects. We have committed to participate in the drilling of 38 Antrim Shale wells on these projects in 2003. We have proved undeveloped reserves with significant upside potential in the South Buckeye and Clayton fields, which produce natural gas from the Prairie du Chien Formation.

 

In the Cherokee Basin of southeastern Kansas, we are in the early stages of developing a coalbed methane project in which we have drilled eight test wells designed to determine the thickness and natural gas content of coal seams within the Cherokee Formation on our 91,284 acre leasehold. We are currently in the beginning stages of installing a pilot program designed to determine the productive potential of our leasehold.

 

The table below describes the increase in our proved reserves that we have achieved for some of the projects described above:

 

          Proved Reserves

    
          At Acquisition (1)

   At April 1, 2003

    

Acquisition


  

Date Acquired


   MMboe

   Bcfe

   MMboe

   Bcfe

  

%

Change


Williston Basin

  

August 1999 through

February 2002

   24.1    144.7    29.0    173.7    20.0

Stuart City Reef Trend

   June 2001    4.6    27.7    5.9    35.3    27.4

Agua Dulce Field

   March 2002    2.8    16.9    3.4    20.4    20.7

(1)   Adjusted for production through April 1, 2003.

 

Our Relationship with Alliant Energy

 

Whiting Petroleum Corporation is currently an indirect wholly-owned subsidiary of Alliant Energy, an energy services provider engaged primarily in regulated utility operations in the Midwest, with other non-regulated domestic and international operations. In November 2002, Alliant Energy announced that its board of directors had approved various strategic actions designed to maintain a strong credit profile, strengthen its balance sheet and position it for improved long-term financial performance. These strategic actions include the sale of, or other exit strategies for, a number of its non-regulated businesses, including Whiting Petroleum Corporation. This offering of our common stock pursuant to this prospectus is intended to facilitate Alliant Energy’s plan to exit its involvement in the exploration and production business. Accordingly, we will receive no proceeds from this offering.

 

After this offering, we expect that Alliant Energy will beneficially own approximately         % of our outstanding common stock. Alliant Energy currently intends to divest its remaining interest in us during the first half of 2004, subject to market conditions. See “Stock Ownership of Management and Selling Stockholders” and “Risk Factors—Risks Related to Our Relationship with Alliant Energy.” In addition, we and Alliant Energy will enter into various agreements that will govern our relationship with Alliant Energy after the offering. As a result of these agreements and Alliant Energy’s significant ownership of our common stock, Alliant Energy will be in a position to control or influence substantially the manner in which our business is operated and the outcome of stockholder votes on the election of directors and other matters. See “Relationship with Alliant Energy Corporation” for a description of these agreements. We will not have any material commercial relationships with Alliant Energy after this offering.

 

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Corporate Information

 

Whiting Petroleum Holdings, Inc. was incorporated in Delaware on July 18, 2003 for the sole purpose of becoming a holding company of Whiting Petroleum Corporation in connection with this offering. Whiting Petroleum Corporation was incorporated in Delaware in 1983.

 

Immediately prior to the completion of this offering, Resources will transfer all of the outstanding stock of Whiting Petroleum Corporation to Whiting Petroleum Holdings, Inc. in exchange for              shares of common stock of Whiting Petroleum Holdings, Inc., which will constitute all of its outstanding common stock, and other property. We refer to this transaction as the share exchange. See “Relationship with Alliant Energy Corporation” for a description of the share exchange and other agreements to be entered into between Alliant Energy and us in connection with the share exchange and this offering.

 

Our principal executive offices are located at 1700 Broadway, Suite 2300, Denver, Colorado, 80290-2300, and our telephone number is (303) 837-1661.

 

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The Offering

 

Common stock offered by the selling stockholder

                   shares

Shares outstanding after the offering

                   shares

Common stock to be owned by the selling stockholder after the offering

                   shares

Use of proceeds

   We will not receive any proceeds from the sale of shares in this offering. The selling stockholder will receive all of the proceeds.

Risk factors

   Please read “Risk Factors” and other information included in this prospectus for a discussion of factors you should consider carefully before deciding to invest in shares of our common stock.

Proposed New York Stock Exchange symbol

   “WLL”

 

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Summary Historical Financial Information

 

The summary historical financial information set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with our financial statements and the notes to those financial statements included elsewhere in this prospectus. The consolidated income statement information for the years ended December 31, 2000, 2001 and 2002 and the balance sheet information as of December 31, 2001 and 2002 were derived from our audited financial statements included in this prospectus. The consolidated income statement information for the six months ended June 30, 2002 and 2003 and the balance sheet information as of December 31, 2000 and June 30, 2003 were derived from our unaudited financial statements. The unaudited interim period financial information, in our opinion, includes all adjustments, which are normal and recurring in nature, necessary for a fair presentation for the periods shown. Results for the six months ended June 30, 2003 are not necessarily indicative of the results to be expected for the full fiscal year.

 

     Year Ended December 31,

   

Six Months

Ended June 30,


 
     2000

    2001

   2002

    2002

    2003

 
     (dollars in millions)  

Consolidated Income Statement Information:

                                       

Revenues:

                                       

Oil and gas sales

   $ 107.0     $ 125.2    $ 122.7     $ 49.7     $ 91.4  

Gain (loss) on oil and gas hedging activities

     (3.8 )     2.3      (3.2 )     (0.6 )     (8.8 )

Gain on sale of oil and gas properties

     7.7       11.7      1.0       —         —    

Interest income and other

     0.1       0.2      —         —         0.1  
    


 

  


 


 


Total revenues

   $ 111.0     $ 139.4    $ 120.5     $ 49.1     $ 82.7  
    


 

  


 


 


Costs and expenses:

                                       

Lease operating

     23.8       29.8      32.9       14.3       20.8  

Production taxes

     5.4       6.5      7.4       2.8       5.6  

Depreciation, depletion and amortization (1)

     21.5       26.9      43.6       20.1       20.5  

Exploration costs

     1.1       0.8      1.8       0.9       0.7  

General and administrative

     6.3       10.9      12.0       5.7       6.4  

Interest expense

     7.5       10.2      10.9       5.0       5.3  
    


 

  


 


 


Total costs and expenses

     65.6       85.1      108.6       48.8       59.3  

Income before income taxes

     45.4       54.3      11.9       0.3       23.4  

Income tax expense (benefit) (2)

     11.7       13.1      4.2       0.1       8.9  

Cumulative change in accounting principle (3)

     —         —        —         —         3.9  
    


 

  


 


 


Net income

   $ 33.7     $ 41.2    $ 7.7     $ 0.2     $ 10.6  
    


 

  


 


 


Operating Data:

                                       

Net production:

                                       

Natural gas (Bcf)

     16.9       19.9      21.4       10.3       10.7  

Oil (MMbbls)

     1.6       2.1      2.3       1.0       1.3  

Total (Bcfe)

     26.5       32.4      35.2       16.4       18.4  

Average sales price:

                                       

Natural gas (per Mcf) (4)

   $ 3.51     $ 3.82    $ 3.21     $ 2.80     $ 5.18  

Oil (per Bbl) (4)

     26.96       23.85      23.35       20.60       28.02  

Total (per Mcfe) (4)

     4.07       3.88      3.48       3.03       4.97  

Other Financial Information:

                                       

Net cash provided by operating activities

   $ 42.3     $ 62.3    $ 62.6     $ 19.2     $ 46.9  

Capital expenditures (5)

     139.1       99.6      165.4       108.7       20.8  

EBITDA (6)

     74.4       91.4      66.4       25.4       45.3  

 

     As of December 31,

   As of June 30,

     2000

   2001

   2002

   2003

     (dollars in millions)

Balance Sheet Information:

    

Total assets

   $ 256.4    $ 319.8    $ 448.5    $ 486.1

Long-term debt

     139.7      163.6      265.5      185.0

Stockholder’s equity

     70.0      111.5      122.8      215.9

 

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(1)   We reduced the amount of our abandonment liability estimate from approximately $13.0 million at December 31, 2000 to $4.0 million at December 31, 2001 as a result of receiving a revised and more detailed dismantlement plan from our dismantlement operator. This $9.0 million change in estimate reduced our depreciation, depletion and amortization expense in our 2001 financial statements as the expense for the abandonment liability had originally been recorded as a depreciation, depletion and amortization expense.
(2)   We generated Section 29 tax credits of $5.2 million in 2000, $6.6 million in 2001 and $5.4 million in 2002. Section 29 tax credits expired as of December 31, 2002. In 2002, we were able to use our $5.4 million of Section 29 tax credits in the consolidated federal income tax return filed by Alliant Energy, but since these credits would not have been used in a stand-alone filing, they were recorded as additional paid-in capital as opposed to a reduction in income tax expense.
(3)   In 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” This was a one-time charge to net income.
(4)   Before consideration of hedging transactions.
(5)   In June 2003, we acquired the limited partnership interests in two partnerships in which our wholly owned subsidiary is the general partner. Though disclosed as acquisitions of limited partnership interests in our consolidated statements of cash flows, these amounts are recorded as oil and natural gas properties on our consolidated balance sheets and are included in capital expenditures in this summary historical financial information.
(6)   See Note 5 to “Selected Historical Financial Information” for a definition of EBITDA and a reconciliation of EBITDA to net income.

 

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Summary Historical Reserve and Operating Data

 

The following table presents summary information regarding our estimated net proved oil and natural gas reserves as of December 31, 2000, 2001 and 2002 and April 1, 2003 and our historical operating data for the years ended December 31, 2000, 2001 and 2002 and the six months ended June 30, 2002 and 2003. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the Securities and Exchange Commission, or the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. For additional information regarding our reserves, please read “Business and Properties – Summary of Oil and Natural Gas Properties and Projects” and note 11 to our financial statements.

 

     As of December 31,

  

As of April 1,

2003


     2000

   2001

   2002

  

Reserve Data:

                           

Total estimated net proved reserves:

                           

Natural gas (Bcf)

     157.5      227.5      236.0      226.4

Oil (MMbbls)

     19.1      14.8      29.5      35.5

Total (Bcfe)

     272.1      316.3      412.7      439.2

Estimated net proved developed reserves:

                           

Natural gas (Bcf)

     134.4      136.8      167.6      162.9

Oil (MMbbls)

     14.9      11.0      23.8      24.8

Total (Bcfe)

     223.8      202.8      310.4      312.5

Estimated future net revenues before income taxes (in millions)

   $ 1,356.1    $ 425.6    $ 1,112.4    $ 1,256.3

Present value of estimated future net revenues before income taxes (in millions) (1) (2)

   $ 728.3    $ 244.6    $ 638.6    $ 718.3

Standardized measure of discounted future net cash flows (in millions) (3)

   $ 519.2    $ 211.7    $ 476.0    $ 503.7

 

     Year Ended December 31,

  

Six Months Ended

June 30,


     2000

   2001

   2002

   2002

   2003

Operating Data:

                                  

Net production:

                                  

Natural gas (Bcf)

     16.9      19.8      21.4      10.3      10.7

Oil (MMbbls)

     1.6      2.1      2.3      1.0      1.3

Total (Bcfe)

     26.5      32.4      35.2      16.4      18.4

Net sales (in millions) (4):

                                  

Natural gas

   $ 65.0    $ 75.4    $ 68.6    $ 28.8    $ 55.7

Oil

     42.0      49.8      54.1      20.9      35.7

Total

     107.0      125.2      122.7      49.7      91.4

Average sales price:

                                  

Natural gas (per Mcf)(4)

   $ 3.51    $ 3.82    $ 3.21    $ 2.80    $ 5.18

Oil (per Bbl)(4)

     26.96      23.85      23.35      20.60      28.02

Total (per Mcfe)(4)

     4.07      3.88      3.48      3.03      4.97

Average (per Mcfe):

                                  

Lease operating expenses

   $ 0.90    $ 0.92    $ 0.93    $ 0.88    $ 1.13

Production taxes

     0.20      0.20      0.21      0.17      0.30

Depreciation, depletion and amortization expense (5)

     0.82      1.11      1.24      1.22      1.11

General and administrative expenses, net of reimbursements

     0.24      0.34      0.34      0.35      0.35

Net income

     1.28      1.28      0.22      0.01      0.58

EBITDA (6)

     2.83      2.83      1.88      1.55      2.46

 

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(1)   The present value of estimated future net revenues attributable to our reserves was prepared using constant prices, as of the calculation date, discounted at 10% per year on a pre-tax basis.
(2)   The December 31, 2002 amount was calculated using a period end average realized oil price of $28.21 per barrel and a period end average realized natural gas price of $4.39 per Mcf, and the April 1, 2003 amount was calculated using a period end average realized oil price of $27.75 per barrel and a period end average realized natural gas price of $4.85 per Mcf.
(3)   The standardized measure of discounted future net cash flows represents the present value of future cash flows after income tax discounted at 10%.
(4)   Before consideration of hedging transactions.
(5)   We reduced the amount of our abandonment liability estimate from approximately $13.0 million at December 31, 2000 to $4.0 million at December 31, 2001 as a result of receiving a revised and more detailed dismantlement plan from our dismantlement operator. This $9.0 million change in estimate reduced our depreciation, depletion and amortization expense in our 2001 financial statements as the expense for the abandonment liability had originally been recorded as a depreciation, depletion and amortization expense.
(6)   See Note 5 to “Selected Historical Financial Information” for a definition of EBITDA and a reconciliation of EBITDA to net income.

 

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RISK FACTORS

 

You should carefully consider each of the risks described below, together with all of the other information contained in this prospectus, before deciding to invest in shares of our common stock. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline and you may lose all or part of your investment.

 

Risks Relating to the Oil and Natural Gas Industry and Our Business

 

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operation and our ability to meet our capital expenditure obligations and financial commitments.

 

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

 

  • ¨   changes in global supply and demand for oil and natural gas;

 

  • ¨   the actions of the Organization of Petroleum Exporting Countries, or OPEC;

 

  • ¨   the price and quantity of imports of foreign oil and natural gas;

 

  • ¨   political conditions, including embargoes, in or affecting other oil-producing activity;

 

  • ¨   the level of global oil and natural gas exploration and production activity;

 

  • ¨   the level of global oil and natural gas inventories;

 

  • ¨   weather conditions;

 

  • ¨   technological advances affecting energy consumption; and

 

  • ¨   the price and availability of alternative fuels.

 

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

 

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

 

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate” for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

 

  • ¨   delays imposed by or resulting from compliance with regulatory requirements;

 

  • ¨   pressure or irregularities in geological formations;

 

  • ¨   shortages of or delays in obtaining equipment and qualified personnel;

 

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  • ¨   equipment failures or accidents;

 

  • ¨   adverse weather conditions, such as hurricanes and tropical storms;

 

  • ¨   reductions in oil and natural gas prices;

 

  • ¨   title problems; and

 

  • ¨   limitations in the market for oil and natural gas.

 

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

 

In order to finance acquisitions of additional producing properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for any such acquisitions or other transactions or to obtain external funding on terms acceptable to us.

 

Properties that we buy may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain protection from sellers against them.

 

Our business strategy includes a continuing acquisition program. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

 

  • ¨   the amount of recoverable reserves;

 

  • ¨   future oil and natural gas prices;

 

  • ¨   estimates of operating costs;

 

  • ¨   estimates of future development costs;

 

  • ¨   estimates of the costs and timing of plugging and abandonment; and

 

  • ¨   potential environmental and other liabilities.

 

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform or pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination, when they are made. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

 

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

 

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

 

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Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. Please read “Business and Properties—Summary of Oil and Natural Gas Properties and Projects” for information about our oil and natural gas reserves.

 

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

 

You should not assume that the present value of future net revenues from our proved reserves referred to in this prospectus is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If natural gas prices decline by $0.10 per Mcf, then the pre-tax PV10% value of our proved reserves as of April 1, 2003 would decrease from $718.3 million to $706.3 million. If oil prices decline by $1.00 per barrel, then the pre-tax PV10% value of our proved reserves as of April 1, 2003 would decrease from $718.3 million to $703.9 million.

 

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

 

Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

  • ¨   environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

 

  • ¨   abnormally pressured formations;

 

  • ¨   mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

 

  • ¨   fires and explosions;

 

  • ¨   personal injuries and death; and

 

  • ¨   natural disasters.

 

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company. We maintain insurance at levels that we believe are consistent with industry

 

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practices, but we are not fully insured against all risks. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then it could adversely affect us.

 

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

 

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until production arrangements were made to deliver to market.

 

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

 

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

 

  • ¨   discharge permits for drilling operations,

 

  • ¨   drilling bonds,

 

  • ¨   reports concerning operations,

 

  • ¨   the spacing of wells,

 

  • ¨   unitization and pooling of properties, and

 

  • ¨   taxation.

 

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

 

Our operations may incur substantial liabilities to comply with the environmental laws and regulations.

 

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, incurrence of investigatory or remedial obligations, or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position, or financial condition as well as the industry in general. Under these

 

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environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

 

Our level of indebtedness reduces our financial flexibility, and our level of indebtedness may increase.

 

As of June 30, 2003, we had long-term indebtedness of $185.0 million and our long-term indebtedness represented 46.0% of our total capitalization.

 

Our level of indebtedness affects our operations in several ways, including the following:

 

  • ¨   a significant portion of our cash flow must be used to service our indebtedness,

 

  • ¨   a high level of debt increases our vulnerability to general adverse economic and industry conditions,

 

  • ¨   the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments,

 

  • ¨   our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry, and

 

  • ¨   a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

 

We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions or to develop our properties. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

 

In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

 

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

 

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production.

 

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The loss of senior management or technical personnel could adversely affect us.

 

To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

 

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

 

Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

 

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

 

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

 

Our use of oil and natural gas price hedging contracts involves credit risk and may limit future revenues from price increases and result in significant fluctuations in our net income.

 

We enter into hedging transactions for our oil and natural gas production to reduce our exposure to fluctuations in the price of oil and natural gas. Our hedging transactions have to date consisted of financially settled crude oil and natural gas forward sales contracts with major financial institutions. As of June 30, 2003, we had contracts maturing monthly through December 31, 2003 covering the sale of 17,000 barrels of crude oil and 4.2 million MMbtu of natural gas. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure about Market Risk” for pricing and a more detailed discussion of hedging transactions.

 

We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Hedging transactions may limit the benefit we would have otherwise received from increases in the price for oil and natural gas. Furthermore, if we do not engage in hedging transactions, then we may be more adversely affected by declines in oil and natural gas prices than our competitors who engage in hedging transactions. Additionally, hedging transactions may expose us to cash margin requirements.

 

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Risks Relating to Our Relationship with Alliant Energy

 

Our principal stockholder is in a position to affect our ongoing operations, corporate transactions and other matters.

 

After giving effect to this offering, our principal stockholder, Alliant Energy, through its wholly-owned subsidiary Resources, will beneficially own approximately         % of our outstanding shares of common stock.

 

In connection with this offering, we will enter into a master separation agreement with Alliant Energy, which is described in more detail under “Relationship with Alliant Energy Corporation—Master Separation Agreement.” The master separation agreement provides, among other things, that for so long as Alliant Energy owns at least 10% of our outstanding common stock, it will have the right to nominate the number of our directors equal to the percentage of our outstanding common stock it owns, rounded up to the nearest full number of directors. However, such number of directors must be at least one but less than a majority of our board of directors. Under the master separation agreement, for so long as Alliant Energy owns at least 10% of our outstanding common stock, we must obtain Alliant Energy’s consent before we may take specified corporate actions, including issuing equity securities, declaring dividends, redeeming or repurchasing equity securities, merging or consolidating with another entity, amending our charter documents, taking or recommending to our stockholders actions limiting the rights of, or denying benefits to, any stockholder, adopting a stockholder rights plan or liquidating, dissolving or winding-up. The master separation agreement also provides that two-thirds of our board of directors must approve specified corporate matters, including our annual acquisitions and drilling budget, indebtedness in excess of the borrowing base under our credit agreement, significant business acquisitions or dispositions, our annual capital and operating budgets, significant joint ventures, certain executive compensation matters or hedging our production in excess of specified volumes. As a result, Alliant Energy will be in a position to control or influence substantially the manner in which our business is operated and the outcome of stockholder votes on the election of directors and other matters. See “Relationship with Alliant Energy Corporation.”

 

Prior to Alliant Energy’s divestiture of its interest in us, we will continue to be subject to regulation under the Public Utility Holding Company Act absent an exemption. That Act limits our business operations, our ability to pay dividends, our ability to receive dividends from our subsidiaries and our ability to affiliate with public utilities.

 

Until Alliant Energy owns less than 10% of our common stock, we will continue to be subject to regulation under the Public Utility Holding Company Act of 1935, or PUHCA, as a subsidiary company of a public utility holding company registered under PUHCA. We and Alliant Energy have agreed to seek an exemption from our being considered a “subsidiary company” of Alliant Energy for purposes of PUHCA, but we may not be able to obtain such an exemption. As a result, we will be subject to limitations under PUHCA related to our acquisition strategy, ownership and operation of energy assets outside of our current business plan, payments of dividends by us and our subsidiaries from capital surplus and issuances of securities. Additionally, as long as Alliant Energy owns 5% or more of our outstanding common stock, we must obtain approval under PUHCA prior to acquiring 5% or more of the voting securities of any public utility or taking any other actions that would result in affiliation with another public utility or entering into any contractual arrangements with Alliant Energy or any of its affiliates. Once Alliant Energy owns less than 10% of our common stock, we do not expect to be subject to regulation under PUHCA as a subsidiary company and we do not currently intend to take actions that would cause us subsequently to become subject to regulation under PUHCA.

 

PUHCA prohibits Alliant Energy and its subsidiaries, including us, from making additional investments in non-utility “energy assets” without approval from the SEC. Currently, Alliant Energy and its subsidiaries are authorized under an order issued by the SEC under PUHCA to invest, without further approval from the SEC, up to $800 million in additional “energy assets” in the United States and Canada. The SEC order expires on December 31, 2004. As defined in the SEC order, “energy assets” include

 

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natural gas production, gathering, processing, storage and transportation facilities and equipment, liquid oil reserves and storage facilities, and associated facilities. Without obtaining another order from the SEC, we will not be able to acquire assets that fall outside of these categories. As of June 30, 2003, Alliant Energy and its subsidiaries, including us, had used approximately $384 million of the $800 million granted under the SEC order. Alliant Energy has agreed that we may use at least $300 million of the remaining $416 million authority under the SEC order. Alliant Energy has also agreed to allow us to apply to the SEC for our own authority to acquire “energy assets.”

 

If Alliant Energy continues to own 10% or more of our common stock after December 31, 2004 and the SEC does not extend the order beyond that date or grant us our own order, or if the authority to acquire “energy assets” under Alliant Energy’s or our own order is not sufficient to maintain our acquisition strategy, then our operations may be adversely affected and we may not be able to pursue our business strategies.

 

Further, we and our subsidiaries are authorized under an order issued by the SEC to pay dividends out of capital or unearned surplus. This order is necessary to exempt us and our subsidiaries from restrictions on the payment of dividends contained in PUHCA and expiring on December 31, 2004. If Alliant Energy continues to own 10% or more of our common stock after December 31, 2004 and the SEC does not extend the order beyond that date or grant us our own order, cash held by our subsidiaries may not be able to be distributed to us, reducing our cash management flexibility and increasing our need for working capital and external financing.

 

PUHCA also regulates our issuance of securities and requires compliance with applicable SEC rules respecting such issuances. Current SEC rules exempt our issuances of securities from PUHCA requirements so long as the securities are issued solely for the purpose of financing our existing business.

 

Potential conflicts may arise between us and Alliant Energy and its other affiliates that may not be resolved in our favor.

 

The relationship between us and Alliant Energy and its other affiliates may give rise to conflicts of interest with respect to, among other things, transactions and agreements among us and Alliant Energy and its other affiliates, issuances of additional shares of voting securities, the election of directors or the payment of dividends, if any, by us. When the interests of Alliant Energy and its other affiliates diverge from our interests, Alliant Energy may exercise its substantial influence and control over us in favor of its own interests or the interests of another of its affiliates over our interests.

 

Our intercompany agreements with Alliant Energy and its other affiliates are not the result of arm’s-length negotiations with third parties.

 

We have entered or will enter into various agreements with Alliant Energy and some of its other affiliates which govern various transactions between us and our ongoing relationship following completion of this offering, including agreements relating to registration rights, tax separation and indemnification. All of these agreements were or will be entered into in the context of a parent-subsidiary relationship and were negotiated in the overall context of this offering. These agreements may have terms and conditions that may be less favorable to us than agreements that we might have negotiated at arm’s-length with independent parties. We and Alliant Energy and its other affiliates may enter into other material transactions and agreements from time to time in the future.

 

Our historical financial results as a subsidiary of Alliant Energy may not be representative of our results as a separate company.

 

The historical financial information included in this prospectus does not necessarily reflect what our financial position, results of operations and cash flows would have been had we been a separate, stand-alone entity during the periods presented. This historical financial information is not necessarily indicative of what our results of operations, financial position and cash flows will be in the future. We

 

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may experience significant changes in our cost structure, funding and operations as a result of becoming a publicly traded, stand-alone company.

 

Risks Relating to the Offering and Our Common Stock

 

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public markets, including by Alliant Energy.

 

Sales by Alliant Energy of a substantial number of shares of our common stock in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities. Alliant Energy currently intends to divest all of its remaining interest in us during the first half of 2004, subject to market conditions. We do not know whether such divestiture would be made in the public market or in a private placement to strategic or financial investors, nor do we know what impact Alliant Energy’s planned or actual divestiture will have on our stock price in the future. Please read “Shares Eligible for Future Sale.”

 

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, our stock price may be volatile.

 

Prior to this offering, Alliant Energy, through Resources, held all of our outstanding common stock, and therefore, there has been no public market for our common stock. An active market for our common stock may not develop or may not be sustained after this offering. The initial public offering price of our common stock was determined by negotiations between us and representatives of the underwriters, based on numerous factors which we discuss in the “Underwriting” section of this prospectus. This price may not be indicative of the market price for our common stock after this initial public offering. The market price of our common stock could be subject to significant fluctuations after this offering, and may decline below the initial public offering price. You may not be able to resell your shares at or above the initial public offering price. The following factors could affect our stock price:

 

  • ¨   our operating and financial performance and prospects,

 

  • ¨   quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues,

 

  • ¨   changes in revenue or earnings estimates or publication of research reports by analysts,

 

  • ¨   speculation in the press or investment community,

 

  • ¨   sales of our common stock by Alliant Energy or other stockholders,

 

  • ¨   actions by institutional investors or by Alliant Energy prior to its disposition of our common stock,

 

  • ¨   general market conditions, including fluctuations in commodity prices, and

 

  • ¨   domestic and international economic, legal and regulatory factors unrelated to our performance.

 

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.

 

We have no plans to pay dividends on our common stock. You may not receive funds without selling your shares.

 

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends, and restrictions under

 

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PUHCA may limit our ability to pay dividends. The consent of Alliant Energy is also required to pay dividends.

 

Provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

 

The existence of some provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. The provisions in our certificate of incorporation and by-laws that could delay or prevent an unsolicited change in control of our company include the following:

 

  • ¨   dividing our board of directors into three classes to be elected on a staggered basis, one class each year;

 

  • ¨   authorizing our board of directors to issue shares of our preferred stock in one or more series without further authorization of our stockholders;

 

  • ¨   requiring that stockholders provide advance notice of any stockholder nomination of directors or any proposal of new business to be considered at any meeting of stockholders;

 

  • ¨   permitting removal of directors only for cause by a supermajority vote;

 

  • ¨   providing that vacancies on our board of directors will be filled by the remaining directors then in office;

 

  • ¨   eliminating the right of stockholders to call a special meeting of stockholders or take action by written consent without a meeting of stockholders; and

 

  • ¨   requiring that a supermajority vote be obtained to amend or repeal specified provisions of our certificate of incorporation or by-laws.

 

In addition, Delaware law imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.

 

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

  • ¨   business strategy;

 

  • ¨   reserves;

 

  • ¨   technology;

 

  • ¨   financial strategy;

 

  • ¨   realized oil and natural gas prices;

 

  • ¨   production;

 

  • ¨   uncertainty regarding our future operating results; and

 

  • ¨   plans, objectives, expectations and intentions contained in this prospectus that are not historical.

 

All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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USE OF PROCEEDS

 

We estimate that the selling stockholder will receive net proceeds of approximately $             million from the sale of the shares of our common stock in this offering, based upon an assumed initial public offering price of $             per share, the midpoint of the offering range, and after deducting underwriting discounts and commissions and estimated offering expenses. If the underwriters’ overallotment options are exercised in full, we estimate that the selling stockholder’s net proceeds will be approximately $             million.

 

We will not receive any of the net proceeds, including any amount received in connection with an exercise of the underwriters’ overallotment options, from this offering.

 

DIVIDEND POLICY

 

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends, and restrictions under PUHCA may limit our ability to pay dividends. The consent of Alliant Energy is also required to pay dividends.

 

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CAPITALIZATION

 

The following table sets forth, as of June 30, 2003, the actual capitalization of Whiting Petroleum Corporation and the capitalization, on a pro forma, as adjusted basis to reflect the share exchange that will occur immediately prior to the closing of this offering. In connection with the share exchange, Resources will receive from Whiting Petroleum Holdings, Inc.             shares of its common stock in exchange for all of the issued and outstanding shares of Whiting Petroleum Corporation. You should read this table in conjunction with our financial statements and the notes to those financial statements included elsewhere in this prospectus.

 

The pro forma, as adjusted capitalization below does not reflect the impact of two adjustments affecting total stockholders’ equity that will be made at the time this offering is completed. First, a charge to earnings will occur that will decrease total stockholders’ equity because the completion of this offering will constitute a “triggering event” under our Phantom Equity Plan. See “Management—Change of Control Arrangements.” The amount of the charge will be based on the value of our proved reserves, but we expect that it will be approximately $              after related income tax effects. Second, an increase in total stockholders’ equity will occur as a result of the change in tax basis of the assets of Whiting Petroleum Corporation in connection with the share exchange. See “Relationship With Alliant Energy Corporation—Tax Separation and Indemnification Agreement.” We will adjust the amount of deferred taxes on our balance sheet based on the new tax basis of the assets of Whiting Petroleum Corporation, record a payable to Alliant Energy equal to the fair value of the expected future payments to be made under the tax separation and indemnification agreement, and record the difference as an equity contribution from Alliant Energy. The amount of the increase in total stockholders’ equity will depend on the value of the assets of Whiting Petroleum Corporation on the date Alliant Energy transfers the stock of Whiting Petroleum Corporation to Whiting Petroleum Holdings, Inc. and will also depend on the determination of the fair value of the anticipated payments to Alliant Energy under the tax separation and indemnification agreement. While the ultimate amounts recorded will depend on a number of factors at the time this offering is completed, we currently expect the amount of the equity contribution from the tax separation and indemnification agreement will be $            .

 

     As of June 30, 2003

  

% of Total
Capitalization


     Whiting Petroleum
Corporation Actual


   Whiting Petroleum
Holdings, Inc. Pro
Forma, as Adjusted


  
     (dollars in millions)     

Cash and cash equivalents

   $ 31.2    $      %
    

  

    

Short-term debt

     —        —      —  

Long-term debt

   $ 185.0    $      %
    

  

    

Total debt

     185.0           %

Total stockholders’ equity

     215.9           %
    

  

  

Total capitalization

   $ 400.9    $      100%
    

  

  

 

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SELECTED HISTORICAL FINANCIAL INFORMATION

 

The selected historical financial information set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with our financial statements and the notes to those financial statements included elsewhere in this prospectus. The consolidated income statement information for years ended December 31, 2000, 2001 and 2002 and the balance sheet information as of December 31, 2001 and 2002 were derived from our audited financial statements included in this prospectus. The consolidated income statement information for the years ended December 31, 1998 and 1999 and the six months ended June 30, 2002 and 2003 and the balance sheet information as of December 31, 1998, 1999 and 2000 and June 30, 2002 and 2003 were derived from our unaudited financial statements. The unaudited interim period financial information, in our opinion, includes all adjustments, which are normal and recurring in nature, necessary for a fair presentation for the periods shown. Results for the six months ended June 30, 2003 are not necessarily indicative of the results to be expected for the full fiscal year.

 

     Year Ended December 31,

   

Six Months

Ended June 30,


 
     1998

    1999

   2000

    2001

   2002

    2002

    2003

 
     (dollars in millions except per share data)  

Consolidated Income Statement Information:

                                                      

Revenues:

                                                      

Oil and gas sales

   $ 59.2     $ 60.9    $ 107.0     $ 125.2    $ 122.7     $ 49.7     $ 91.4  

Gain (loss) on oil and gas hedging activities

     —         —        (3.8 )     2.3      (3.2 )     (0.6 )     (8.8 )

Gain on sale of oil and gas properties

     1.2       10.1      7.7       11.7      1.0       —         —    

Interest income and other

     0.1       0.1      0.1       0.2      —         —         0.1  
    


 

  


 

  


 


 


Total revenues

   $ 60.5     $ 71.1    $ 111.0     $ 139.4    $ 120.5     $ 49.1     $ 82.7  
    


 

  


 

  


 


 


Costs and expenses:

                                                      

Lease operating

   $ 19.5     $ 20.7    $ 23.8     $ 29.8    $ 32.9     $ 14.3     $ 20.8  

Production taxes

     2.6       3.0      5.4       6.5      7.4       2.8       5.6  

Depreciation, depletion and amortization (1)

     23.0       19.8      21.5       26.9      43.6       20.1       20.5  

Impairment of proven oil and gas properties

     9.7       3.3      —         —        —         —         —    

Exploration costs

     1.4       1.9      1.1       0.8      1.8       0.9       0.7  

General and administrative

     3.1       4.3      6.3       10.9      12.0       5.7       6.4  

Interest expense

     6.2       5.4      7.5       10.2      10.9       5.0       5.3  
    


 

  


 

  


 


 


Total costs and expenses

   $ 65.5     $ 58.4    $ 65.6     $ 85.1    $ 108.6     $ 48.8     $ 59.3  

Income (loss) before income taxes

   $ (5.0 )   $ 12.7    $ 45.4     $ 54.3    $ 11.9     $ 0.3     $ 23.4  

Income tax expense (benefit) (2):

                                                      

Current

     (6.2 )     0.3      7.9       1.8      (6.4 )     (3.2 )     0.4  

Deferred

     1.1       1.5      3.8       11.3      10.6       3.3       8.5  
    


 

  


 

  


 


 


Total income tax expense

     (5.1 )     1.8      11.7       13.1      4.2       0.1       8.9  
    


 

  


 

  


 


 


Cumulative change in accounting principle (3)

     —         —        —         —        —         —         3.9  
    


 

  


 

  


 


 


Net income

   $ 0.1     $ 10.9    $ 33.7     $ 41.2    $ 7.7     $ 0.2     $ 10.6  
    


 

  


 

  


 


 


Basic net income per common share

   $       $      $       $      $       $       $    
    


 

  


 

  


 


 


Other Financial Information:

                                                      

Net cash provided by operating activities

   $ 23.6     $ 38.7    $ 42.3     $ 62.3    $ 62.6     $ 19.2     $ 46.9  

Capital expenditures (4)

     46.8       34.9      139.1       99.6      165.4       108.7       20.8  

EBITDA(5)

     24.2       37.9      74.4       91.4      66.4       25.4       45.3  

 

     As of December 31,

   As of June 30,

     1998

   1999

   2000

   2001

   2002

   2002

   2003

     (dollars in millions)

Balance Sheet Information:

                                                

Total assets

   $ 144.3    $ 148.5    $ 256.4    $ 319.8    $ 448.5    $ 409.5    $ 486.1

Long-term debt

     87.6      72.5      139.7      163.6      265.5      246.1      185.0

Stockholder’s equity

     28.0      36.2      70.0      111.5      122.8      117.7      215.9

 

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(1)   We reduced the amount of our abandonment liability estimate from approximately $13.0 million at December 31, 2000 to $4.0 million at December 31, 2001 as a result of receiving a revised and more detailed dismantlement plan from our dismantlement operator. This $9.0 million change in estimate reduced our depreciation, depletion and amortization expense in our 2001 financial statements as the expense for the abandonment liability had originally been recorded as a depreciation, depletion and amortization expense.
(2)   We generated Section 29 tax credits of $2.3 million in 1998, $3.0 million in 1999, $5.2 million in 2000, $6.6 million in 2001 and $5.4 million in 2002. Section 29 tax credits expired as of December 31, 2002. In 2002, we were able to use our $5.4 million of Section 29 tax credits in the consolidated federal income tax return filed by Alliant Energy, but since these credits would not have been used in a stand-alone filing, they were recorded as additional paid-in capital as opposed to a reduction in income tax expense.
(3)   In 2003, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” This was a one-time charge to net income.
(4)   In June 2003, we acquired the limited partnership interests in two partnerships in which our wholly owned subsidiary is the general partner. Though disclosed as acquisitions of limited partnership interests in our consolidated statements of cash flows, these amounts are recorded as oil and natural gas properties on our consolidated balance sheets and are included in capital expenditures in this summary historical financial information.
(5)   We define EBITDA as earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with generally accepted accounting principles in the United States, or GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies. In addition, EBITDA does not represent funds available for discretionary use.

 

The following table presents a reconciliation of our consolidated net income to consolidated EBITDA:

 

     Year Ended December 31,

   Six Months Ended

       

June 30,

2002


  

June 30,

2003


     1998

    1999

   2000

   2001

   2002

     
     (dollars in millions)    (unaudited)

Net income

   $ 0.1     $ 10.9    $ 33.7    $ 41.2    $ 7.7    $ 0.2    $ 10.6

Income tax expense (benefit)

     (5.1 )     1.8      11.7      13.1      4.2      0.1      8.9

Interest expense

     6.2       5.4      7.5      10.2      10.9      5.0      5.3

Depreciation, depletion and amortization

     23.0       19.8      21.5      26.9      43.6      20.1      20.5
    


 

  

  

  

  

  

EBITDA

   $ 24.2     $ 37.9    $ 74.4    $ 91.4    $ 66.4    $ 25.4    $ 45.3
    


 

  

  

  

  

  

 

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MANAGEMENT’S DISCUSSION AND

ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Introduction

 

The following discussion and analysis should be read in conjunction with our selected historical financial data and our accompanying financial statements and the notes to those financial statements included elsewhere in this prospectus. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this prospectus, particularly in “Risk Factors.”

 

Overview

 

We are engaged in oil and natural gas exploitation, acquisition and exploration activities primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan and Mid-Continent regions of the United States. Over the last three years, we have emphasized the acquisition of properties that provided current production and significant upside potential through further development. Our drilling activity is directed at this development, specifically on projects that we believe provide repeatable successes in particular fields.

 

We have increased our reserves significantly by investing $140 million on acquisitions and $26 million on drilling and completion in 2002, following total capital expenditures of approximately $99.6 million in 2001 and approximately $139.1 million in 2000. In addition, our technical staff has identified significant additional reserves following our acquisitions.

 

Our capital budget of approximately $98.0 million for 2003 includes $41.0 million for the drilling of existing proved reserves and $57.0 million for the acquisition and development of additional reserves. During the six months ended June 30, 2003, we have invested $16.7 million in our drilling projects. We have budgeted $24.3 million for drilling projects for the remainder of 2003.

 

Our combination of acquisitions and development allows us to direct our capital resources to what we believe to be the most advantageous investments. During periods of radically changing prices, we focus our emphasis on drilling and development of our owned properties. When prices stabilize, we generally direct the majority of our capital to acquisitions.

 

Based on our rate of return criteria, we have historically acquired operated as well as non-operated properties. We will continue to acquire both operated and non-operated interests to the extent we believe they meet our return criteria. We believe our track record demonstrates that equivalent and often greater returns can be achieved through the acquisition of non-operated interests. In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis. We sell properties when management is of the opinion that the sale price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.

 

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. See “Risk Factors” for a more detailed discussion of these risks.

 

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Results of Operations

 

The following table sets forth selected operating data for the periods indicated:

 

     Years Ended December 31,

  

Six Months

Ended June 30,


     2000

   2001

   2002

   2002

   2003

Net production:

                                  

Natural gas (Bcf)

     16.9      19.8      21.4      10.3      10.7

Oil (MMbbls)

     1.6      2.1      2.3      1.0      1.3

Net sales (in millions):

                                  

Natural gas (1)

   $ 65.0    $ 75.4    $ 68.6    $ 28.8    $ 55.7

Oil (1)

   $ 42.0    $ 49.8    $ 54.1    $ 20.9    $ 35.7

Average sales price:

                                  

Natural gas (per Mcf) (1)

   $ 3.51    $ 3.82    $ 3.21    $ 2.80    $ 5.18

Oil (per Bbl) (1)

   $ 26.96    $ 23.85    $ 23.35    $ 20.60    $ 28.02

Production costs and expenses (per Mcfe):

                                  

Lease operating expenses

   $ 0.90    $ 0.92    $ 0.93    $ 0.88    $ 1.13

Production taxes

   $ 0.20    $ 0.20    $ 0.21    $ 0.17    $ 0.30

Depreciation, depletion and amortization expense

   $ 0.82    $ 1.11    $ 1.24    $ 1.22    $ 1.11

General and administrative expenses, net of reimbursements

   $ 0.24    $ 0.34    $ 0.34    $ 0.35    $ 0.35

(1)   Before consideration of hedging transactions.

 

Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002

 

Oil and Natural Gas Sales. Oil and natural gas sales revenue increased approximately $41.6 million from $49.8 million for the first six months of 2002 to $91.4 million for the first six months of 2003. Natural gas sales increased $26.9 million and oil sales increased $14.8 million. The natural gas sales increase was caused by an 85% increase in the average realized natural gas price from $2.80 per Mcf for the first six months of 2002 to $5.18 per Mcf during the first six months of 2003 and an increase in natural gas production of 400,000 Mcf for the first six months of 2003. The oil sales increase was caused by a sales volume increase of 300,000 Bbls in 2003 and a 36% increase in the averaged realized oil price from $20.60 during the initial six months of 2002 to $28.02 during the comparable period of 2003. The volume increase for crude oil and natural gas primarily resulted from $165.4 million of capital expenditures during 2002.

 

Loss on Oil and Natural Gas Hedging Activities. We hedged 43% of our natural gas volumes during the first six months of 2003 and 6% of our natural gas volumes during the first six months of 2002, incurring a hedging loss of $7.9 million in 2003 compared with no hedging loss in 2002. We hedged 15% of our oil volumes during the first six months of 2003 and 24% of our oil volumes during the first six months of 2002, incurring hedging losses of $0.9 million in 2003 and $0.6 million in 2002.

 

Lease Operating Expenses. Our lease operating expenses per Mcfe increased from $0.88 in the first six months of 2002 to $1.13 during the same period in 2003. This increase was a result of the acquisitions completed during 2002 that increased the proportion of our operations that are located in North Dakota and Michigan, where weather conditions, crude oil sulfur content and remote locations result in higher operating costs in comparison to our other areas of operation.

 

Production Taxes. Production taxes as a percentage of oil and natural gas sales were 6.1% during the first six months of 2003 and 5.6% during the first six months of 2002. The increase in the effective rate

 

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resulted from additional property purchases in the states of North Dakota and Montana where effective production tax rates are higher on average than other areas where we own significant producing properties.

 

Depreciation, Depletion and Amortization. Our depreciation, depletion and amortization expense increased by $0.4 million during the first six months of 2003 compared to the same period in 2002. The increase was a result of increasing sales volumes due to our 2002 acquisitions, partially offset by a decrease in the average depreciation, depletion and amortization rate from $1.22 per Mcfe during the first six months of 2002 to $1.11 per Mcfe during the first six months of 2003. The decreased depreciation, depletion and amortization rate was the result of higher prices between periods, which allowed for a longer economic production life and corresponding increased reserve volumes and, as a result, a lower depreciation, depletion and amortization rate.

 

Exploration Costs. Exploration costs decreased $0.2 million during the first six months of 2003 compared to the same period in 2002. The decrease was primarily the result of a decrease in the amount of seismic data purchased and processed.

 

General and Administrative Expenses. General and administrative expenses increased by $0.7 million to $6.4 million during the first six months of 2003. This increase was primarily related to increases in compensation expense associated with an increase in personnel required to administer our growth and to general cost inflation.

 

Interest Expense. Interest expense increased $0.3 million during the first six months of 2003 compared to the same period in 2002. The increase was due to higher average debt levels in 2003 to fund our growth, partially offset by a lower effective interest rate. In March 2003, Alliant Energy converted its remaining $80.9 million of intercompany debt into our equity, thereby lowering the amount of interest expense to be reported by us in the future.

 

Income Tax Expense. Our effective tax rate was 38.0% during the first six months of 2003 and 23.8% during the first six months of 2002. The rate was lower for the first six months of 2002 because our income before income taxes was sufficiently low such that our excess percentage depletion significantly reduced the effective rate.

 

Cumulative Change in Accounting Principle. Effective January 1, 2003, we adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” This statement generally applies to legal obligations associated with the retirement of long-lived assets and requires us to recognize the fair value of asset retirement obligations in our financial statements by capitalizing that cost as a part of the cost of the related asset. This statement applies directly to the plug and abandonment liabilities associated with our net working interest in well bores. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to accretion expense. The liability is discounted using a credit-adjusted risk-free rate of approximately 7%. If the obligation is settled for other than the carrying amount, a gain or loss is recognized on settlement. Upon adoption of SFAS No. 143, we recorded an increase to our discounted abandonment liability of $16.4 million, increased proved property cost by $10.1 million and recognized a one-time cumulative effect charge of $3.9 million (net of a deferred tax benefit of $2.4 million).

 

Net Income. Net income increased from $0.2 million for the first six months of 2002 to $10.6 million for the first six months of 2003. The primary reasons for this increase include higher crude oil and natural gas prices between periods and an increase in volumes sold, partially offset by higher lease operating, tax and general and administrative expense due to our growth.

 

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Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

 

Oil and Natural Gas Sales. Oil and natural gas sales revenue decreased approximately $2.6 million to $122.7 million in 2002. Natural gas sales decreased $6.8 million, while oil sales increased $4.2 million. The natural gas sales decrease was caused by a 16% decline in the average realized natural gas price from $3.82 Mcf in 2001 to $3.21 Mcf in 2002, partially offset by an increase in natural gas production of 1.6 Bcf in 2002. The oil sales increase was caused by a sales volume increase of 200,000 Bbls in 2002, partially offset by a 2% decline in the average realized oil price from $23.85 in 2001 to $23.35 in 2002. The volume increase for oil and natural gas was due to $265 million of capital expenditures during 2001 and 2002.

 

Loss on Oil and Natural Gas Hedging Activities. We hedged 8% of our natural gas volumes during 2002, incurring a hedging loss of $0.2 million, and 11% of our natural gas volumes during 2001, incurring a gain of $1.6 million. We hedged 35% of our oil volumes during 2002, incurring a hedging loss of $3.0 million, and 17% of our oil volumes during 2001, incurring a gain of $0.7 million.

 

Gain (Loss) on Sale of Oil and Natural Gas Properties. In 2002, we divested only one property, realizing a gain of $1.0 million, while in 2001, we divested several properties, realizing total sales gains of $11.7 million.

 

Lease Operating Expenses. Our lease operating expenses per Mcfe increased from $0.92 in 2001 to $0.93 in 2002. The increase resulted from acquisitions during 2002 that caused a larger portion of our operations to be located in Michigan and the Williston Basin, where weather conditions, sulfur content and remote locations create higher operating costs.

 

Production Taxes. Production taxes as a percentage of oil and natural gas sales were 6.0% in 2002 and 5.2% in 2001. The increase in the effective rate resulted from additional property purchases in the states of North Dakota and Montana, where effective production tax rates are higher on average than other areas where we own significant producing properties.

 

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense in 2001 included a $9.0 million reduction related to the abandonment liability for the Point Arguello platform located offshore from California. During 2001, we received a revised and more detailed dismantlement plan from the operator. The $9.0 million reduction of liability was credited against depreciation, depletion and amortization expense since the liability was initially created by charges to depreciation, depletion and amortization expense. Without this credit, our depreciation, depletion and amortization expense charge for 2001 would have been $35.9 million. The increase to $43.6 million of depreciation, depletion and amortization expense in 2002 was a result of increasing sales volumes and an increased rate from $1.11 per Mcfe in 2001 to $1.24 per Mcfe in 2002.

 

Exploration Costs. Exploration costs increased $1.0 million to $1.8 million for 2002 compared with $0.8 million for 2001. The increase was partially the result of a $420,000 charge for an exploratory dry hole in 2002. In addition, we spent $302,000 in 2002 for the further development and processing of our geophysical library.

 

General and Administrative Expenses. General and administrative expenses increased 9.5% or $1.1 million from $10.9 million in 2001 to $12.0 million in 2002. This increase was related to increases in compensation expense associated with increased personnel required to administer our growth and to general cost inflation.

 

Interest Expense. Interest expense increased $0.7 million to $10.9 million in 2002 compared to $10.2 million in 2001. The increase was due to higher average debt levels in 2002 to fund our growth, partially offset by a lower effective interest rate.

 

Income Tax Expense. Our effective tax rate before tax credits was 36.8% in 2002 and 36.2% in 2001. In 2001, we were able to reduce our tax expense by $6.6 million due to the recording of Section 29 tax

 

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credits. In 2002, we generated $5.4 million of Section 29 credits that we were not able to be offset against tax expense. We expect these credits to be utilized in the future by Alliant Energy and that Alliant Energy will compensate us for such use under our tax separation and indemnification agreement. Under current generally accepted accounting principles, the recording of the tax credits are required to be charged as additional paid-in capital rather than as a decrease to our 2002 income tax expense. Section 29 of the Internal Revenue Code expired December 31, 2002. Therefore, unless additional legislation is passed, Section 29 credits will not be available in periods subsequent to 2002.

 

Net Income. Net income decreased from $41.2 million in 2001 to $7.7 million in 2002. The primary reasons were a $19.0 million decline in revenues, a $23.5 million increase in expenses and the inability to recognize $5.4 million of tax credits as a reduction of tax expense. The revenue decrease was caused by a decline in oil and natural gas prices between years and $10.7 million less gains from the sales of properties in 2002. The expense increase was caused by the $9.0 reduction to 2001 depreciation, depletion and amortization related to the adjustment of the Point Arguello abandonment liability and cost increases in all other categories to operate and administer the property acquisitions during 2001 and 2002.

 

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

 

Oil and Natural Gas Sales. Oil and natural gas sales revenue increased $18.3 million from $107.0 million to $125.3 million in 2001. Natural gas sales increased $10.4 million and oil sales increased $7.9 million. The natural gas sales increase was the result of a 9% increase in the average realized natural gas price from $3.51 Mcf in 2000 to $3.82 Mcf in 2001 and an increase in natural gas production of 2.9 Bcf in 2001. The oil sales increase was caused by a sales volume increase of 500,000 Bbls in 2001, partially offset by a 11% decline in the averaged realized oil price from $26.96 in 2000 to $23.85 in 2001. The volume increase for oil and natural gas was due to $239 million of capital expenditures during 2000 and 2001.

 

Gain (Loss) on Oil and Natural Gas Hedging Activities. We incurred a hedging gain of $2.3 million during 2001 and incurred a hedging loss of $3.8 during 2000. During 2001 we hedged 11% of our natural gas volumes, incurring a gain of $1.6 million, and 17% of our oil volumes, incurring a gain of $0.7 million. In 2000, we hedged approximately 20% of our oil volume incurring a loss of $3.8 million.

 

Gain on Sale of Oil and Natural Gas Properties. In 2001 and 2000, we divested several properties, realizing total gains of $11.7 million in 2001 and $7.7 million in 2000.

 

Lease Operating Expenses. Our lease operating expenses per Mcfe increased from $0.90 in 2000 to $0.92 in 2001. The increase resulted from inflation and higher costs in the oil and natural gas business in 2001 as subcontractors, vendors and oil field operators raised prices for services and equipment in the face of a sharp increase in demand for their products and services.

 

Production Taxes. Production taxes as a percentage of oil and natural gas sales were 5.2% in 2001 and 5.0% in 2000. The increase in the effective rate resulted from additional property purchases in the state of North Dakota, where effective production tax rates are higher on average than other areas where we own significant producing properties.

 

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense in 2001 included a $9.0 million reduction related to the abandonment liability for the Point Arguello platform located offshore California. During 2001, we received a revised and more detailed dismantlement plan from the operator. The $9.0 million reduction of liability was credited against depreciation, depletion and amortization expense since the liability was initially created by charges to depreciation, depletion and amortization expense. Without this credit, our depreciation, depletion and amortization expense for 2001 would have been $35.9 million. The increase from $21.5 million of depreciation, depletion and amortization expense in 2000 was a result of increasing sales volumes and an increased rate from $0.82 per Mcfe in 2000 to $1.11 per Mcfe in 2001. The rate change was the result of

 

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management reducing its estimate of future oil and natural gas reserve quantities in one large producing area and dry hole costs associated with drilling of developmental wells.

 

Exploration Costs. Exploration costs decreased $0.3 million to $0.8 million for 2001 compared with $1.1 million for 2000. The decrease was the result of extra discretionary spending in 2000 to further the development and processing of our geophysical library.

 

General and Administrative Expenses. General and administrative expense increased $4.7 million from $6.3 million in 2000 to $10.9 million in 2001. This increase was related to increases in compensation expense associated with increased personnel required to administer our growth and to general cost inflation.

 

Interest Expense. Interest expense increased $2.7 million to $10.2 million in 2001 compared to $7.5 million in 2000. The increase was due to higher average debt levels in 2001 to fund our growth, partially offset by lower effective interest rates.

 

Income Tax Expense. Our effective tax rate before tax credits was 36.2% in 2001 and 37.6% in 2000. We were able to reduce our tax expense by $6.6 million in 2001 and $5.2 million in 2000 through the use of Section 29 tax credits.

 

Net Income. Net income increased from $33.7 million in 2000 to $41.2 million in 2001. The primary reason was a $28.5 million increase in revenues, partially offset by a $19.5 million increase in expenses. The revenue increase was caused primarily by an increase in sales volumes between years and a $4.0 million increase in gains from sales of properties in 2001. The expense increase was caused by cost increases in all other categories to operate, administer and finance our property acquisitions during 2000 and 2001.

 

Liquidity and Capital Resources

 

Historical Financing. As an indirect wholly-owned subsidiary of Alliant Energy, our liquidity has historically been directly related to the financial resources and capital expenditure allocations of Alliant Energy. In the past, Alliant Energy provided a capital expenditure budget and funded net cash requirements beyond cash generated from operations. Until our $185.0 million bank borrowing in December of 2002 which is described below, we did not rely on outside sources of borrowing or capital. Instead, we received advances on Alliant Energy’s intercompany credit facility, which primarily covered the shortfall between our capital expenditures (including acquisitions) and cash generated from operations and property sales. The table below describes net borrowings and payments on Alliant Energy’s intercompany credit facility.

 

     Year Ended December 31,

     Six Months
Ended June 30,
2003
     Total  
     2000    2001    2002        
    

  

  


  


  


Alliant Energy (1)

   $ 62.9    $ 23.9    $ (83.1 )    $ (80.9 )    $ (77.2 )

Whiting credit facility

     —        —        185.0        —          185.0  
    

  

  


  


  


Total

   $ 62.9    $ 23.9    $ 101.9      $ (80.9 )    $ 107.8  
    

  

  


  


  



(1)   In March 2003, Alliant Energy converted its remaining loan plus accrued interest of $80.9 million to “paid in capital” of Whiting.

 

In November 2002, Alliant Energy announced that its board of directors had approved various strategic actions, including the sale of, or other exit strategies for, a number of its non-regulated businesses, including Whiting Petroleum Corporation. In connection with those strategic actions and certain financing requirements, on December 20, 2002, we entered into a $350.0 million credit agreement with a syndicate of banks. The credit agreement provided for an initial borrowing base of $200.0 million with an immediate draw of $185.0 million. This $185.0 million loan was used to repay a portion of our

 

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$266.0 million intercompany debt obligation to Alliant Energy. In March 2003, Alliant Energy converted the remaining $81.0 million intercompany debt balance into our equity.

 

Credit Facility. The initial borrowing base of $200.0 million under the credit agreement is based on the collateral value of proved reserves and is subject to redetermination on May 1 and November 1 of each year. The borrowing base was increased to $210.0 million effective June 11, 2003. As of June 30, 2003, we had borrowed $185.0 million under the credit facility, with $25.0 million of undrawn capacity. If the borrowing base is determined to be lower than the outstanding principal balance then drawn, we must immediately pay the difference. The credit agreement provides for interest only payments until December 20, 2005 when the entire amount borrowed is due. Interest accrues, at our option, at either (1) the base rate plus a margin where the base rate is defined as the higher of the federal funds rate plus 0.5% or the prime rate and the margin varies from 0.25% to 1.0% depending on the ratio of the amounts borrowed to the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.5% to 2.25% depending on the ratio of the amounts borrowed to the borrowing base. At December 31, 2002, all amounts outstanding under the credit agreement bore interest at an effective interest rate of 3.6% per year through August 6, 2003. The credit agreement has covenants that restrict the payment of cash dividends, borrowings, sale of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires us to maintain certain debt to EBITDAX (as defined in our credit agreement) ratios and a working capital ratio. The credit agreement also precludes us from providing any cash to Alliant Energy except for services rendered on an arms-length basis or for income taxes. We were in compliance with our covenants under the credit agreement as of June 30, 2003. The credit agreement is secured by a first lien on substantially all of our assets.

 

Cash Flows. Our primary sources of cash have been cash flows from operations, debt financing and the sale of non-strategic properties. During the three years ended December 31, 2002 we generated $167.2 million from operating activities, financed $188.7 through debt obligations and received proceeds from the sale of non-strategic properties of $50.6 million for a total of $406.5 million. We primarily used this cash generation to fund our capital expenditures aggregating $404.1 million over the three years ($332.6 million of which was spent on acquisitions). At June 30, 2003, we had $31.2 million of cash and $44.7 million of working capital compared to December 31, 2002 when our cash position was $4.8 million and working capital was $19.3 million.

 

We continually evaluate our capital needs and compare them to our capital resources. Our budgeted capital expenditures during 2003 are a combined $98.0 million for acquisitions and further development of our property base. We expect to fund these expenditures from internally generated cash flow during 2003. Expenditures in excess of $98.0 million we believe could be financed through additional borrowings under our credit facility or otherwise, issuances of additional equity or development with industry partners. The level of capital expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among others.

 

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Schedule of Contractual Obligations. The following table summarizes our future estimated principal and minimum debt and lease payments for periods subsequent to June 30, 2003 (in millions).

 

Year


   Long-Term Debt

   Operating Lease

   Total Cash Obligation

2003

     —      $ 0.5    $ 0.5

2004

     —      $ 1.0    $ 1.0

2005

   $ 185.0    $ 0.8    $ 185.8

Total

   $ 185.0    $ 2.3    $ 187.3

 

Off-Balance Sheet Arrangements. As of June 30, 2003, we had no off-balance sheet arrangements.

 

New Accounting Policies

 

In June 2001, the Financial Accounting Standards Board, or the FASB, issued Statement of Financial Accounting Standards, or SFAS, No. 141, “Business Combinations,” which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite-lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. We did not change or reclassify the contractual mineral rights included in our oil and natural gas properties on the balance sheet upon adoption of SFAS No. 142. We believe that the current accounting of such mineral rights as part of crude oil and natural gas properties is appropriate under the successful efforts method of accounting. However, there is an alternative view that reclassification of mineral rights to an intangible asset may be necessary. This issue is currently being considered by the SEC. We do not believe that the ultimate outcome of this issue will have a significant impact on our results of operations or financial condition.

 

Effective January 1, 2003, we adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” This statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires us to recognize the fair value of asset retirement obligations in our financial statements by capitalizing that cost as a part of the cost of the related asset. In regards to us, this statement applies directly to the plug and abandonment liabilities associated with our net working interest in well bores. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to accretion expense. The liability is discounted using a credit-adjusted risk-free rate of approximately 7%. If the obligation is settled for other than the carrying amount, a gain or loss is recognized on settlement. Upon adoption of SFAS No. 143, we recorded an increase to our discounted abandonment liability of $16.4 million, increased proved property cost by $10.1 million and recognized a one-time cumulative effect charge of $3.9 million (net of a deferred tax benefit of $2.4 million). We have an additional $4.2 million abandonment liability relating to our retained obligation with respect to the Point Arguello facility.

 

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, “Amendment of FASB Statement No. 13, and Technical Corrections.” This Statement rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements.” This Statement also rescinds SFAS No. 44, “Accounting for Intangible Assets of Motor Carriers.” This Statement amends SFAS No 13, “Accounting for Leases,” to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have

 

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economic effects that are similar to sale-leaseback transactions. This Statement also amends other existing authoritative pronouncements to make various technical corrections, clarifying meanings, or describe their applicability under changed conditions. The provisions of this Statement will be applied in fiscal years beginning after May 15, 2002. The adoption of this Statement had no impact on our financial statements.

 

In June 2002 the FASB issued SFAS No. 146, “Accounting for Costs Associates with Exit or Disposal Activities.” This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. We do not believe that adoption of this Statement will have a material impact on our financial statements.

 

FASB Interpretation No. 45, or FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” was issued in November 2002 by the FASB. FIN 45 requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that the adoption of this statement had a material impact on our financial statements. Under the disclosure provisions, we agreed, as part of a 2002 purchase transaction, to share with the seller 50% of the actual price received for certain crude oil production in excess of $19.00 per barrel. The agreement runs through December 31, 2009 and contains a 2% price escalation per year. As a result, the sharing amount at January 1, 2003 increased to 50% of the actual price received in excess of $19.38 per barrel. Approximately 40,000 net barrels of crude oil per month are subject to this sharing agreement.

 

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” to amend and clarify financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. The changes in this statement require that contracts with comparable characteristics be accounted for similarly to achieve more consistent reporting of contracts as either derivative or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and will be applied prospectively. We do not believe that adoption of this Statement will have a material impact on our financial statements.

 

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” to classify certain financial instruments as liabilities in statements of financial position. The financial instruments are mandatorily redeemable shares, which the issuing company is obligated to buy back in exchange for cash or other assets, put options and forward purchase contracts, instruments that do or may require the issuer to buy back some of its shares in exchange for cash or other assets, and obligations that can be settled with shares, the monetary value of which is fixed, tied solely or predominantly to a variable such as a market index, or varies inversely with the value of the issuers’ shares. Most of the guidance in SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. We do not believe that adoption of this Statement will have a material impact on our financial statements.

 

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Critical Accounting Policies and Estimates

 

Our discussion of financial condition and results of operation is based upon the information reported in our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 1 to our consolidated financial statements included in this prospectus. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

 

Revenue Recognition. We predominantly derive our revenue from the sale of produced crude oil and natural gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received; however, differences have been insignificant.

 

Hedging. Our crude oil and natural gas hedges are designed to be treated as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity.” This policy is significant since it impacts the timing of revenue recognition. Under this pronouncement, the majority of our hedging gains or losses are recorded in the month the contracts settle. We reflect this as an adjustment to revenue through the “Gain (loss) on oil and gas hedging activities” line item in our consolidated income statements. If our hedges did not qualify for cash flow hedge treatment, then our consolidated income statements could include large non-cash fluctuations in this line item, particularly in volatile pricing environments, as our contracts are marked to their period end market values.

 

Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and natural gas production costs. All of our properties are located within the continental United States and the Gulf of Mexico.

 

Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this prospectus are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:

 

  • ¨   the quality and quantity of available data;

 

  • ¨   the interpretation of that data;

 

  • ¨   the accuracy of various mandated economic assumptions; and

 

  • ¨   the judgments of the persons preparing the estimates.

 

Our proved reserve information included in this prospectus is based on estimates prepared by Ryder Scott Company, Cawley, Gillespie & Associates, Inc., R.A. Lenser & Associates, Inc. and our engineering staff. Estimates prepared by others may be higher or lower than our estimates. Because

 

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these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.

 

Impairment of Oil and Natural Gas Properties. We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. We provide for impairments on undeveloped property when we determine that the property will not be developed or a permanent impairment in value has occurred. Impairments of proved producing properties are calculated by comparing the properties future net undiscounted cash flow using escalating prices to the net recorded book cost. In the event that calculated future net revenues do not exceed book cost, the property is written down to our estimate of fair value. Different pricing assumptions or discount rates could result in a different calculated impairment. We have not recorded any property impairments since 1999.

 

Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.” Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

 

Effects of Inflation and Pricing

 

We experienced increased costs during 2001 and 2002 due to increased demand for oil field products and services. The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, continued high prices for oil and natural gas could result in increases in the cost of material, services and personnel.

 

Tax Separation and Indemnification Agreement

 

In connection with the share exchange and this offering, Whiting Petroleum Holdings, Inc., Whiting Petroleum Corporation, Alliant Energy and Resources will enter into a tax separation and indemnification agreement, which is described under “Relationship with Alliant Energy Corporation—Tax Separation and Indemnification Agreement.” Pursuant to this agreement, we and Alliant Energy will make an election under Section 338(h)(10) of the Internal Revenue Code, with the effect that the tax basis of the assets of Whiting Petroleum Corporation will be increased to the deemed purchase price of the assets, and an amount equal to such increase will be included in income in the consolidated federal income tax return filed by Alliant Energy. We expect that this additional basis will result in increased future income tax deductions and, accordingly, reduced income taxes payable by us. Pursuant to the tax separation and indemnification agreement, we will pay Alliant Energy 90% of any tax benefits realized by us, on a quarterly basis, generally calculated by comparing our actual taxes to the taxes that would have been owed by us had the increase in basis not occurred. In the event any taxing authority successfully challenges any deductions reflected in a tax benefit payment to Alliant Energy, Alliant Energy will reimburse us for 90% of the loss of the tax benefit and any related interest or penalties imposed upon us. The tax benefit payments to Alliant Energy should have no material effect on our earnings or cash flows, which

 

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should not be materially less than they would have been in the absence of the tax separation and indemnification agreement and additional tax basis.

 

The tax separation and indemnification agreement provides that the tax benefit calculation for any period ending after the completion of the offering will not be less than the tax benefit calculated without giving effect to any items of income, expense, loss, deduction, credit or related carryovers or carrybacks from businesses conducted by us or relating to our assets and liabilities other than those businesses conducted by us and those assets and liabilities existing immediately prior to the completion of the offering. The tax separation and indemnification agreement further provides that we will not enter into any transaction a significant purpose of which is to reduce the amount payable to Alliant Energy under the tax separation and indemnification agreement.

 

Quantitative and Qualitative Disclosure About Market Risk

 

Commodity Price Risk

 

We periodically enter into derivative contracts to manage our exposure to oil and natural gas price volatility. Our derivative contracts have traditionally been with no-cost collars, although we evaluate other forms of derivative instruments as well. Our derivative contracts have historically qualified for cash flow hedge accounting under SFAS No. 133. This accounting treatment allows the aggregate change in fair market value to be recorded as other comprehensive income on the consolidated balance sheet. Recognition in the consolidated income statement occurs in the period of contract settlement. We generally limit our aggregate hedge position to less than 50% of expected production, but will hedge larger percentages of total expected production in certain circumstances. We do not intend to hedge in excess of 60% of our expected production. We also seek to diversify our hedge position with various counterparties where we have clear indications of their current financial strength.

 

Our hedging arrangements have the effect of locking in for specified periods the prices we will receive for the volumes and commodity to which the hedge relates. Consequently, while these hedges are designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price increases. For contracts in place at June 30, 2003, a hypothetical $0.10 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amount of 4.2 million MMbtu covered by our remaining natural gas no-cost collars would cause a change in the gain (loss) on hedging activities of $420,000 in 2003. None of our current hedges extend beyond December 31, 2003.

 

Our outstanding hedges at June 30, 2003 are summarized below:

 

Commodity


 

Original Period

Covered


 

Monthly Volume


 

NYMEX


   

Oil (bbls)


 

Natural Gas (MMbtu)


 

Floor/Ceiling


Crude Oil

  08/2002 to 07/2003   17,000       $24.00/$26.15

Natural Gas

  05/2003 to 12/2003       100,000   4.70/5.66

Natural Gas

  05/2003 to 12/2003       100,000   4.70/5.63

Natural Gas

  07/2003 to 12/2003       250,000   4.70/5.64

Natural Gas

  07/2003 to 12/2003       250,000   4.70/5.67

 

We have also entered into fixed price marketing contracts directly with end users for a portion of the natural gas we produce in Michigan. The contracts covering 111,000 MMbtu per month through 2011 and 2012 have built-in pricing escalators of 4% per year. The remaining contracts expire at December 31, 2003.

 

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Our outstanding fixed price marketing contracts at June 30, 2003 are summarized below:

 

Commodity


 

Period


 

Monthly Volume MMbtu


 

Fixed Price


Natural Gas

  01/2002 to 12/2003   210,000   $3.25

Natural Gas

  09/2002 to 12/2003   70,000   3.62

Natural Gas

  01/2002 to 12/2011   51,000   3.91

Natural Gas

  01/2002 to 12/2012   60,000   3.46

 

As part of a 2002 purchase transaction, we agreed to share with the seller 50% of the actual price received for certain crude oil production in excess of $19.00 per barrel. The agreement runs through December 31, 2009 and contains a 2% price escalation per year. As a result, the sharing amount at January 1, 2003 increased to 50% of the actual price received in excess of $19.38 per barrel. Currently, approximately 40,000 net barrels of crude oil per month (19% of June 2003 net crude oil production) are subject to this sharing agreement.

 

Interest Rate Risk

 

Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the $185 million outstanding under our credit facility. The credit facility allows us to fix the interest rate for all or a portion of the principal balance for a period up to six months. To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. At June 30, 2003, the interest rate on the entire $185 million outstanding principal balance under our credit facility was fixed at 3.6% through August 6, 2003. At June 30, 2003, the carrying amount approximated fair market value. Assuming constant debt levels, the cash flow impact for the remainder of 2003 resulting from a 100 basis point change in interest rates would be approximately $745,000 before taxes.

 

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BUSINESS AND PROPERTIES

 

About Our Company

 

We are engaged in oil and natural gas exploitation, acquisition and exploration activities primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan and Mid-Continent regions of the United States. Our focus is on maintaining a balanced portfolio of lower risk, long-lived oil and natural gas properties that provide stable cash flows to fund projects which we believe will generate an attractive rate of return.

 

Since our inception in 1980, we have built a strong asset base and achieved steady growth through both property acquisitions and exploitation activities. From January 1, 2000 through April 1, 2003, we increased our proved reserves from 194.1 Bcfe to 439.2 Bcfe, an average annual growth rate of 38.8%, at an average all-in finding cost of $1.00 per Mcfe. We spent approximately $165.4 million on capital projects during 2002, including $23.1 million for the drilling of 33 gross wells (24 successful completions and nine uneconomic wells) and $140.7 million for the acquisition of 157.4 Bcfe of proved reserves (estimated as of the date of acquisition). We expect to further develop these properties through drilling and enhanced recovery methods. We have budgeted approximately $98.0 million for capital expenditures in 2003, including $41.0 million for drilling and exploitation opportunities. We believe that our exploitation and acquisition expertise and our exploration inventory, together with our operating experience and efficient cost structure, provide us with substantial growth potential.

 

As of April 1, 2003, our estimated proved reserves had a pre-tax PV10% value of approximately $718.3 million, approximately 86.5% of which came from properties located in three states: Texas, North Dakota and Michigan. Approximately 61.2% of our proved reserves are classified as PDP. Approximately 8.1% of our proved reserves are classified as PDNP, and approximately 30.7% are classified as PUD.

 

We have a balanced portfolio of oil and natural gas reserves, with approximately 51.5% of our proved reserves consisting of natural gas and approximately 48.5% consisting of oil. The following table summarizes our total net proved reserves and pre-tax PV10% value within our four core areas as of April 1, 2003, as well as our June 2003 average daily production.

 

Core Area


   Proved Reserves

  

Pre-Tax PV
10% Value

(In thousands)


  

June 2003

Average Daily Production


 
  

Oil

(MMbbl)


  

Natural

Gas

(Bcf)


  

Total

(Bcfe)


      MMcfe

   % Natural
Gas


 

Gulf Coast/Permian Basin

   5.0    87.7    117.9    $ 225,480    35.5    80 %

Rocky Mountains

   27.4    15.6    180.0      249,010    34.2    11 %

Michigan

   1.2    105.6    113.1      203,219    22.1    94 %

Mid-Continent

   1.3    13.8    21.8      30,452    6.4    68 %

Other

   0.5    3.7    6.4      10,100    3.1    70 %
    
  
  
  

  
  

Total

   35.4    226.4    439.2    $ 718,261    101.3    60 %
    
  
  
  

  
  

 

Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics. Our ratio of proved reserves to trailing 12 month production ending March 31, 2003 was approximately 11 years.

 

Business Strategy

 

Our goal is to generate an attractive return on capital employed for all of our investment opportunities. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing acquisitions of additional properties that we believe have above-average

 

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exploitation and development potential. Specifically, we have focused, and plan to continue to focus, on the following:

 

Developing and Exploiting Existing Properties. We believe that there is significant value to be created by drilling the numerous identified undeveloped opportunities on our properties. We own interests in a total of 512,000 gross and 204,000 net developed acres and operate approximately 85.2% of the net pre-tax PV10% value of our PUD reserves. Over the past three years, we have invested $68.4 million to participate in the drilling of 124 gross and 45.1 net wells at an average cost of $552,000 per gross well. The majority of these wells have been developmental wells, and 81% were successful completions. We expect to spend approximately 50% of our internally generated cash flow during 2003 to add additional reserves and production through developing and exploiting existing core properties. As of April 1, 2003, we had identified a total of 196 drilling locations on our properties. We have participated in the drilling of 24 gross wells and 11.8 net wells during the six months ended June 30, 2003, and we plan to drill an additional 66 wells during the remainder of 2003. We believe our inventory of proved development drilling locations or major recompletion opportunities on our existing properties is sufficient to sustain this level of activity for approximately three years.

 

Pursuing Profitable Acquisitions. We will continue to pursue acquisitions of properties that we believe to have above-average exploitation and development potential. We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have a dedicated team of management and engineering and geoscience professionals who both identify and evaluate acquisition opportunities and manage those properties once acquired. From January 1, 2000 through December 31, 2002, we completed 41 acquisitions at an aggregate cost of approximately $332.7 million, representing approximately 369.6 Bcfe of proved reserves (at an average cost of $0.90 per Mcfe or $5.40 per Boe). During 2002, we acquired 157.4 Bcfe of proved reserves for an aggregate cost of $140.7 million and an average cost of $0.89 per Mcfe ($5.36 per Boe).

 

Focusing on High Return Operated and Non-Operated Properties. Based on our rate of return criteria, we have historically acquired operated as well as non-operated properties. We will continue to acquire both operated and non-operated interests to the extent they meet our return criteria. While we believe that a number of our competitors focus primarily, if not exclusively, on acquisitions of operated reserves, our track record demonstrates that equivalent and often greater returns can be achieved through the acquisition of non-operated interests. In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data that in some cases leads to further acquisitions in the same region, whether on an operated or non-operated basis.

 

Controlling Costs through Efficient Operation of Existing Properties. We operate approximately 58.4% of the pre-tax PV10% value of our reserves, which we believe enables us to better manage expenses, capital allocation and the decision-making processes related to our exploitation and exploration activities. For the year ended December 31, 2002, our lease operating expense per Mcfe averaged $0.93 and general and administrative costs averaged $0.34 per Mcfe produced, net of reimbursements.

 

Competitive Strengths

 

We believe that our key competitive strengths lie in our diversified asset base, our experienced management team and our commitment to efficient utilization of new technologies.

 

Diversified Asset Base. We have interests in 1,573 properties in 16 states across our four core geographical areas of the United States. This property base, as well as our continuing business strategy of acquiring and developing properties with above-average potential in our core operating areas, presents us with a large number of opportunities for successful development and exploitation.

 

Experienced Management Team. Our management team averages 26 years of experience in the oil and natural gas industry. Our personnel have extensive experience in each of our core geographical areas and in all of our operational disciplines. In addition, each of our acquisition professionals has at least

 

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20 years of experience in the evaluation, acquisition and operational assimilation of oil and natural gas properties.

 

Commitment to Technology. In each of our core operating areas, we have accumulated detailed geologic and geophysical knowledge and have developed significant technical and operational expertise. In recent years, we have developed considerable expertise in conventional and 3-D seismic imaging and interpretation. Our technical team has access to approximately 571 square miles of 3-D seismic inventory, which we have assembled primarily over the past five years. A team with access to state-of-the-art geophysical/geological computer applications and hardware analyzes this information. Computer applications, such as the WellView® software system, enable us to quickly generate reports and schematics on our wells. In addition, our information systems enable us to update our production databases through daily uploads from hand-held computers in the field. This technology and expertise has greatly aided our pursuit of attractive development projects in our 386,000 gross undeveloped acres (188,000 net), located in North Dakota, Montana, Kansas and Texas.

 

Recent Development and Acquisition Activity

 

We have a capital budget of approximately $98.0 million for 2003, including $41.0 million for exploiting and drilling on our existing core properties and $57.0 million for the acquisition and subsequent development of additional oil and natural gas properties. During the six months ended June 30, 2003, we invested $16.7 million in our drilling projects. We have budgeted $24.3 million for drilling projects for the remainder of 2003.

 

Our major recent and ongoing acquisition and development projects include the following:

 

Williston Basin. The Williston Basin is the primary focus of our Rocky Mountains operations. We operate 45 fields in the North Dakota and Montana portions of the Williston Basin, with operated and non-operated interests in 916 wells and a 53% average working interest. As of April 1, 2003, our properties in the Williston Basin contained 173.7 Bcfe (6.8% natural gas) of net proved reserves with a net pre-tax PV10% value of $239.0 million. Our major development projects in the Williston Basin include the Big Stick (Madison) Unit, the North Elkhorn Ranch Unit and the Red Water (Bakken) field. We believe we have significant opportunities in the Bakken, Nisku and Mission Canyon Formations in the Golden Valley area of western North Dakota, as well as in several Red River Formation prospects in the Tolksdorf area of northern Richland County, Montana. We have drilled or participated in the drilling of seven wells in the Williston Basin during the first six months of 2003, six of which were successful, and we plan to drill an additional eleven wells during the remainder of the year.

 

Gulf Coast/Permian Basin. In the Gulf Coast/Permian Basin region, we have major operated development projects in the Stuart City Reef Trend and the Vicksburg Trend. In the Stuart City Reef Trend along the upper Texas Gulf Coast, we have interests in five fields that produce natural gas, primarily from the Edwards Limestone. We have operated and non-operated interests in 37 wells, with a 65% average working interest. As of April 1, 2003, our properties in the Stuart City Reef Trend contained 35.3 Bcfe (92% natural gas) of net proved reserves with a net pre-tax PV10% value of $49.4 million. We have significant ongoing development activity in the Yoakum, Word North and Kawitt fields. We have drilled two successful wells in 2003 and plan to drill an additional four wells during the remainder of the year.

 

In the Vicksburg Trend, we produce natural gas from the Vicksburg and Frio Formations in four fields located in Nueces and San Patricio Counties, Texas. We have significant ongoing operations in the Agua Dulce field, where we operate eleven wells with a 99.8% average working interest. As of April 1, 2003, our properties in this field contained 20.4 Bcfe (90.7% natural gas) of net proved reserves, with a net pre-tax PV10% value of $60.2 million. Our development plans in this field include a total of four wells this year, of which two successful wells have been drilled to date.

 

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Michigan and Mid-Continent. In northern Michigan, we have proved reserves and development potential in 56 multi-well Antrim Shale natural gas development projects. We have committed to participate in the drilling of 38 Antrim Shale wells on these projects in 2003. We have proved undeveloped reserves with significant upside potential in the South Buckeye and Clayton fields, which produce natural gas from the Prairie du Chien Formation.

 

In the Cherokee Basin of southeastern Kansas, we are in the early stages of developing a coalbed methane project in which we have drilled eight test wells designed to determine the thickness and natural gas content of coal seams within the Cherokee Formation on our 91,284 acre leasehold. We are currently in the beginning stages of installing a pilot program designed to determine the productive potential of our leasehold.

 

The table below describes the increase in our proved reserves that we have achieved for some of the projects described above:

 

Acquisition


  

Date Acquired


   Proved Reserves

  

%
Change


      At Acquisition (1)

   At April 1, 2003

  
      MMboe

   Bcfe

   MMboe

   Bcfe

  

Williston Basin

   August 1999 through February 2002    24.1    144.7    29.0    173.7    20.0

Stuart City Reef Trend

   June 2001    4.6    27.7    5.9    35.3    27.4

Agua Dulce Field

   March 2002    2.8    16.9    3.4    20.4    20.7

(1)   Adjusted for production through April 1, 2003.

 

Our Relationship with Alliant Energy

 

Whiting Petroleum Corporation is currently an indirect wholly-owned subsidiary of Alliant Energy, an energy services provider engaged primarily in regulated utility operations in the Midwest, with other non-regulated domestic and international operations. In November 2002, Alliant Energy announced that its board of directors had approved various strategic actions designed to maintain a strong credit profile, strengthen its balance sheet and position it for improved long-term financial performance. These strategic actions include the sale of, or other exit strategies for, a number of its non-regulated businesses, including Whiting Petroleum Corporation. This offering of our common stock pursuant to this prospectus is intended to facilitate Alliant Energy’s plan to exit its involvement in the exploration and production business. Accordingly, we will receive no proceeds from this offering.

 

After this offering, we expect that Alliant Energy will beneficially own approximately % of our outstanding common stock. Alliant Energy currently intends to divest its remaining interest in us during the first half of 2004, subject to market conditions. See “Stock Ownership of Management and Selling Stockholders” and “Risk Factors—Risks Related to Our Relationship with Alliant Energy.” In addition, we and Alliant Energy will enter into various agreements that will govern our relationship with Alliant Energy after the offering. As a result of these agreements and Alliant Energy’s significant ownership of our common stock, Alliant Energy will be in a position to control or influence substantially the manner in which our business is operated and the outcome of stockholder votes on the election of directors and other matters. See “Relationship with Alliant Energy Corporation” for a description of these agreements. We will not have any material commercial relationships with Alliant Energy after this offering.

 

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Proved Reserves

 

Our 439.2 Bcfe of proved reserves, which consist of approximately 51.5% natural gas and 48.5% oil, are summarized below as of April 1, 2003 on a net pre-tax PV10% value basis. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC) since January 1, 2002.

 

Total Net Pre-Tax PV10% Value (April 1, 2003): $718.3 million

 

LOGO   LOGO

 

Although our proved reserves are geographically diverse, as shown in the chart below as of April 1, 2003, approximately 87% of the value of our proved reserves on a pre-tax PV10% basis is located in three states: North Dakota, Texas and Michigan. As of April 1, 2003, our Williston Basin (North Dakota and Montana) proved reserves had a net pre-tax PV10% value of $239.0 million ($216.5 million in North Dakota), our Texas proved reserves had a net pre-tax PV10% value of $201.4 million and our Michigan proved reserves had a net pre-tax PV10% value of $203.2 million. Collectively, these three areas represented approximately $643.6 million, or 89.6%, of the total proved reserve net pre-tax PV10% value of $718.3 million as of April 1, 2003.

 

Total Net Pre-Tax PV10% Value (April 1, 2003): $718.3 million

 

LOGO

 


*   “Other” includes Montana, Colorado, Wyoming, Ohio, Louisiana, New Mexico, Oklahoma, Arkansas and Kansas.

 

As of April 1, 2003, approximately 65.3% of the 439.2 Bcfe of proved reserves have been classified as proved developed producing, or PDP. Proved developed non-producing, or PDNP, and proved undeveloped, or PUD, reserves constitute 5.7% and 29.0%, respectively, of the proved reserves as of April 1, 2003.

 

Total proved reserves had a net pre-tax PV10% value as of April 1, 2003 of approximately $718.3 million, 61.2% or $439.3 million of which is associated with the PDP reserves. An additional $59.0 million is associated with the PDNP reserves ($498.3 million for total proved developed reserves, or 69.4% of total proved reserves’ pre-tax PV10% value) and $220.0 million is associated with PUD reserves. Of the $71.7 million of capital expenditures included in our reserve report for development activity, we expect to spend $63.9 million over a three-year period beginning in 2003 relating to an additional 152.4 Bcfe of PDNP and PUD reserves.

 

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Our proved reserves as of April 1, 2003 are summarized in the table below.

 

    

Oil

(MBbl)


  

Natural Gas

(MMcf)


  

Total

(Bcfe)


  

% of Total

Proved


   

Pre-tax PV10%

(In thousands)


  

Future Capital
Expenditures

(In thousands)


Gulf Coast/

Permian Basin:

                                  

PDP

   3,577.3    44,201.1    65.7    15.0 %   $ 129,721.9    $ 2,454.4

PDNP

   336.2    5,017.1    7.0    1.6 %     14,377.1      1,767.0

PUD

   1,130.4    38,468.7    45.3    10.3 %     81,380.6      28,507.4
    
  
  
  

 

  

Total Proved

   5,043.9    87,686.9    118.0    26.9 %   $ 225,479.6    $ 32,728.8
    
  
  
  

 

  

Rocky Mountains:

                                  

PDP

   17,886.4    11,751.7    119.1    27.1 %   $ 151,017.9    $ 604.6

PDNP

   639.4    89.2    3.9    0.9 %     5,014.2      419.1

PUD

   8,863.8    3,778.6    57.0    13.0 %     92,977.8      22,716.9
    
  
  
  

 

  

Total Proved

   27,389.6    15,619.5    180.0    41.0 %   $ 249,009.9    $ 23,740.6
    
  
  
  

 

  

Michigan:

                                  

PDP

   411.2    73,021.5    75.5    17.2 %   $ 120,211.3      —  

PDNP

   310.6    11,284.9    13.1    3.0 %     37,386.1      2,205.9

PUD

   528.2    21,270.8    24.4    5.6 %     45,621.9      15,562.9
    
  
  
  

 

  

Total Proved

   1,250.0    105,577.2    113.0    25.8 %   $ 203,219.3    $ 17,768.8
    
  
  
  

 

  

Mid-Continent:

                                  

PDP

   1,269.5    12,608.8    20.2    4.6 %   $ 28,340.3      —  

PDNP

   54.2    1,227.2    1.6    0.4 %     2,111.7      321.5
    
  
  
  

 

  

Total Proved

   1,323.7    13,836.0    21.8    5.0 %   $ 30,452.0    $ 321.5
    
  
  
  

 

  

Other(1):

                                  

PDP

   448.0    3,659.5    6.4    1.5 %   $ 10,008.8      —  

PDNP

   0.8    46.5    0.1    0.0 %     91.1      236.0
    
  
  
  

 

  

Total Proved

   448.8    3706.0    6.5    1.5 %     10,099.9      236.0
    
  
  
  

 

  

Total Corporate:

                                  

PDP

   23,592.4    145,242.6    286.8    65.3 %   $ 439,300.2    $ 3,059.0

PDNP

   1,341.2    17,664.9    25.7    5.9 %     58,980.2      4,949.5

PUD

   10,522.4    63,518.1    126.7    28.8 %     219,980.3      66,787.2
    
  
  
  

 

  

Total Proved

   35,456.0    226,425.6    439.2    100.0 %   $ 718,260.7    $ 74,795.7
    
  
  
  

 

  


(1)   Includes our partnership interests.

 

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Production

 

Our estimated June 2003 average daily production is summarized below. These charts indicate the percentage of our estimated June 2003 average daily production of 101.3 MMcfe/d attributable to each geographic region and to oil versus natural gas production.

 

Average Daily Production (June 2003): 101.3 MMcfe/d

 

LOGO   LOGO

 

As shown in the chart below, our estimated June 2003 average daily production of 101.3 MMcfe/d is predominantly focused in Texas (27.5%), North Dakota (29.2%) and Michigan (21.8%). Collectively, these three areas comprise 78.6%, or 79.5 MMcfe/d, of our estimated June 2003 average daily production.

 

Average Daily Production (June 2003): 101.3 MMcfe/d

 

LOGO


*   Other includes Oklahoma, Arkansas, Kansas, Wyoming, Ohio, Colorado, New Mexico, Louisiana and Montana.

 

Summary of Oil and Natural Gas Properties and Projects

 

Gulf Coast/Permian Basin

 

Our Gulf Coast/Permian Basin operations include assets in Texas, Louisiana and New Mexico. The Gulf Coast/Permian Basin region contributes 117.9 Bcfe (74.5% natural gas) of net proved reserves to our portfolio of operations, which represents 26.8% of our total net proved reserves. Approximately 93.0% of the proved reserves and 89.3% of the net pre-tax PV10% value of our Gulf Coast/Permian Basin operations are related to properties in Texas.

 

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Significant Gulf Coast/Permian Basin Operations

 

Stuart City Reef Trend. We operate five fields located along a regional geologic structure known as the Stuart City Reef Trend in Texas: the Word North, Sweet Home, Yoakum, Kawitt and Three Rivers fields. Natural gas production in the Stuart City Reef Trend is primarily from the Edwards Limestone at a depth of approximately 14,000 feet, with additional production from the Yegua, Wilcox, and Sligo Formations at depths between 7,000 and 16,000 feet. The natural gas column in the Edwards Limestone ranges between 150 and 600 feet thick, but these reservoirs are characterized by extremely low permeability and moderate porosity. The existing vertical wellbores are often ineffective in draining the Edwards natural gas reserves due to these particular reservoir properties. Horizontal and directional drilling technologies allow us to access up to three thousand feet of Edwards Limestone with a single well. In addition, these horizontal wells can often be drilled as horizontal re-entry wells from existing vertical wellbores, resulting in significant cost savings over drilling new wells. The application of these two techniques has resulted in significantly improved economic parameters for developing our Edwards Limestone natural gas reserves. During the first six months of 2003, we have drilled two successful wells in the Stuart City Reef Trend, and we plan to drill four additional wells during the remainder of the year.

 

Our three most significant fields located on the Stuart City Reef Trend are the Yoakum field, the Word North field and the Kawitt field.

 

The Yoakum field is a natural gas field located in DeWitt and Lavaca counties, Texas. This field was discovered in 1946 and currently has estimated ultimate recoverable natural gas of 44 Bcf. Currently, production is primarily from the Edwards and Wilcox Formations, with productive natural gas flow rates established in the Sligo Formation at 16,000 feet.

 

We operate five of the sixteen producing wells in the Yoakum field with an 86.3% average working interest and a 65.8% average net revenue interest. Most of our undeveloped locations are in units with a working interest of 98.3% and a net revenue interest of 74.0%. As of April 1, 2003, our properties in the Yoakum field contained 9.2 Bcfe (99.6% natural gas) of net proved reserves (25.1% developed) with a net pre-tax PV10% value of $14.6 million. Our net daily production as of such date was 1,346 Mcf/d of natural gas, with 3 barrels of oil per day. Through the use of 2-D seismic data and well control we have defined significant remaining development potential in the eastern and southern parts of the field. Independent engineers have confirmed four proved undeveloped drilling locations as of April 1, 2003. The first of these, the Julia Mott #1H well, was drilled in April 2003 as a horizontal re-entry well, and was successfully completed with an initial producing rate of 2,500 Mcf/d. We plan to drill one additional well in the Yoakum field during 2003.

 

The Word North field is the largest of three contiguous Edwards Limestone natural gas reservoirs located in Lavaca County, Texas. Natural gas production in the Word North field was discovered in 1960, and by the mid 1980s extended for eight miles northeast into Word North field. The Edwards Limestone at depths of 13,055 to 13,840 feet is the primary reservoir at Word North field. Additional production has been developed in the Wilcox Formation at depths of 7,170 to 10,140 feet, the Yegua Formation at depths of 5,800 to 6,980 feet and the Frio Formation at depths of 3,000 to 3,130 feet.

 

We have operated and non-operated interests in the Word North field, with an average working interest of 35.0%. As of April 1, 2003, our properties in the Word North field contained 17.2 Bcfe (97.3% natural gas) of net proved reserves (22.6% developed) with an estimated net pre-tax PV10% value of $24.5 million. Our net production is six barrels of oil per day and 1,565 Mcf/d of natural gas. In May 2003, we drilled the Albert Smolik #3ST H well, which is currently being completed. We plan to drill one additional well in the Word North field during 2003.

 

The Kawitt field is located in Karnes and Dewitt Counties, Texas. The Kawitt field was discovered in 1960 and produces primarily from the Edwards Limestone at 13,400 feet, with secondary production from the Wilcox and Yegua Formations at depths between 6,600 and 9,500 feet.

 

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As of April 1, 2003, our properties in the Kawitt field contained 7.6 Bcfe (70.2% natural gas) of net proved reserves (12.4% developed) with a net pre-tax PV10% value of $8.3 million. Our working interest in the Kawitt field is 100% and net production is four barrels of oil per day and 710 Mcf/d of natural gas. Our proved undeveloped drilling projects at Kawitt field consist of the five Edwards and five Wilcox wells. In addition, we hold significant undeveloped acreage within the productive area of the Kawitt field. Drilling in this field is guided by 3-D seismic data, which we use to identify the locations of faults within the reservoir and to estimate reservoir thickness. We plan to drill one horizontal re-entry well in the Edwards Limestone and one vertical well in the Wilcox Formation in 2003.

 

Vicksburg Trend. We own interests in several fields within the Vicksburg Trend located in the vicinity of Nueces Bay in San Patricio and Nueces Counties, Texas. These fields include the Agua Dulce, Triple A, South Midway, and East White Point fields. Natural gas and oil production in this area is from multiple, low permeability sandstone reservoirs within the Vicksburg and Frio Formations at depths ranging between 4,000 and 15,000 feet. These reservoirs are contained within highly faulted structures, typically resulting in multiple reservoir compartments within a given field. Our use of 3-D seismic data to delineate trapping faults and to directly detect oil and natural gas reservoirs has significantly enhanced our ability to discover and develop these reserves.

 

Production in the Agua Dulce field is from a series of highly faulted, overpressured, low permeability sandstones within the Vicksburg Formation at depths ranging from 8,000 to 10,000 feet. 3-D seismic data aids our drilling at Agua Dulce. Each wellbore in our drilling program is designed to access several natural gas-charged reservoir sands, which are then fracture simulated and simultaneously produced.

 

We operate eleven wells in the Agua Dulce field, in which we have a 99.0% average working interest and an average net revenue interest of 81.0%. As of April 1, 2003, our net production in the Agua Dulce field was 7.6 MMcf/d of natural gas and 245 barrels per day of condensate. Our properties in this field contained 20.4 Bcfe (90.7% natural gas) of net proved reserves (60.6% developed) with a net pre-tax PV10% value of $60.2 million. We have drilled two successful wells in the Agua Dulce field in 2003 and plan to drill an additional two wells for the remainder of the year.

 

South Texas Olmos Trend. We own an average of 50% working interest in 250 natural gas wells located in Webb and LaSalle Counties, Texas which are operated by Lewis Petro Properties, Inc. These wells produce from low permeability sands in the Olmos, Escondido and Wilcox Formations at depths ranging from 4,000 to 8,000 feet. Improvements in drilling and fracture stimulation technology over the last several years have reduced our drilling costs and increased our reserve volumes. Our net daily production from Lewis Petro operated wells is five MMcf/d. As of April 1, 2003, these properties contained 15.2 Bcfe (100% natural gas) of net proved reserves with a pre-tax PV10% value of $26.4 million.

 

Development of these properties has continued at a steady pace with six to twelve new wells drilled per year since 1998. Our current drilling activity is primarily in the Escondido field. During 2003, one unsuccessful well was drilled in this field. Four new wells are planned for the remainder of the year.

 

Additional Drilling Activity in the Gulf Coast/Permian Basin

 

In addition to the projects described above, we have an 18% working interest in a successful, non-operated drilling and recompletion project in South Timbalier, Block 185 of the Gulf of Mexico shelf area, offshore Louisiana. We have additional interests in ongoing drilling activity in South Timbalier, Blocks 200 and 203, which will continue during the remainder of 2003.

 

Drilling activity planned for 2003 includes an operated test well in Cotton Valley, Leon County, Texas, at a depth of 15,000 feet, in which we have a 65% working interest, a non-operated drilling project in the South Midway field, San Patricio County, Texas, in which we have a 20% working interest and an

 

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operated development drilling project at High Island Block 98-L field in Texas state waters, in which we have a 57% working interest.

 

Rocky Mountains

 

Our Rocky Mountain operations include assets in North Dakota, Montana, Colorado and Wyoming. As of April 1, 2003, our proved reserves in the Rocky Mountain region were 30 MMboe (91.3% oil), which accounted for 41.0% of our total proved reserves. The majority of our interests in the Rocky Mountain region are within North Dakota and Montana, where we have interests in 97 fields, 45 of which we operate. Approximately 86.6% of the proved reserves and approximately 86.9% of the pre-tax PV10% value of our Rocky Mountain operations are related to assets in North Dakota.

 

Significant Rocky Mountains Operations

 

Big Stick (Madison) Unit. The Big Stick field, which contains the Big Stick (Madison) Unit, is located along a north-to-south trending geologic structure known as the Billings nose in Billings County, North Dakota. The field was discovered by Tenneco Oil Company in 1979. Production within this field is primarily from a series of stacked, oil saturated, porous dolomites within the Mission Canyon Formation at an average depth of 9,400 feet. Additional, deeper pay zones include the Duperow Formation at 11,100 feet, and the Red River Formation at 12,700 feet. We acquired a 62% working interest (51.6% net revenue interest) in the Big Stick (Madison) Unit and its associated leasehold in early 2002 and have served as the unit operator since that date.

 

The Big Stick (Madison) Unit currently contains 37 producing wellbores and 12 water injection wells. Producing wells within the unit are developed on 160 acre spacing, and water is currently being reinjected with approximately one injector well per 1,200 acres. Although water injection has been moderately effective at maintaining reservoir pressure, the injector wells have not established an effective sweep.

 

We have recently completed a detailed reservoir model study of the Mission Canyon Formation, which has demonstrated that significant additional reserves may be recovered from the Big Stick (Madison) Unit. Specifically, this study indicates that production to date accounts for 18% of the 276 million barrels of oil originally in place within the Mission Canyon pay zones. The study also indicates that, through a combination of additional drilling designed to access poorly drained portions of the reservoir and full implementation of a waterflood, oil production may be increased to 25% of the original oil in place, yielding an additional 20 million barrels of gross oil production. Development of the Big Stick (Madison) Unit is proceeding through a combination of new vertical and horizontal drilling. Several of the horizontal wells will be drilled as sidetracks from existing vertical wellbores within the field in order to optimize our capital investment.

 

Independent engineering estimates indicate that as of April 1, 2003 our properties in the Big Stick field contain 12.8 MMboe (7.8% natural gas) of net proved reserves (53.0% developed) with a net pre-tax PV10% value of $98.3 million.

 

In addition to the Big Stick (Madison) Unit, the Duperow Formation has produced 1.6 MMbbls of oil and 2,300 MMcf of natural gas from three pools within the Big Stick field. Several Duperow wells were shut-in while still producing over 100 barrels of oil per day and low water cuts. The Red River Formation tested at a rate of 2.2 MMcfg/d of natural gas on a brief production test in 1979. The formation was not produced because of high (9.7%) hydrogen sulfide content and a lack of pipelines or facilities to transport or process this natural gas. Currently there are pipelines in the area capable of transporting this natural gas. We believe that the Duperow and the Red River Formations can be economically developed with vertical wells and existing infrastructure; however, additional natural gas compression facilities may be required as natural gas production from these formations increases.

 

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During 2003, we have drilled two horizontal re-entry wells. One of these had an initial producing rate of 160 barrels of oil per day, and the second is currently being completed. We plan to drill five additional wells in the Big Stick (Madison) unit and one in the Red River Formation during the remainder of the year.

 

North Elkhorn Ranch Unit. The North Elkhorn Ranch Unit is located eight miles north of the Big Stick field in Billings County, North Dakota on the north end of the Billings Nose. The field was discovered by Tenneco in January 1981. The primary production in this field is from oil saturated, porous dolomites within the Mission Canyon Formation. Several of these zones are present and produce at the Big Stick (Madison) Unit. The average producing depth of these reservoirs is 9,500 feet. Additional, deeper pay zones include the Duperow Formation at 11,300 feet, and the Red River Formation at 13,100 feet. We acquired a 60.0% working interest (49.6% net revenue interest) in the North Elkhorn Ranch Unit and its associated leasehold in early 2002 and have served as the unit operator since that date.

 

The North Elkhorn Ranch Unit currently contains 23 producing wellbores and six water injection wells. Producing wells within this unit are developed on 160 acre spacing. Drilling opportunities in the North Elkhorn Ranch Unit are similar to those in the Big Stick (Madison) Unit, consisting of a mixture of new vertical and horizontal infill wells as well as some horizontal re-entry wells. We are currently in the process of obtaining permits for two wells that we plan to drill beginning in August 2003. An integrated reservoir model study planned for 2004 will be used to define the optimal development plan for the North Elkhorn Ranch Unit.

 

As of April 1, 2003, we had an interest in 23 producers, six water injectors and two water source wells. Our properties in the field contain 4.5 MMboe (6.2% natural gas) of net proved reserves (81.1% developed) with a net pre-tax PV10% value of $28.8 million. In addition, we have five proved undeveloped drilling locations in the Mission Canyon Formation and deeper drilling opportunities in the Duperow and Red River Formations. We plan to drill three new wells during the remainder of 2003.

 

Additional Drilling Activity in the Rocky Mountains

 

In addition to the projects described above, we are involved in several additional drilling projects on our Williston Basin properties. In Richland County, Montana, we are completing the third well of a successful five well horizontal drilling program targeting the Middle Bakken Dolomite in the Red Water field, in which we have a 40% working interest. These wells are drilled with dual horizontal boreholes and are fracture stimulated to enhance production. The estimated ultimate production from the first two wells is 704 Mbo per well. We believe that the newer fracture technologies that have been instrumental to our success in Richland County have the potential to be applied to our extensive leasehold to the east in Billings, McKenzie and Golden Valley Counties, North Dakota.

 

Also in Richland County, we recently completed a 36 square mile 3-D seismic program and plan to complete a three-well drilling program in which we have a 50% working interest and which primarily targets the Red River Formation at 11,800 feet, later this year. The first well in this program was unsuccessful, but the information gained from that well, combined with our seismic data, has increased our understanding of the geologic conditions, which is necessary to establish commercial oil production and to establish future drilling locations.

 

We also have development drilling scheduled for our properties in the Roosevelt, Landa and Lucky Mound fields in North Dakota.

 

Michigan

 

Our Michigan operations include assets in Michigan and Ohio. Virtually all of the proved reserves and pre-tax PV10% value associated with our Michigan operations are from properties located in the state of Michigan. The Michigan region contributes 113.1 Bcfe (almost entirely natural gas) of net proved reserves to our portfolio of operations, which represents 25.8% of our total net proved reserves.

 

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Production in Michigan can be divided into two groupings. The majority of the reserves reside in the Antrim Shale, none of which we operate. The non-Antrim Shale production is conventional oil and natural gas production and is a combination of operated and non-operated production. Additionally, we operate the West Branch and Stoney Point natural gas plants in the region. We believe these plants to be in excellent mechanical condition and capable of handling additional production without upgrading them. The West Branch Plant gathers production from the Clayton, West Branch and other smaller fields while 19 MMcf/d of capacity is available for additional third party natural gas.

 

Significant Michigan Operations

 

Antrim Shale. The Antrim Shale play involves the production of natural gas from shallow (1,200 to 2,200 feet), fractured, Upper Devonian shale present within a 3,400 square mile region of northern Michigan. We own interests in 56 multi-well Antrim Shale natural gas projects within this area. As of April 1, 2003, our net proved reserves from these projects was 82.6 Bcfe (100% natural gas) with a pre-tax PV10% value of $126.3 million (17.6% of our the total pre tax PV10% value of our reserves). Our net production from the Antrim Shale natural gas projects is 16.6 MMcf/d. our Antrim Shale properties are operated by a small number of Michigan-based companies, and our average working interest in the Antrim Shale projects is 39% with a 29.1% net revenue interest.

 

Approximately 20 of our Antrim Shale projects have significant remaining development potential. These projects are concentrated in three areas. In Briley Township, we have proved undeveloped reserves of 5.9 Bcf. The Old Vandy Projects in Charlevoix and Otsego Counties have proved undeveloped reserves of 3.19 Bcfe. An additional 5.5 Bcf of proved undeveloped reserves are present within eight additional townships which are less geographically concentrated. The aggregate pre-tax PV10% value of our Antrim Shale development opportunities is $19.2 million. During 2003, we have drilled six wells, and we expect to drill 32 additional wells during the remainder of 2003.

 

Conventional (non-Antrim Shale ) Production. Our non-Antrim Shale production is from conventional reservoirs (primarily the Prairie du Chien, Trenton and Black River Formations) located in Central Michigan. Estimated net proved reserves (75.0% developed) from these properties total 30.5 Bcfe (83.1% natural gas), which comprises 7.0% of our total net proved reserves, with a net pre-tax PV10% value of $76.9 million (10.7% of our total pre-tax PV10% value). We have interests in 18 oil and natural gas fields in this region and operate 7 of them. Our conventional non-Antrim Shale fields are estimated to be producing 5.1 MMcfe/d, net to our interest.

 

The Prairie du Chien fields produce natural gas and retrograde condensate from various intervals within a 500-800 foot thick sequence of sandstones and dolomitic sandstones at a depth of 10,500-11,200 feet. The low permeability and heterogeneous character of the Prairie du Chien reservoirs has resulted in low recovery of the original natural gas in place from the existing wells, providing us with significant opportunities for increased recovery through infill and horizontal drilling.

 

The South Buckeye field is a structurally-trapped natural gas accumulation in the Prairie du Chien Formation. The estimated range of original natural gas in place in the South Buckeye field is 195 – 331 Bcf. The total field production to date is 9.3 Bcfe, which is less than 5% of the original oil in place. In addition, present-day reservoir pressure is 4,800 pounds per square inch, which compares favorably with the original field pressure of 5,826 pounds per square inch.

 

As of April 1, 2003, two proved undeveloped drilling opportunities have been identified in the South Buckeye field, with a combined 2.0 Bcfe of net proved undeveloped reserves and a pre-tax PV 10% value of $3.76 million. We plan to drill one of these wells during 2003. We believe that significant additional potential exists for horizontal re-entry wells and conventional vertical and horizontal wells.

 

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Mid-Continent

 

Our Mid-Continent operations include assets in Oklahoma, Arkansas and Kansas. The Mid-Continent region contributes 21.8 Bcfe (63.5% natural gas) of net proved reserves to our portfolio of operations, which represents 4.9% of total net proved reserves. The majority of the proved value within our Mid-Continent operations is related to properties in Oklahoma (approximately $23.1 million pre-tax PV10% value or 76.0% of the region’s pre-tax PV10% value). The Oklahoma production is scattered throughout the state, with the single largest concentration being in the company-operated Putnam Oswego Unit, located in Dewey and Custer counties in West-Central Oklahoma.

 

Our proved properties located in Arkansas represent approximately $7.1 million of pre-tax PV10% value (23.4% of the region’s pre-tax PV10% value). Essentially all of the assets in Arkansas are operated, and are primarily in two fields, the Magnolia Smackover Pool Unit and the Wesson Hogg Sand Unit. Both of these fields are mature pressure maintenance units.

 

Cherokee Basin Coalbed Methane Project. In 2002 and 2003, we acquired a 91,284 acre lease position in the Cherokee Basin, which is prospective for natural gas from coal seams (coalbed methane). Approximately 70,000 acres are concentrated in our Center prospect, which is located south of Emporia, Kansas and in which we have a 100% working interest.

 

In 2003, we conducted an eight-well drilling program to determine total coal thickness, natural gas content and reservoir properties of coal seams within the Cherokee Formation at an average depth of 2,200 feet. Based on the results of this program, we are currently implementing a pilot natural gas recovery project designed to determine the productive capacity of these coals. The first pilot well has recently begun to produce natural gas, but will require between several weeks and several months before its total productive capacity can be determined.

 

If the pilot program is successful, we estimate that we may have approximately 460 additional drilling locations based on 111 acre spacing. Costs for implementing the project are estimated at $168,000 per well, which includes equity investment for saltwater disposal facilities, gathering facilities, compression, drilling and completion. Our estimate of natural gas reserves is 397 MMcf per well, which we base on an analogy to drilling activity in other areas within the Cherokee and Forest City basins.

 

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Acreage

 

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2002 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

 

     Developed Acreage

   Undeveloped Acreage

   Total Acreage

     Gross

   Net

   Gross

   Net

   Gross

   Net

Gulf Coast/Permian Basin:

                             

Texas

   113,971    43,385    8,514    7,518    122,485    50,903

Louisiana

   42,366    14,857    —      —      42,366    14,857

New Mexico

   2,923    443    —      —      2,923    443
    
  
  
  
  
  

Sub-Total

   159,260    58,685    8,514    7,518    167,774    66,203
    
  
  
  
  
  

Rocky Mountains:

                             

North Dakota

   79,410    46,964    109,000    42,000    188,410    88,964

Montana

   24,320    8,120    177,000    48,400    201,320    56,520

Colorado

   2,213    1,760    —      —      2,213    1,760

Wyoming

   31,095    9,663    —      —      31,095    9,663
    
  
  
  
  
  

Sub-Total

   137,038    66,507    286,000    90,400    423,038    156,907
    
  
  
  
  
  

Michigan

                             

Michigan

   178,821    58,744    —      —      178,821    58,744

Ohio

   800    667    —      —      800    667
    
  
  
  
  
  

Sub-Total

   179,621    59,411    —      —      179,621    59,411
    
  
  
  
  
  

Mid-Continent:

                             

Oklahoma

   31,640    17,861    —      —      31,640    17,861

Arkansas

   4,300    1,300    —      —      4,300    1,300

Kansas

   320    160    91,284    90,395    91,604    90,555
    
  
  
  
  
  

Sub-Total

   36,260    19,321    91,284    90,395    127,544    109,716
    
  
  
  
  
  

Total

   512,179    203,924    385,798    188,313    897,977    392,237
    
  
  
  
  
  

 

Production History

 

The following table presents the historical information about our produced natural gas and oil volumes.

 

     Year Ended December 31,

  

Compounded

Annual

Growth Rate


    Six Months
Ended
June 30, 2003


     2000

   2001

   2002

    

Oil production (MMbbls)

     1.6      2.1      2.3    19.9 %     1.3

Natural gas production (Bcf)

     16.9      19.8      21.4    12.5 %     10.7

Total production (Bcfe)

     26.5      32.4      35.2    15.3 %     18.4

Daily production (MMcfe/d)

     72.6      88.8      96.4    15.2 %     101.6

Average sales prices:

                                 

Natural gas (per Mcf)(1)

   $ 3.51    $ 3.82    $ 3.21    N/A     $ 5.18

Oil (per Bbl)(1)

     26.96      23.85      23.35    N/A       28.02

Total (per Mcfe)(1)

     4.07      3.88      3.48    N/A       4.97

Average production cost (per Mcfe)

     2.16      2.57      2.72    N/A       2.89

(1)   Before consideration of hedging transactions.

 

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Productive Wells

 

The following table presents our ownership at December 31, 2002 in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).

 

     Oil Wells

   Natural Gas Wells

   Total Wells

     Gross

   Net

   Gross

   Net

   Gross

   Net

Gulf Coast/Permian Basin:

                             

Texas

   1,121    126.1    719    214.6    1,840    340.7

Louisiana

   26    2.0    95    29.1    121    31.1

New Mexico

   39    1.4    7    1.0    46    2.4
    
  
  
  
  
  

Sub-Total

   1,186    129.5    821    244.7    2,007    374.2
    
  
  
  
  
  

Rocky Mountains:

                             

North Dakota

   847    170.2    4    4.0    851    174.2

Montana

   65    18.8    —      —      65    18.8

Colorado

   10    7.2    8    1.5    18    8.7

Wyoming

   84    8.4    102    13.5    186    21.9
    
  
  
  
  
  

Sub-Total

   1,006    204.6    114    19.0    1,120    223.6
    
  
  
  
  
  

Michigan:

                             

Michigan

   80    59.2    954    356.9    1,034    416.1

Ohio

   —      0.0    6    5.0    6    5.0
    
  
  
  
  
  

Sub-Total

   80    59.2    960    361.9    1,040    421.1
    
  
  
  
  
  

Mid-Continent:

                             

Oklahoma

   236    55.2    156    62.0    392    117.2

Arkansas

   112    80.6    —      —      112    80.6

Kansas

   1    1.0    10    9.0    11    10.0
    
  
  
  
  
  

Sub-Total

   349    136.8    166    71.0    515    207.8
    
  
  
  
  
  

Alabama, Mississippi and Utah (1)

   27    —      19    —      46    —  
    
  
  
  
  
  

Total

   2,648    530.1    2,080    696.6    4,728    1,226.7
    
  
  
  
  
  

 

(1)   Ownership in these three states is primarily through our interests in partnerships.

 

Drilling Activity

 

We are engaged in numerous drilling activities on properties presently owned and intend to drill or develop other properties acquired in the future. The following table sets forth the results of our drilling activity for the last three years.

 

    

Gulf Coast/

Permian Basin


   Mid-Continent

   Rocky Mountains

   Michigan

   Total

     2000

   2001

   2002

   2000

   2001

   2002

   2000

   2001

   2002

   2002

   2000

   2001

   2002

Gross:

                                                                

Productive

   15    22    10    1    3    3    4    31    7    4    20    56    24

Dry

   4    6    6    2    —      —      1    2    3    —      7    8    9
    
  
  
  
  
  
  
  
  
  
  
  
  

Total

   19    28    16    3    3    3    5    33    10    4    27    64    33
    
  
  
  
  
  
  
  
  
  
  
  
  

Net:

                                                                

Productive

   5.5    10.5    4.2    0.2    1.0    0.2    0.1    8.1    2.7    1.0    5.9    19.6    8.1

Dry

   3.0    1.9    2.2    0.3    —      —      0.1    1.9    2.1    —      3.4    3.8    4.3
    
  
  
  
  
  
  
  
  
  
  
  
  

Total

   8.5    12.4    6.4    0.5    1.0    0.2    0.2    10.0    4.8    1.0    9.3    23.4    12.4
    
  
  
  
  
  
  
  
  
  
  
  
  

 

Our drilling activities from exploratory wells included in the table above are located in the Gulf Coast/Permian Basin region only and consisted of no wells for 2000, one productive gross well (0.2 net) for 2001 and one dry gross well (0.15 net) for 2002.

 

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The table below sets forth the results of our drilling activities for the six months ended June 30, 2003:

 

    

Gulf Coast/

Permian Basin


   Mid-Continent

   Rocky
Mountains


   Michigan

   Total

Gross:

                        

Productive

   9    0    6    6    21

Dry

   2    0    1    0    3
    
  
  
  
  

Total

   11    0    7    6    24
    
  
  
  
  

Net:

                        

Productive

   5.8    0    2.2    2.4    10.4

Dry

   0.9    0    0.5    0    1.4
    
  
  
  
  

Total

   6.7    0.0    2.7    2.4    11.8
    
  
  
  
  

 

Our drilling activities from exploratory wells included in the table above consisted of one gross (0.5 net) exploratory dry well in the Rocky Mountain region.

 

Cost Information

 

We conduct our oil and natural gas activities entirely in the United States. Costs incurred in oil and natural gas producing activities are shown below.

 

     Year Ended December 31,

  

Three Months
Ended

March 31, 2003


     2000

   2001

   2002

  
     (dollars in millions)     

Proved property acquisition

   $ 125.9    $ 66.0    $ 140.7    $ 0.2

Development

     13.2      32.1      23.1      4.7

Exploration

     1.1      0.8      1.8      0.2

Unproved property acquisition

     0.3      0.1      0.9      0.3
    

  

  

  

Total

   $ 140.5    $ 99.0    $ 166.5    $ 5.4
    

  

  

  

 

Net capitalized costs related to our oil and natural gas producing activities are shown below.

 

     Year Ended December 31,

   

Three Months
Ended

March 31, 2003


 
     2000

    2001

    2002

   
     (dollars in millions)        

Proved oil and natural gas properties

   $ 349.4     $ 391.4     $ 553.9     $ 568.9  

Unproved oil and natural gas properties

     0.7       0.7       1.6       1.9  

Accumulated depreciation, depletion and amortization

     (123.9 )     (110.8 )     (152.6 )     (162.6 )
    


 


 


 


Oil and natural gas properties, net

   $ 226.2     $ 281.3     $ 402.9     $ 408.2  
    


 


 


 


 

Reserve Quantity Information

 

Our estimates of proved reserves and related valuations were based primarily on reports of Ryder Scott Company, L.P., Cawley, Gillespie & Associates, Inc. and R.A. Lenser & Associates, Inc., independent petroleum and geological engineers, in accordance with the provisions of SFAS 69, “Disclosures about Oil and Gas Producing Activities.” The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

 

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Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil and natural gas reserves is shown below.

 

     Oil (MMbbl)

    Natural Gas
(Bcf)


 

Balance, December 31, 1999

   11.9     122.6  

Purchases of minerals in place

   11.9     45.8  

Extensions and discoveries

   0.5     4.7  

Sales of minerals in place

   (1.1 )   (8.8 )

Production

   (1.6 )   (16.9 )

Revisions of previous estimates

   (2.5 )   10.1  
    

 

Balance, December 31, 2000

   19.1     157.5  

Purchases of minerals in place

   1.0     89.8  

Extensions and discoveries

   1.1     9.3  

Sales of minerals in place

   (0.7 )   (6.0 )

Production

   (2.1 )   (19.8 )

Revisions of previous estimates

   (3.6 )   (3.3 )
    

 

Balance, December 31, 2001

   14.8     227.5  

Purchases of minerals in place

   15.2     58.4  

Extensions and discoveries

   0.5     2.3  

Sales of minerals in place

   0.0     (0.9 )

Production

   (2.3 )   (21.4 )

Revisions of previous estimates

   1.3     (29.9 )
    

 

Balance, December 31, 2002

   29.5     236.0  
    

 

Purchases of minerals in place

   0.0     0.0  

Extensions and discoveries

   0.9     0.0  

Sales of minerals in place

   0.0     0.0  

Production

   (0.6 )   (5.4 )

Revisions of previous estimates

   5.6     (4.2 )
    

 

Balance, March 31, 2003

   35.4     226.4  
    

 

 

Our proved developed oil and natural gas reserves are shown below.

 

     As of December 31,

   As of
April 1, 2003


     2000

   2001

   2002

  

Oil (MMbbls):

                   

Developed

   14.9    11.0    23.8    24.8

Undeveloped

   4.2    3.8    5.7    10.6
    
  
  
  

Total

   19.1    14.8    29.5    35.4
    
  
  
  

Natural Gas (Bcf):

                   

Developed

   134.4    136.8    167.6    162.9

Undeveloped

   23.1    90.7    68.4    63.5
    
  
  
  

Total

   157.5    227.5    236.0    226.4
    
  
  
  

Total (Bcfe):

                   

Developed

   223.8    202.8    310.4    311.9

Undeveloped

   48.3    113.5    102.6    127.3
    
  
  
  

Total

   272.1    316.3    413.0    439.2
    
  
  
  

 

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Standardized Measure of Discounted Future Net Cash Flows

 

Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with the provisions of SFAS 69. Future cash inflows were computed by applying year-end prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in producing and developing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

 

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10 percent annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our oil and natural gas properties.

 

The standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.

 

     As of December 31,

    As of
March 31, 2003


 
     2000

    2001

    2002

   
     (dollars in millions)  

Future cash inflows

   $ 1,912.5     $ 880.9     $ 1,854.9     $ 2,119.5  

Future production costs

     (523.5 )     (379.7 )     (677.1 )     (788.0 )

Future development costs

     (32.8 )     (75.6 )     (65.4 )     (75.3 )

Future income tax expense

     (398.4 )     (62.0 )     (270.5 )     (375.0 )
    


 


 


 


Total future net cash flows

     957.8       363.6       841.8       881.2  

10% annual discount

     (438.6 )     (151.9 )     (365.8 )     (377.5 )
    


 


 


 


Standardized measure of discounted future net cash flows

   $ 519.2     $ 211.7     $ 476.0     $ 503.7  
    


 


 


 


 

The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.

 

     2000

    2001

    2002

   

Three Months
Ended

March 31, 2003


 
     (dollars in millions)  

Beginning balance

   $ 150.9     $ 519.2     $ 211.7     $ 476.0  

Net change in income taxes

     (170.3 )     183.1       (116.9 )     (61.4 )

Purchases of minerals in place

     241.1       84.6       241.8       —    

Accretion of discount

     19.0       73.5       24.8       15.7  

Extensions, discoveries and improved recoveries

     33.9       17.5       6.6       7.8  

Development costs, net

     4.4       (3.3 )     (11.3 )     (13.8 )

Sales of minerals in place

     (18.0 )     (11.2 )     (0.7 )     —    

Revisions of previous quantity estimates

     (9.6 )     (16.2 )     (36.2 )     51.3  

Sale of oil and natural gas produced, net of production costs

     (76.7 )     (87.3 )     (80.3 )     (35.1 )

Changes in prices and production costs

     359.4       (528.1 )     212.2       54.1  

Changes in production rates and other

     (14.9 )     (20.1 )     24.4       9.1  
    


 


 


 


Ending balance

   $ 519.2     $ 211.7     $ 476.0     $ 503.7  
    


 


 


 


 

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Marketing and Major Customers

 

We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For fiscal year 2002, no single customer was responsible for generating 10% or more of our total oil and natural gas sales.

 

Title to Properties

 

Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interferes with the use of our properties in the operation of our business.

 

We believe that we have satisfactory title to or rights in all of our producing properties. As is customary in the oil and natural gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.

 

Competition

 

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry.

 

Regulation

 

Public Utility Holding Company Act of 1935

 

Until Alliant Energy owns less than 10% of our common stock, we will continue to be subject to regulation under PUHCA, as a subsidiary company of a public utility holding company registered under PUHCA. We and Alliant Energy have agreed to seek an exemption from our being considered a “subsidiary company” of Alliant Energy for purposes of PUHCA, but we may not be able to obtain such an exemption. As a result, we will be subject to limitations under PUHCA related to our acquisition strategy, ownership and operation of energy assets outside of our current business plan, payments of dividends by us and our subsidiaries from capital surplus and issuances of securities. Additionally, as long as Alliant Energy owns 5% or more of our outstanding common stock, we must obtain approval under PUHCA prior to acquiring 5% or more of the voting securities of any public utility or taking any other actions that would result in affiliation with another public utility or entering into any contractual arrangements with Alliant Energy or any of its affiliates. Once Alliant Energy owns less than 10% of our common stock, we do not expect to be subject to regulation under PUHCA as a subsidiary company and we do not currently intend to take actions that would cause us subsequently to become subject to regulation under PUHCA.

 

PUHCA prohibits Alliant Energy and its subsidiaries, including us, from making additional investments in non-utility “energy assets” without approval from the SEC. Currently, Alliant Energy and its subsidiaries are authorized under an order issued by the SEC under PUHCA to invest, without further

 

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approval from the SEC, up to $800 million in additional “energy assets” in the United States and Canada. The SEC order expires on December 31, 2004. As defined in the SEC order, “energy assets” include natural gas production, gathering, processing, storage and transportation facilities and equipment, liquid oil reserves and storage facilities, and associated facilities. Without obtaining another order from the SEC, we will not be able to acquire assets that fall outside of these categories. As of June 30, 2003, Alliant Energy and its subsidiaries, including us, had used approximately $384 million of the $800 million granted under the SEC order. Alliant Energy has agreed that we may use at least $300 million of the remaining $416 million authority under the SEC order. Alliant Energy has also agreed to allow us to apply to the SEC for our own authority to acquire “energy assets.”

 

If Alliant Energy continues to own 10% or more of our common stock after December 31, 2004 and the SEC does not extend the order beyond that date or grant us our own order, or if the authority to acquire “energy assets” under Alliant Energy’s or our own order is not sufficient to maintain our acquisition strategy, then our operations may be adversely affected and we may not be able to pursue our business strategies.

 

Further, we and our subsidiaries are authorized under an order issued by the SEC to pay dividends out of capital or unearned surplus. This order is necessary to exempt us and our subsidiaries from restrictions on the payment of dividends contained in PUHCA and expiring on December 31, 2004. If Alliant Energy continues to own 10% or more of our common stock after December 31, 2004 and the SEC does not extend the order beyond that date or grant us our own order, cash held by our subsidiaries may not be able to be distributed to us, reducing our cash management flexibility and increasing our need for working capital and external financing.

 

PUHCA also regulates our issuance of securities and requires compliance with applicable SEC rules respecting such issuances. Current SEC rules exempt our issuances of securities from PUHCA requirements so long as the securities are issued solely for the purpose of financing our existing business.

 

Regulation of Transportation and Sale of Natural Gas

 

Historically, the transportation and sale for resale of natural gas in inter state commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the Federal Energy Regulatory Commission, or the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

 

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order

 

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No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect. While most major aspects of Order No. 637 have been upheld on judicial review, certain issues such as capacity segmentation and right of first refusal are pending further consideration by the FERC. We cannot predict what action FERC will take on these matters in the future, or whether the FERC’s actions will survive further judicial review.

 

The Outer Continental Shelf Lands Act, which the FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the outer continental shelf provide open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out this Act’s mandate is to increase transparency in the market to provide producers and shippers on the outer continental shelf with greater assurance of open access services on pipelines located on the outer continental shelf and non-discriminatory rates and conditions of service on such pipelines.

 

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

 

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.

 

Regulation of Transportation of Oil

 

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

 

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

 

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full

 

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capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

 

Regulation of Production

 

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

 

Some of our offshore operations are conducted on federal leases that are administered by Minerals Management Service, or MMS, and are required to comply with the regulations and orders issued by MMS under the Outer Continental Shelf Lands Act. Among other things, we are required to obtain prior MMS approval for any exploration plans we pursue and our development and production plans for these leases. MMS regulations also establish construction requirements for production facilities located on our federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease.

 

MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural gas leases. The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and natural gas lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

 

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

 

Environmental Regulations

 

General. Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, also referred to as the “EPA,” issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit project siting, construction, or drilling activities on certain lands laying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations. The EPA and analogous state agencies may delay or refuse the issuance of required permits or otherwise include onerous or limiting permit conditions that may have a significant

 

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adverse impact on our ability to conduct operations. The regulatory burden on the oil and natural gas industry increases the cost of doing business and consequently affects its profitability.

 

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and have not experienced any material adverse effect from compliance with these environmental requirements, there is no assurance that this trend will continue in the future.

 

The environmental laws and regulations which have the most significant impact on the oil and natural gas exploration and production industry are as follows:

 

Superfund. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” or “operator” of a disposal site or sites where a release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.” Consequently, we may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed or released.

 

We currently own or lease, and in the past have owned or leased, properties that for many years have been used for the exploration and production of oil and natural gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on, under, or from the properties owned or leased by us or on, under, or from other locations where these wastes have been taken for disposal. In addition, many of these owned and leased properties have been operated by third parties whose management and disposal of hydrocarbons and wastes were not under our control. Similarly, the waste disposal facilities where wastes are sent are also often operated by third parties whose waste treatment and disposal practices may not be adequate. While we only use what we consider to be reputable disposal facilities, we might not know of a potential problem if the disposal occurred before we acquired the property. Our properties, adjacent affected properties, the disposal sites, and the waste itself may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

 

  • ¨   to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators or other third parties;

 

  • ¨   to clean up contaminated property, including contaminated groundwater; or

 

  • ¨   to perform remedial operations to prevent future contamination.

 

At this time, we do not believe that we are associated with any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.

 

Oil Pollution Act. The Oil Pollution Act of 1990, also known as “OPA,” and regulations issued under OPA impose liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. Liability under OPA is strict, and under certain circumstances joint and several, and potentially unlimited. A

 

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“responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35 million ($10 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150 million, depending on the risk represented by the quantity or quality of oil that is handled by the facility. We believe we are in compliance with all applicable OPA financial responsibility obligations. Any failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.

 

Resource Conservation Recovery Act. The Resource Conservation and Recovery Act, also known as “RCRA,” is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy” and thus we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. However, these wastes may be regulated by EPA or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated as hazardous waste. Although we do not believe the current costs of managing our wastes as they are presently classified to be significant, any repeal or modification of the oil and natural gas exploration and production exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.

 

Clean Air Act. The Clean Air Act, also known as “CAA,” restricts the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. In addition, more stringent regulations governing emissions of toxic air pollutants are being developed by the EPA, and may increase the costs of compliance for some facilities. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold or have applied for all necessary permits for our operations.

 

Clean Water Act. The Federal Water Pollution Control Act of 1972, or the Clean Water Act, imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. In furtherance of the Clean Water Act, the EPA promulgated the Spill Prevention, Control, and Countermeasure, or SPCC, regulations, which require certain oil containing facilities to prepare plans and

 

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meet construction and operating standards. The SPCC regulations were revised in 2002 and will require updated SPCC plans beginning in early 2004. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution and that updating of our SPCC plans will not have a significant impact on our operations.

 

Safe Drinking Water Act. Underground injection is the subsurface placement of fluid through a well, such as the re-injection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The Safe Drinking Water Act of 1974 establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. (If wastes are classified as hazardous, they must be properly transported, using a uniform hazardous waste manifest, documented, and disposed at an approved hazardous waste facility.) We currently own and operate various underground injection wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

 

Endangered Species Act. Certain flora and fauna that have officially been classified as “threatened” or “endangered” are protected by the Endangered Species Act. This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area we wish to develop, the work could be prohibited or delayed, or expensive mitigation might be required.

 

Migratory Bird Act. If migratory birds are injured or killed because of improper facility construction or maintenance methods that result in such birds being exposed to oil or other related substances, the operator of that facility is subject to substantial fines. We frequently inspect the properties we operate to make sure that the screens covering open top tanks and pits are in good condition and that any oil film on the water contained in them is promptly removed.

 

Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act, the National Environmental Policy Act, and the Coastal Zone Management Act require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. The Outer Continental Shelf Lands Act, for instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, the National Environmental Policy Act requires the Department of Interior and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. The Coastal Zone Management Act, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development. In obtaining various approvals from the Department of Interior, we must certify that we will conduct our activities in a manner consistent with these regulations.

 

Naturally Occurring Radioactive Materials. Naturally Occurring Radioactive Materials, or NORM, are materials whose radioactivity is enhanced by processing such as mineral extraction or oil and natural gas production. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards.

 

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Abandonment Costs. One of the responsibilities of owning and operating oil and natural gas properties is paying for the cost of abandonment. Effective January 1, 2003, companies are required to reflect abandonment costs as a liability on their balance sheets in the period in which it is incurred. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—New Accounting Policies.”

 

Employees

 

As of June 30, 2003, we had 108 full-time employees, including five senior level geoscientists and fourteen petroleum engineers. Our employees are not represented by any labor union. We consider our relations with our employees to be satisfactory, and have never experienced a work stoppage or strike.

 

Legal Proceedings

 

In the ordinary course of business, we are a claimant or a defendant in various legal proceedings. In the opinion of our management, we do not have any litigation pending or threatened that is material.

 

Environmental and Safety

 

In the opinion of our management, our operations comply in all material respects with applicable environmental legislation and regulations. We believe that compliance with existing federal, state, and local laws, rules, and regulations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment will not have any material effect upon our capital expenditures, earnings, or competitive position.

 

We take safety as a priority as shown by the fact that there have been no safety-related Notices of Violation, Lost Time Accidents or Worker’s Compensation claims in 2001 or 2002. In addition, there have been minimal vehicle insurance claims during the last two years. All required employees are current with HAZWOPER, H2S, CPR and First Aid training. We maintain a comprehensive safety manual that is distributed on CD. In addition, we have an ongoing CD based safety-training program. All field employees are required to attend quarterly safety meetings. Target areas are identified and emphasized as necessary from year to year.

 

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MANAGEMENT

 

Executive Officers and Directors

 

The following table sets forth information regarding our executive officers, certain other officers and directors as of June 30, 2003:

 

Name


   Age

  

Position


James J. Volker

   56   

President and Chief Executive Officer and Director

D. Sherwin Artus

   66   

Senior Vice President

James R. Casperson

   55   

Chief Financial Officer

James T. Brown

   51   

Vice President, Operations

John R. Hazlett

   64   

Vice President, Acquisitions and Land

Mark R. Williams

   46   

Vice President, Exploration and Development

Patricia J. Miller

   66   

Vice President of Human Resources and Corporate Secretary

Michael J. Stevens

   37   

Controller and Treasurer

Joseph A. Farrar, Jr*.

   63   

Manager of Acquisitions and Engineering

Charles LaCouture*

   47   

Manager of Marketing

Gale Keithline*

   52   

Director of Information Technology

Thomas L. Aller

   54   

Director

James E. Hoffman

   50   

Director

J. B. Ladd

   79   

Director

Thomas M. Walker

   56   

Director

Kenneth R. Whiting

   76   

Director


*   Not an executive officer.

 

The following biographies describe the business experience of our executive officers and directors:

 

James J. Volker joined us in August 1983 as Vice President of Corporate Development and served in that position through April 1993. In March 1993, he became a contract consultant to us and served in that capacity until August 2000, at which time he became Executive Vice President and Chief Operating Officer. Mr. Volker was appointed President and Chief Executive Officer and a director in January 2002. Mr. Volker was co-founder, Vice President and later President of Energy Management Corporation from 1971 through 1982. He has over thirty years of experience in the oil and natural gas industry. Mr. Volker has a degree in finance from the University of Denver, a MBA from the University of Colorado and has completed H. K. VanPoolen and Associates’ course of study in reservoir engineering.

 

D. Sherwin Artus joined us in January 1989 as Vice President of Operations and became Executive Vice President and Chief Operating Officer in July 1999. In January 2000, he was appointed President and Chief Executive Officer and a director. In January 2002, he became Senior Vice President. He has been in the oil and natural gas business for forty years. Mr. Artus holds a Bachelor’s Degree in geologic engineering and a Master’s Degree in mining engineering from the South Dakota School of Mines and Technology.

 

James R. Casperson joined us in February 2000 as Vice President of Finance and Chief Financial Officer. From June 1985 to February 2000, he was founder and president of Casperson, Inc., a private consulting firm. Mr. Casperson has twenty-five years of financial and operational experience in the oil and natural gas industry. Mr. Casperson holds a Bachelor’s Degree from Texas Tech University.

 

James T. Brown joined us in May 1993 as a consulting engineer. In March 1999, he became Operations Manager and, in January 2000, he became Vice President of Operations. Mr. Brown has

 

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twenty-nine years of oil and natural gas experience in the Rocky Mountains, Gulf Coast, California and Alaska. Mr. Brown is a graduate of the University of Wyoming, with a Bachelor’s Degree in civil engineering and a MBA from the University of Denver.

 

John R. Hazlett joined us in January 1994 as Vice President of Land and Acquisitions. He has forty years of experience in the oil and natural gas industry as a land man and acquisitions team leader. Mr. Hazlett is a graduate of Ft. Hays State College in Hays, Kansas. Mr. Hazlett is a Certified Professional Landman.

 

Mark R. Williams joined us in December 1983 as Exploration Geologist, becoming Vice President of Exploration and Development in December 1999. He has twenty-two years of experience in the oil and natural gas industry and his areas of primary technical expertise are in sequence stratigraphy, seismic interpretation and petroleum economics. Mr. Williams is a graduate of the Colorado School of Mines with a Master’s degree in geology and holds a Bachelor’s Degree in geology from the University of Utah.

 

Patricia J. Miller joined us in April 1980 as Corporate Secretary and as Secretary to our President, becoming Director of Human Resources in May 1994. In November 2001, she was appointed Vice President of Human Resources. Mrs. Miller attended business school at Otero Junior College in LaJunta, Colorado and at Texas A & I in Kingsville, Texas.

 

Michael J. Stevens joined us in May 2001 as Controller, and became Treasurer in January 2002. From 1993 until May 2001, he served as Chief Financial Officer, Controller, Secretary and Treasurer at Inland Resources Inc. He spent seven years in public accounting with Coopers & Lybrand in Minneapolis, Minnesota. He is a graduate of Mankato State University of Minnesota and is a certified public accountant.

 

Joseph A. Farrar, Jr., joined us in November 1991 as Manager of Acquisitions and Engineering. He has been in charge of our reservoir engineering and acquisition evaluation since that time. He has forty years of oil and natural gas experience and holds Bachelor’s and Master’s Degrees in petroleum engineering from the University of Tulsa.

 

Charles LaCouture joined us in January 2002 as Manager of Marketing and Business Development. From February 1996 to January 2002, he was employed in the same position with Alliant Energy Investments, Inc. He has over twenty years of oil and natural gas experience. Mr. LaCouture holds a Bachelor’s Degree from Texas A & M University.

 

Gale Keithline joined us in May 2003 as Director of Information Technology. From 1998 until May 2003, he was the Principal for Impact Systems Consulting. From 1995 to 1998, Mr. Keithline was the Director for Resort Computer Corporation. He has over 23 years of experience in the information technology field. He is a graduate of Metro State College and presently holds a position on the board of the Computer Management Science Advisory Board at Metro State College.

 

Thomas A. Aller has been a director since 1997. He serves as President of Alliant Energy Investments, Inc. From 1993 to 1998, he served as Vice President of IES Investments. He received his Bachelor’s Degree in political science from Creighton University and his Master’s Degree in municipal administration from the University of Iowa.

 

James E. Hoffman has been a director since 1997. He has been Executive Vice President—Business Development of Alliant Energy and President of Resources since April 1998. Mr. Hoffman is also a director of McLeodUSA Incorporated, a telecommunications provider. Mr. Hoffman received his BBA in finance and management information systems from the University of Iowa.

 

J. B. Ladd has been a director since our inception in January of 1980. He is an independent oil and natural gas operator with offices in Los Angeles, California and Denver, Colorado. He has over 50 years of experience in the oil and natural gas industry working for Texaco and Consolidated Oil and Gas and as

 

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an independent oil and natural gas operator. He founded Ladd Petroleum in 1968, which was merged into Utah International and later merged into General Electric Company. Mr. Ladd received a degree in petroleum engineering from the University of Kansas.

 

Thomas M. Walker has been a director since November 2000. Mr. Walker has served as Executive Vice President and Chief Financial Officer of Alliant Energy since April 1998. Prior to his becoming Chief Financial Officer of Alliant Energy, he served as Executive Vice President and Chief Financial Officer of IES Utilities, Inc. He received his Bachelor’s Degree in accounting from Kent State and his Master of Business Administration degree from Ohio State University.

 

Kenneth R. Whiting is our founder and has been a director and an employee of Whiting since our inception in January of 1980. He was President and Chief Executive Officer from our inception until 1993, when he was appointed Vice President of International Business for IES Diversified, our parent company’s predecessor. From 1978 to late 1979 he served as President of Webb Resources, Inc. He has many years of experience in the oil and natural gas industry, including his positions with Ladd Petroleum Corporation. He was a partner and associate with Holme Roberts & Owen, Attorneys at Law. Mr. Whiting received his Bachelor’s Degree in business from the University of Colorado and his J.D. from the University of Denver.

 

Our executive officers are elected by, and serve at the discretion of, our board of directors. Our board of directors will be divided into three classes of directors serving staggered three year terms. Our master separation agreement with Alliant Energy provides that, for so long as Alliant Energy owns at least 10% of our outstanding common stock, it will have the right to nominate the number of our directors equal to the percentage of our outstanding common stock it owns, rounded up to the nearest full number of directors. However, such number of directors must be at least one but less than a majority of our board of directors. See “Relationship with Alliant Energy Corporation.”

 

Board Committees

 

Our board of directors will establish an audit committee, a compensation committee and a nominating and corporate governance committee. Each of these committees will be comprised of independent directors, including additional independent directors that we intend to name in connection with becoming a public company. Our board may establish other committees from time to time to facilitate our management.

 

The principal functions to be performed by the audit committee will be to assist the board in monitoring the integrity of our financial statements, the independent auditor’s qualifications and independence, the performance of our independent auditors and our compliance with legal and regulatory requirements. The audit committee will have the sole authority to retain and terminate our independent auditors and to approve the compensation paid to our independent auditors. The audit committee also will be responsible for overseeing our internal audit function.

 

The principal functions of the compensation committee will be to administer our employee benefit plans (including incentive plans), annually evaluate salary grades and ranges, establish guidelines concerning average compensation increases, establish performance criteria for and evaluate the performance of the chief executive officer and approve compensation of all officers and directors.

 

The principal functions of the nominating and corporate governance committee will be to recommend persons to be selected by the board as nominees for election as directors, recommend persons to be elected to fill any vacancies on the board, consider and recommend to the board qualifications for the office of director and policies concerning the term of office of directors and the composition of the board and consider and recommend to the board other actions relating to corporate governance.

 

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Director Compensation

 

For their service on our board of directors, Mr. Whiting is paid $2,000 per month and Mr. Ladd is paid $500 per month. Prior to the offering, we will implement a new program for compensating our directors who are not employees of Whiting or Alliant Energy.

 

Compensation Committee Interlocks and Insider Participation

 

We will not have an active compensation committee of our board of directors until we name additional independent directors. As a result, our board of directors, including Messrs. Volker and Whiting, have been responsible for fixing the compensation to be paid to our executive officers. None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.

 

Executive Officer Compensation

 

The following table sets forth information concerning the compensation paid by us to our chief executive officer and each of our four other most highly compensated executive officers for 2002.

 

Summary Compensation Table

 

     Annual Compensation

    

Name and Principal Position


   Salary($)

   Bonus($)(1)

   All Other
Compensation($)(2)


James J. Volker

President and Chief Executive Officer

   165,000    205,041    —  

D. Sherwin Artus

Senior Vice President

   100,000    156,641    11,000

John R. Hazlett

Vice President, Acquisitions and

Land

   112,050    114,941    11,000

Mark Williams

Vice President, Exploration and

Development

   91,510    124,819    11,000

Patricia J. Miller

Vice President of Human Resources

and Corporate Secretary

   96,228    114,630    11,000

(1)   Except for $57,788 paid to Mr. Volker as an incentive bonus, all amounts presented under the Bonus column were paid under our Production Participation Plan, described below.
(2)   The 2002 amounts consist of matching contributions by us under our 401(k) Employee Savings Plan.

 

Employee Benefit Plans

 

Production Participation Plan. We have a Production Participation Plan for all of our employees, which was established in 1981 to provide an incentive for employees to remain with and make significant contributions to our company. Each year, our management and board of directors allocate on a discretionary basis (but do not legally convey) interests in oil and natural gas wells we acquired or

 

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developed during the year to the Production Participation Plan. Once allocated to plan participants, the interests are fixed and generally vest ratably at 20% per year over five years. Forfeitures are re-allocated among other plan participants. Allocations prior to 1995 consisted of 2%-3% overriding royalty interests with respect to oil and natural gas wells allocated to the Production Participation Plan. Allocations since 1995 have been 2%-5% of net income with respect to the oil and natural gas wells allocated to the Production Participation Plan. Payments to participants under the Production Participation Plan are made annually after year end and amounted to $4.1 million for 2001 and $3.6 million for 2002. We have estimated the total discounted obligations, including these amounts, as being $10.5 million as of December 31, 2001 and $11.7 million as of December 31, 2002. Plan expenses were approximately $2.8 million for 2000, $5.6 million for 2001 and $5.3 million for 2002.

 

Change of Control Arrangements

 

In 2002, we adopted a Phantom Equity Plan effective as of January 1, 2000. Each participant under the Phantom Equity Plan may be granted phantom shares based on his or her role in and contribution to our performance over a specified period of time. Each grant of phantom shares is evidenced by a plan agreement which sets forth the specific terms and conditions applicable to such grant. The phantom shares vest ratably at 20% per year over five years.