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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-9971
BURLINGTON RESOURCES INC.
5051 WESTHEIMER, SUITE 1400, HOUSTON, TEXAS 77056
TELEPHONE: (713) 624-9500
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INCORPORATED IN THE STATE OF DELAWARE EMPLOYER IDENTIFICATION NO. 91-1413284
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
COMMON STOCK, PAR VALUE $.01 PER SHARE
PREFERRED STOCK PURCHASE RIGHTS
THE ABOVE SECURITIES ARE REGISTERED ON THE NEW YORK STOCK EXCHANGE.
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No_____
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
State the aggregate market value of the voting stock held by non-affiliates
of the registrant: Common Stock aggregate market value as of February 29, 2000:
$5,946,038,509
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. Class: Common Stock,
par value $.01 per share, on February 29, 2000, Shares Outstanding: 215,241,213
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the
Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated:
Burlington Resources Inc. 1999 Annual Report to stockholders, which is
incorporated by reference into Part I and Part II of this Form 10-K.
Burlington Resources Inc. definitive proxy statement, to be filed not later
than 120 days after the end of the fiscal year covered by this report, is
incorporated by reference into Part III.
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BURLINGTON RESOURCES INC.
TABLE OF CONTENTS
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PAGE
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PART I
Items One and Two
Business and Properties................................ 1
Employees.............................................. 2
Item Three
Legal Proceedings...................................... 2
Item Four
Submission of Matters to a Vote of Security Holders.... 2
PART II
Item Five
Market for Registrant's Common Equity and Related
Stockholder Matters................................... 3
Item Six
Selected Financial Data................................ 3
Item Seven and Seven A
Management's Discussion and Analysis of Financial
Condition and Results of Operations and Quantitative
and Qualitative Disclosures About Market Risk......... 3
Item Eight
Financial Statements and Supplementary Financial
Information........................................... 5
Item Nine
Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................... 5
PART III
Items Ten and Eleven
Directors and Executive Officers of the Registrant and
Executive Compensation................................ 6
Item Twelve
Security Ownership of Certain Beneficial Owners and
Management............................................ 7
Item Thirteen
Certain Relationships and Related Transactions......... 7
PART IV
Item Fourteen
Exhibits, Financial Statement Schedules and Reports on
Form 8-K.............................................. 7
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PART I
ITEMS ONE AND TWO
BUSINESS AND PROPERTIES
Burlington Resources Inc. ("BR") is a holding company engaged, through its
principal subsidiaries, Burlington Resources Oil & Gas Company, The Louisiana
Land and Exploration Company ("LL&E"), and Burlington Resources Canada Energy
Ltd. (formerly known as Poco Petroleums Ltd. ("Poco")) acquired November 18,
1999, and their affiliated companies (collectively the "Company"), in the
exploration, development, production and marketing of crude oil and natural gas.
On August 16, 1999, the Company entered into a definitive agreement to
acquire Poco, a corporation existing under the laws of the Province of Alberta,
Canada (the "Acquisition"). The Acquisition was consummated on November 18,
1999.
Under the terms of the Acquisition, Poco shareholders received .25 BR
common equivalent shares ("exchangeable shares"), totaling 38,393,135 BR shares,
for each Poco share held. The exchangeable shares are Canadian securities, which
began trading on The Toronto Stock Exchange November 23, 1999 under the symbol
BRX. These shares have the same voting rights, dividend entitlements and other
attributes as shares of BR Common Stock and are exchangeable, at each
shareholder's option, for BR Common Stock on a one for one basis. The
Acquisition was accounted for as a pooling of interests.
All operational and financial information contained herein includes the
business activities of Poco for all periods presented.
For additional information concerning Items One and Two, see pages 7
through 26 of the BR 1999 Annual Report, which information is incorporated
herein by reference.
OTHER MATTERS
Competition. The Company actively competes for reserve acquisitions,
exploration leases and sales of oil and gas, frequently against companies with
substantially larger financial and other resources. In its marketing activities,
the Company competes with numerous companies for the sale of oil, gas and
natural gas liquids ("NGLs"). Competitive factors in the Company's business
include price, contract terms, quality of service, pipeline access,
transportation discounts and distribution efficiencies.
Regulation of Oil and Gas Production, Sales and Transportation. The oil
and gas industry is subject to regulation by numerous national, state and local
governmental agencies and departments in the countries in which the Company
operates, compliance with which is often difficult and costly and some of which
carry substantial noncompliance penalties and risks. Statutes, rules,
regulations or guidelines require drilling permits, drilling bonds and operating
reports. Most jurisdictions in which the Company operates also have statutes,
rules, regulations or guidelines governing conservation matters, including the
unitization or pooling of oil and gas properties and the establishment of
maximum rates of production from oil and gas wells. Many jurisdictions also
limit production to the market demand for oil and gas. Such statutes, rules,
regulations or guidelines may limit the rate at which oil and gas could
otherwise be produced from the Company's properties. All of the Company's sales
of its domestic gas are deregulated.
The Company operates various gathering systems. The United States
Department of Transportation and certain state agencies regulate, under various
statutes, rules or regulations, the safety and operating aspects of the
transportation and storage activities of these facilities by prescribing
standards.
The Federal Energy Regulatory Commission ("FERC") has implemented policies,
subject to court review, allowing interstate pipeline companies to negotiate
their rates with individual shippers. The FERC is also considering allowing the
interstate pipeline companies to negotiate tariffed terms and
1
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conditions of service. The Company will monitor the effects of these programs on
its marketing efforts but does not expect that these actions will have a
material adverse effect on the consolidated financial position or results of
operations of the Company.
Environmental Regulation. Various federal, state and local laws and
regulations relating to the protection of the environment, including the
discharge of materials into the environment, may affect the Company's domestic
operations and costs as a result of their effect on oil and gas exploration,
development and production operations. In addition, certain of the Company's
international operations are subject to environmental regulations administered
by foreign governments, including political subdivisions thereof, or by
international organizations.
Offshore oil and gas operations in the United States ("U.S.") are subject
to regulations of the U.S. Department of the Interior which currently imposes
absolute liability upon the lessee under a federal lease for the cost of
pollution cleanup resulting from the lessee's operations and could subject the
lessee to possible liability for pollution damages. In the event of a serious
incident of pollution, the U.S. Department of the Interior may require a lessee
under a federal lease to suspend or cease operations in the affected area.
The Company believes it is in substantial compliance with applicable
environmental laws and regulations. The Company does not anticipate that it will
be required under current environmental laws and regulations to expend amounts
that will have a material adverse effect on the consolidated financial position
or results of operations of the Company.
Filings of Reserve Estimates With Other Agencies. During 1999, the Company
filed estimates of oil and gas reserves, excluding the Canadian reserves, for
the year 1998 with the Department of Energy. These estimates differ by 5 percent
or less from the reserve data presented. For information concerning proved oil
and gas reserves, see page 59 of the BR 1999 Annual Report, which information is
incorporated herein by reference.
EMPLOYEES
The Company had 1,997 and 2,119 employees at December 31, 1999 and 1998,
respectively. Currently, the Company has no union employees.
ITEM THREE
LEGAL PROCEEDINGS
For information concerning Item Three, see pages 50 through 52 of the BR
1999 Annual Report, which information is incorporated herein by reference.
ITEM FOUR
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At a special meeting of stockholders of the Company held on November 18,
1999, the stockholders voted to approve the issuance of exchangeable shares
pursuant to the Amended and Restated Combination Agreement dated August 16, 1999
among the Company and Poco.
Approval of the issuance of shares of the Company's Common Stock pursuant
to the combination was as follows.
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FOR AGAINST ABSTENTIONS
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136,922,895 858,570 649,512
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PART II
ITEM FIVE
MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company's Common Stock is traded on the New York Stock Exchange under
the symbol "BR." The Company's exchangeable shares are traded on The Toronto
Stock Exchange in Canada under the symbol "BRX." At December 31, 1999, the
number of common stockholders was 20,916.
For information concerning common stock prices and quarterly dividends, see
page 61 of the BR 1999 Annual Report, which information is incorporated herein
by reference.
ITEM SIX
SELECTED FINANCIAL DATA
For information concerning Item Six, see page 31 of the BR 1999 Annual
Report, which information is incorporated herein by reference.
ITEM SEVEN AND SEVEN A
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS AND QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK
For information concerning Item Seven, see pages 32, through 35 of the BR
1999 Annual Report, which information is incorporated herein by reference.
FORWARD-LOOKING STATEMENTS
The Company, in discussions of its future plans, objectives and expected
performance in periodic reports filed by the Company with the Securities and
Exchange Commission (or documents incorporated by reference therein) and in
written and oral presentations made by the Company, may include projections or
other forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 or Section 21E of the Securities Exchange Act of 1934, as
amended. Such projections and forward-looking statements are based on
assumptions which the Company believes are reasonable, but are by their nature
inherently uncertain. In all cases, there can be no assurance that such
assumptions will prove correct or that projected events will occur, and actual
results could differ materially from those projected. Some of the important
factors that could cause actual results to differ from any such projections or
other forward-looking statements follow.
Changes in crude oil and natural gas prices (including basis differentials)
from those assumed in preparing projections and forward-looking statements could
cause the Company's actual financial results to differ materially from projected
financial results and can also impact the Company's determination of proved
reserves and the standardized measure of discounted future net cash flows
relative to crude oil and natural gas reserves. In addition, periods of sharply
lower commodity prices could affect the Company's production levels and/or cause
it to curtail capital spending projects and delay or defer exploration,
exploitation or development projects.
Projections relating to the price received by the Company for natural gas
also rely on assumptions regarding the availability and pricing of
transportation to the Company's key markets. In particular, the Company has
contractual arrangements for the transportation of natural gas from the San Juan
Basin eastward to Eastern and Midwestern markets or to market hubs in Texas,
Oklahoma and Louisiana. The natural gas price received by the Company could be
adversely affected by any constraints in pipeline capacity to serve these
markets.
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Exploration and Production Risks. The Company's business is subject to all
of the risks and uncertainties normally associated with the exploration for and
development and production of crude oil and natural gas.
Reserves which require the use of improved recovery techniques for
production are included in proved reserves if supported by a successful pilot
project or the operation of an installed program. The process of estimating
quantities of proved reserves is inherently uncertain and involves subjective
engineering and economic determinations. In this regard, changes in the economic
conditions (including commodity prices) or operating conditions (including,
without limitation, exploration, development and production costs and expenses
and drilling results from exploration and development activity) could cause the
Company's estimated proved reserves or production to differ from those included
in any such forward-looking statements or projections.
Projecting future crude oil and natural gas production is imprecise.
Producing oil and gas reservoirs eventually have declining production rates.
Projections of production rates rely on certain assumptions regarding historical
production patterns in the area or formation tests for a particular producing
horizon. Actual production rates could differ materially from such projections.
Production rates depend on a number of additional factors, including commodity
prices, market demand and the political, economic and regulatory climate.
Another major factor affecting the Company's production is its ability to
replace depleting reservoirs with new reserves through acquisition, exploration
or development programs. Exploration success is extremely difficult to predict
with certainty, particularly over the short term where the timing and extent of
successful results vary widely. Over the long term, the ability to replace
reserves depends not only on the Company's ability to locate crude oil and
natural gas reserves, but on the cost of finding and developing such reserves.
Moreover, development of any particular exploration or development project may
not be justified because of the commodity price environment at the time or
because of the Company's finding and development costs for such project. No
assurances can be given as to the level or timing of success that the Company
will be able to achieve in acquiring or finding and developing additional
reserves.
Projections relating to the Company's production and financial results rely
on certain assumptions about the Company's continued success in its acquisition
and asset rationalization programs and in its cost management efforts.
The Company's drilling operations are subject to various hazards common to
the oil and gas industry, including explosions, fires, and blowouts, which could
result in damage to or destruction of oil and gas wells or formations,
production facilities and other property and injury to people. They are also
subject to the additional hazards of marine operations, such as capsizing,
collision and damage or loss from severe weather conditions.
Development Risk. A significant portion of the Company's development plans
involve large projects in the Gulf of Mexico and other areas. A variety of
factors affect the timing and outcome of such projects including, without
limitation, approval by the other parties owning working interests in the
project, receipt of necessary permits and approvals by applicable governmental
agencies, the availability of the necessary drilling equipment, delivery
schedules for critical equipment and arrangements for the gathering and
transportation of the produced hydrocarbons.
Foreign Operations Risk. The Company's operations outside of the U.S. are
subject to risks inherent in foreign operations, including, without limitation,
the loss of revenue, property and equipment from hazards such as expropriation,
nationalization, war, insurrection and other political risks, increases in taxes
and governmental royalties, renegotiation of contracts with governmental
entities, changes in laws and policies governing operations of foreign-based
companies, currency restrictions and exchange rate fluctuations and other
uncertainties arising out of foreign government sovereignty over the Company's
international operations. Laws and policies of the U.S. affecting foreign trade
and taxation may also adversely affect the Company's international operations.
4
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The Company's ability to market oil and natural gas discovered or produced
in its foreign operations, and the price the Company could obtain for such
production, depends on many factors beyond the Company's control, including
ready markets for oil and natural gas, the proximity and capacity of pipelines
and other transportation facilities, fluctuating demand for oil and natural gas,
the availability and cost of competing fuels, and the effects of foreign
governmental regulation of oil and gas production and sales. Pipeline and
processing facilities do not exist in certain areas of exploration and,
therefore, any actual sales of the Company's production could be delayed for
extended periods of time until such facilities are constructed.
Competition. The Company actively competes for property acquisitions,
exploration leases and sales of crude oil and natural gas, frequently against
companies with substantially larger financial and other resources. In its
marketing activities, the Company competes with numerous companies for gas
purchasing and processing contracts and for natural gas and NGLs at several
steps in the distribution chain. Competitive factors in the Company's business
include price, contract terms, quality of service, pipeline access,
transportation discounts and distribution efficiencies.
Political and Regulatory Risk. The Company's operations are affected by
national, state and local laws and regulations such as restrictions on
production, changes in taxes, royalties and other amounts payable to governments
or governmental agencies, price or gathering rate controls and environmental
protection regulations. Changes in such laws and regulations, or interpretations
thereof, could have a significant effect on the Company's operations or
financial results.
Potential Environmental Liabilities. The Company's operations are subject
to various national, state and local laws and regulations covering the discharge
of material into, and protection of, the environment. Such regulations affect
the costs of planning, designing, operating and abandoning facilities. The
Company expends considerable resources, both financial and managerial, to comply
with environmental regulations and permitting requirements. Although the Company
believes that its operations and facilities are in general compliance with
applicable environmental laws and regulations, risks of substantial costs and
liabilities are inherent in crude oil and natural gas operations. Moreover, it
is possible that other developments, such as increasingly strict environmental
laws, regulations and enforcement, and claims for damage to property or persons
resulting from the Company's current or discontinued operations, could result in
substantial costs and liabilities in the future.
ITEM EIGHT
FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
For information concerning Item Eight, see pages 36 through 61 of the BR
1999 Annual Report, which information is incorporated herein by reference.
ITEM NINE
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None
5
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PART III
ITEMS TEN AND ELEVEN
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND EXECUTIVE COMPENSATION
Executive officers of the Company follow.
BOBBY S. SHACKOULS, 49
Chairman of the Board, President and Chief Executive Officer, Burlington
Resources Inc., July 1997 to Present.
President and Chief Executive Officer, Burlington Resources Inc., December 1995
to July 1997; President and Chief Executive Officer, Burlington Resources Oil &
Gas Company, October 1994 to Present; Executive Vice President and Chief
Operating Officer, Meridian Oil Inc., June 1993 to October 1994.
H. LEIGHTON STEWARD, 65
Vice Chairman of the Board, Burlington Resources Inc., October 1997 to Present.
Chairman of the Board, President and Chief Executive Officer, The Louisiana Land
and Exploration Company ("LL&E"), November 1996 to October 1997; Chairman of the
Board and Chief Executive Officer, LL&E, September 1995 to November 1996; and
Chairman of the Board, President and Chief Executive Officer, LL&E, January 1989
to September 1995.
JOHN E. HAGALE, 43
Executive Vice President and Chief Financial Officer, Burlington Resources Inc.,
December 1995 to Present.
Executive Vice President and Chief Financial Officer, Burlington Resources Oil &
Gas Company, March 1993 to Present; Senior Vice President and Chief Financial
Officer, Burlington Resources Inc., April 1994 to December 1995.
L. DAVID HANOWER, 40
Senior Vice President, Law and Administration Burlington Resources Inc., July
1998 to Present.
Senior Vice President, Law, Burlington Resources Inc., April 1996 to June 1998,
Vice President, Law, Burlington Resources Inc., April 1991 to April 1996; Senior
Vice President, Law, Burlington Resources Oil & Gas Company, July 1993 to June
1998.
RANDY L. LIMBACHER, 41
President and Chief Executive Officer, Burlington Resources North America, July
1998 to Present.
Vice President, Gulf Coast Division, Burlington Resources Oil & Gas Company,
February 1997 to June 1998; Vice President, Farmington Region, Burlington
Resources Oil & Gas Company, June 1993 to January 1997.
JOHN A. WILLIAMS, 55
President and Chief Executive Officer, Burlington Resources International, July
1998 to Present.
Senior Vice President, Exploration, Burlington Resources Inc., October 1997 to
June 1998; Senior Vice President, Exploration and Production, LL&E, September
1995 to October 1997; Vice President, LL&E, March 1988 to September 1995.
A definitive proxy statement for the 2000 Annual Meeting of Stockholders of
BR will be filed no later than 120 days after the end of the fiscal year with
the Securities and Exchange Commission. The information set forth therein under
"Election of Directors" and "Executive Compensation" is incorporated herein by
reference.
6
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ITEM TWELVE
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required is set forth under the caption "Election of Directors"
in the Proxy Statement for the 2000 Annual Meeting of Stockholders and is
incorporated herein by reference.
ITEM THIRTEEN
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required is set forth under the caption "Election of Directors"
in the Proxy Statement for the 2000 Annual Meeting of Stockholders and is
incorporated herein by reference.
PART IV
ITEM FOURTEEN
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
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FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
Consolidated Statement of Income.......................... **
Consolidated Balance Sheet................................ **
Consolidated Statement of Cash Flows...................... **
Consolidated Statement of Stockholders' Equity............ **
Notes to Consolidated Financial Statements................ **
Report of Independent Accountants......................... **
Supplemental Oil and Gas Disclosures -- Unaudited......... **
Quarterly Financial Data -- Unaudited..................... **
AMENDED EXHIBIT INDEX....................................... A-1
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REPORTS ON FORM 8-K
The Company filed a Form 8-K dated December 3, 1999 which included as
exhibits Press Releases dated November 18, 1999 and November 22, 1999. The first
Press Release announced the completion of the acquisition of Poco by Burlington.
The second Press Release was of detailed pro forma financial information for the
nine months ended September 30, 1999 to reflect the BR acquisition of Poco.
The Company also filed a Form 8-K dated December 21, 1999 which included as
an exhibit a Press Release dated December 16, 1999, announcing preliminary
estimates of year-end 1999 reserves and disclosing that 1999 reserve revisions
would include performance related downward adjustments associated with certain
properties located on the Gulf of Mexico Shelf and in the Permian Basin. BR also
announced that it would record a one-time, non cash charge of approximately $225
million (pretax) to reduce the carrying value of the affected properties in
accordance with Statement of Financial Accounting Standards No. 121.
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** Included in Annual Report and incorporated herein by reference.
7
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SIGNATURES REQUIRED FOR FORM 10-K
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Burlington Resources Inc. has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
BURLINGTON RESOURCES INC.
By BOBBY S. SHACKOULS
------------------------------------
Bobby S. Shackouls
Chairman of the Board, President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of Burlington
Resources Inc. and in the capacities and on the dates indicated.
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By BOBBY S. SHACKOULS Chairman of the Board, January 19, 2000
----------------------------------------------------- President and Chief
Bobby S. Shackouls Executive Officer
JOHN E. HAGALE Executive Vice President and January 19, 2000
- -------------------------------------------------------- Chief Financial Officer
John E. Hagale
PHILIP W. COOK Vice President, January 19, 2000
- -------------------------------------------------------- Controller and Chief
Philip W. Cook Accounting Officer
H. LEIGHTON STEWARD Vice Chairman of the Board January 19, 2000
- --------------------------------------------------------
H. Leighton Steward
JOHN V. BYRNE Director January 19, 2000
- --------------------------------------------------------
John V. Byrne
S. PARKER GILBERT Director January 19, 2000
- --------------------------------------------------------
S. Parker Gilbert
LAIRD I. GRANT Director January 19, 2000
- --------------------------------------------------------
Laird I. Grant
JOHN T. LAMACCHIA Director January 19, 2000
- --------------------------------------------------------
John T. LaMacchia
JAMES F. MCDONALD Director January 19, 2000
- --------------------------------------------------------
James F. McDonald
KENNETH W. ORCE Director January 19, 2000
- --------------------------------------------------------
Kenneth W. Orce
DONALD M. ROBERTS Director January 19, 2000
- --------------------------------------------------------
Donald M. Roberts
JOHN F. SCHWARZ Director January 19, 2000
- --------------------------------------------------------
John F. Schwarz
WALTER SCOTT, JR. Director January 19, 2000
- --------------------------------------------------------
Walter Scott, Jr.
WILLIAM E. WALL Director January 19, 2000
- --------------------------------------------------------
William E. Wall
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BURLINGTON RESOURCES INC.
AMENDED EXHIBIT INDEX
The following exhibits are filed as part of this report.
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EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
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3.1 Certificate of Incorporation of Burlington Resources Inc. as
amended November 18, 1999...................................
3.2 By-Laws of Burlington Resources Inc. amended as of January
13, 1999 (Exhibit 3.2 to Form 10-K, filed February 1999).... *
4.1 Form of Rights Agreement dated as of December 16, 1998,
between Burlington Resources Inc. and The First National
Bank of Boston which includes, as Exhibit A thereto, the
form of Certificate of Designation specifying terms of the
Series A Junior Participating Preferred Stock and, as
Exhibit B thereto, the form of Rights Certificate (Exhibit 1
to Form 8-A, filed December 1998)........................... *
4.2 Indenture, dated as of June 15, 1990, between the registrant
and Citibank, N.A., including Form of Debt Securities
(Exhibit 4.2 to Form 8, filed February 1992)................ *
4.3 Indenture, dated as of October 1, 1991, between the
registrant and Citibank, N.A., including Form of Debt
Securities (Exhibit 4.3 to Form 8, filed February 1992)..... *
4.4 Indenture, dated as of April 1, 1992, between the registrant
and Citibank, N.A., including Form of Debt Securities
(Exhibit 4.4 to Form 8, filed March 1993)................... *
4.5 Indenture dated as of June 15, 1992 among the Registrant and
Texas Commerce Bank National Association (as Trustee)
(Exhibit 4.1 LL&E's Form S-3, as amended, filed November
1993)....................................................... *
10.1 The 1988 Burlington Resources Inc. Stock Option Incentive
Plan as amended (Exhibit 10.4 to Form 8, filed March
1993)....................................................... *
+10.2 Burlington Resources Inc. Incentive Compensation Plan as
amended and restated (Exhibit 10.2 to Form 10-K, filed
February 1997).............................................. *
+10.3 Burlington Resources Inc. Senior Executive Survivor Benefit
Plan dated as of January 1, 1989 (Exhibit 10.11 to Form 8,
filed February 1989)........................................ *
+10.4 Burlington Resources Inc. Deferred Compensation Plan as
amended and restated (Exhibit 10.4 to Form 10-K, filed
February 1997).............................................. *
+10.5 Burlington Resources Inc. Supplemental Benefits Plan as
amended and restated (Exhibit 10.5 to Form 10-K, filed
February 1997).............................................. *
+10.6 Employment Contract between Burlington Resources Inc. and
Bobby S. Shackouls (Exhibit 10.7 to Form 10-K, filed
February 1996).............................................. *
Amendment to Employment Contract between Burlington
Resources Inc. and Bobby S. Shackouls, dated July 9, 1997
(Exhibit 10.6 to Form 10-K, filed February 1998)............ *
Amendment to Employment Contract between the Company and
Bobby S. Shackouls (Exhibit 10.29 to Form 10-Q, filed August
1999).......................................................
+10.7 Employment Contract between Burlington Resources Inc. and H.
Leighton Steward, dated October 22, 1997 (Exhibit 10.7 to
Form 10-K, filed February 1998)............................. *
+10.8 Burlington Resources Inc. Compensation Plan for Non-Employee
Directors as amended and restated (Exhibit 10.8 to Form
10-K, filed February 1997).................................. *
+10.9 Burlington Resources Inc. Key Executive Severance Protection
Plan as amended June 8, 1989 (Exhibit 10.20 to Form 8, filed
February 1992).............................................. *
+10.10 Burlington Resources Inc. Retirement Income Plan for
Directors (Exhibit 10.21 to Form 8, filed February 1991).... *
+10.11 Burlington Resources Inc. 1991 Director Charitable Award
Plan, dated as of January 16, 1991 (Exhibit 10.22 to Form 8,
filed February 1991)........................................ *
10.12 Master Separation Agreement and documents related thereto
dated January 15, 1992 by and among Burlington Resources
Inc., El Paso Natural Gas Company and Meridian Oil Holding
Inc., including exhibits (Exhibit 10.24 to Form 8, filed
February 1992).............................................. *
+10.13 Burlington Resources Inc. 1992 Stock Option Plan for
Non-employee Directors (Exhibit 28.1 of Form S-8, No.
33-46518, filed March 1992)................................. *
+10.14 Burlington Resources Inc. Key Executive Retention Plan and
Amendments No. 1 and 2 (Exhibit 10.20 to Form 8, filed March
1993)....................................................... *
Amendments No. 3 and 4 to the Burlington Resources Inc. Key
Executive Retention Plan (Exhibit 10.17 to Form 10-K, filed
February 1994).............................................. *
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EXHIBIT PAGE
NUMBER DESCRIPTION NUMBER
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+10.15 Burlington Resources Inc. 1992 Performance Share Unit Plan
as amended and restated (Exhibit 10.17 to Form 10-K, filed
February 1997).............................................. *
+10.16 Burlington Resources Inc. 1993 Stock Incentive Plan (Exhibit
10.22 to Form 10-K, filed February 1994).................... *
+10.17 Burlington Resources Inc. 1994 Restricted Stock Exchange
Plan (Exhibit 10.23 to Form 10-K, filed February 1995)...... *
+10.18 Burlington Resources Inc. 1997 Performance Share Unit Plan,
(Exhibit 10.21 to Form 10-K, filed February 1997)........... *
10.19 $400 million Short-term Revolving Credit Agreement, dated as
of February 25, 1998, as Amended and Restated February 23,
1999 between Burlington Resources Inc. and Chase Bank of
Texas, N.A., as agent, dated as of February 23, 1999
(Exhibit 10.22 to Form 10-K filed February 1999)............ *
10.20 $600 million Long-term Revolving Credit Agreement, dated as
of February 25, 1998, between Burlington Resources Inc. and
Morgan Guaranty Trust Company of New York as agent (Exhibit
10.23 to Form 10-K filed February 1999)..................... *
Amendment and Restatement Agreement dated as of February 23,
1999 in respect of the Long-Term Credit Agreement (Exhibit
10.23 to Form 10-K filed February 1999)..................... *
+10.21 Form of Termination Agreement with Certain Senior Management
Personnel as amended (Exhibit 10(a)(i) to LL&E's Form 10-K,
filed March 1996)........................................... *
+10.22 Pension Agreement, dated as of December 27, 1994 (Exhibit
10(e) to LL&E's Form 10-K filed March 1995)................. *
+10.23 Form of The Louisiana Land and Exploration Company Deferred
Compensation Arrangement for Selected Key Employees (Exhibit
10(g) to LL&E's Form 10-K filed March 1991)................. *
Amendment to the LL&E Deferred Compensation Arrangement for
Selected Key Employees dated December 21, 1998 (Exhibit
10.26 to Form 10-K filed February 1999)..................... *
+10.24 The LL&E Supplemental Excess Plan (Exhibit 10(j) to LL&E's
Form 10-K filed March 1993)................................. *
10.25 Severance benefit agreement between Burlington Resources
Inc. and John A. Williams, dated March 25, 1999 (Exhibit
10.28 to Form 10-Q filed May 1999).......................... *
10.26 Form of agreement on pension related benefits with certain
former Seattle holding company office employees.............
10.27 Poco Petroleums Ltd. Incentive Stock Option Plan (Form S-8
No. 333-91247, filed November 18, 1999)..................... *
10.28 Employee Savings Plan for Eligible Employees of Poco
Petroleums Ltd. (Exhibit 4.4 to Form S-8 No. 333-95071,
filed January 20, 2000)..................................... *
13.1 Burlington Resources Inc. 1999 Annual Report................
21.1 Subsidiaries of the Registrant..............................
23.1 Consent of Independent
Accountants -- PricewaterhouseCoopers.......................
23.2 Consent of Independent Accountants -- KPMG..................
27.1 Financial Data Schedule..................................... **
99.1 Audit opinion of KPMG.......................................
</TABLE>
- ---------------
*Exhibit incorporated herein by reference as indicated.
**Exhibit required only for filings made electronically using the Securities and
Exchange Commission's EDGAR System.
+Exhibit constitutes a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this report pursuant to Item 14(c) of
Form 10-K.
A-2
<PAGE> 1
EXHIBIT 3.1
BURLINGTON
RESOURCES
CERTIFICATE OF INCORPORATION
of
BURLINGTON RESOURCES INC.
As Amended Through November 18, 1999
<PAGE> 2
CERTIFICATE OF INCORPORATION
OF
BURLINGTON RESOURCES INC.
ARTICLE 1. NAME
The name of this corporation is Burlington Resources Inc.
ARTICLE 2. REGISTERED OFFICE AND AGENT
The address of the initial registered office of this corporation is
Corporation Trust Center, 1209 Orange Street, Wilmington, County of New Castle,
State of Delaware 19081, and the name of its initial registered agent at such
address is The Corporation Trust Company.
ARTICLE 3. PURPOSES
The purpose of this corporation is to engage in any lawful act or activity
for which corporations may be organized under the General Corporation Law of
Delaware.
ARTICLE 4. SHARES
4.1 Authorized Capital. The total authorized stock of this corporation
shall consist of 325,000,000 shares of common stock having a par value of $.01
per share and 75,000,000 shares of preferred stock having a par value of $.01
per share.
4.2 Issuance of Preferred Stock in Series. The preferred stock may be
issued from time to time in one or more series, the shares of each series to
have such voting powers, full or limited, or no voting powers, and such
designations, preferences and relative, participating, optional or other
special rights and qualifications, limitations or restrictions thereof as are
stated and expressed herein or in the resolution or resolutions providing for
the issue of such series adopted by the Board of Directors.
4.3 Authority of the Board of Directors. Authority is hereby expressly
granted to the Board of Directors of this corporation, subject to the
provisions of this Article 4 and to the limitations prescribed by law, to
authorize the issue of one or more series of preferred stock, and with respect
to each such series to fix by resolution or resolutions providing for the issue
of such series the number of shares of such series, the voting powers, full or
limited, if any, of the shares of such series and the designations, preferences
and relative, participating, optional or other special rights and the
qualifications, limitations or restrictions thereof. The authority of the Board
of Directors with respect to each series of preferred stock shall include, but
not be limited to, the determination or fixing of the following:
(a) The number of shares of such series;
(b) The designation of such series;
(c) The dividend on the shares of such series, the conditions and
dates upon which such dividends shall be payable, the relation which such
dividends shall bear to the dividends payable on any other class or
classes or on any other series of any class or classes of stock of this
corporation and whether such dividends shall be cumulative or
noncumulative;
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<PAGE> 3
(d) Whether the shares of such series shall be subject to redemption
by this corporation and, if made subject to such redemption, the times,
prices, rates, adjustments, and other terms and conditions of such
redemption;
(e) The terms and amounts of any sinking fund provided for the
purchase or redemption of the shares of such series;
(f) Whether or not the shares of such series shall be convertible
into or exchangeable for shares of any other class or classes or of any
other series of any class or classes of stock of this corporation and, if
provision be made for conversion or exchange, the times, prices, rates,
adjustments, and other terms and conditions of such conversion or
exchange;
(g) The extent, if any, to which the holders of the shares of such
series shall be entitled to vote with respect to the election of directors
or otherwise, including the right to elect a specified number or class of
directors, the extent, if any, to which the holders of the shares of such
series shall have (i) separate voting rights with respect to the matters
solely affecting the preferences, rights or powers of such series but not
so affecting the common stock or the entire class of preferred stock and
(ii) on a pro rata basis with other shares of preferred stock having
voting rights, voting rights with respect to matters solely affecting the
preferences, rights or powers of the entire class of preferred stock but
not so affecting the common stock, the number or percentage of votes
required for certain actions, and the extent to which a vote by class or
series shall be required for certain actions;
(h) The restrictions, if any, on the issue or reissue of any
preferred stock;
(i) The amount or amounts payable upon the shares of such series in
the event of voluntary or involuntary liquidation, dissolution or winding
up of the corporation prior to any payment or distribution of the assets
of the corporation to any class or classes of stock of the corporation
ranking junior to the preferred stock;
(j) Whether, and the extent to which, any of the voting powers,
designations, preferences, rights and qualifications, limitations or
restrictions of any such series may be made dependent upon facts
ascertainable outside this Certificate of Incorporation or of any
amendment hereto, or outside the resolution or resolutions providing for
the issuance of such series adopted by the Board of Directors, provided
that the manner in which such facts shall operate upon the voting powers,
designations, preferences, rights and qualifications, limitations or
restrictions of such series is clearly and expressly set forth in the
resolution or resolutions providing for the issuance of such series
adopted by the Board of Directors;
(k) The extent, if any, to which any committee of the Board of
Directors may fix the designations and any of the preferences, privileges
and powers and relative, participating, optional or other special rights
and qualifications, limitations or restrictions of the shares of such
series relating to dividends, redemption, dissolution, any distribution of
assets of this corporation or the conversion into or exchange of such
shares for shares of any other class or classes of stock of this
corporation or any other series of the same or any other class or classes
of stock of this corporation, or fix the number of shares of any such
series or authorize the increase or decrease in the shares of such series;
and
(l) Any other preferences, privileges and powers and relative,
participating, optional or other special rights and qualifications,
limitations or restrictions of such series, as the Board of Directors may
deem advisable, which shall not adversely affect any other class or series
of
2
<PAGE> 4
preferred stock at the time outstanding and which shall not be
inconsistent with the provisions hereof.
4.4 Dividends. Subject to any preferential rights granted to any series
of preferred stock, the holders of shares of the common stock shall be entitled
to receive dividends, out of the funds of this corporation legally available
therefor, at the rate and at the time or times, whether cumulative or
noncumulative, as may be provided by the Board of Directors. The holders of
shares of the preferred stock shall be entitled to receive dividends to the
extent provided by the Board of Directors in designating the particular series
of preferred stock. The holders of shares of the common stock shall not be
entitled to receive any dividends thereon other than the dividends referred to
in this section.
4.5 Voting. The holders of shares of the common stock, on the basis of
one vote per share, shall have the right to vote for the election of members of
the Board of Directors of this corporation and the right to vote on all other
matters, except those matters on which the holders of a separate class or
series of this corporation's stock are entitled to vote separately by class or
series. To the extent provided by resolution or resolutions of the Board of
Directors providing for the issue of a series of preferred stock, the holders
of each such series of preferred stock shall have the right to vote for the
election of members of the Board of Directors of this corporation and the right
to vote on all other matters, except those matters on which the holders of a
separate class or series of this corporation's stock are entitled to vote
separately by class or series.
ARTICLE 5. INCORPORATOR
The name and mailing address of the incorporator are as follows:
Andrew Bor
1900 Washington Building
Seattle, Washington 98101
ARTICLE 6. DIRECTORS
The powers of the incorporator shall terminate upon the filing of this
Certificate of Incorporation with the Secretary of State of the State of
Delaware. The names and mailing addresses of the persons whom are to serve as
Directors until the first annual meeting of stockholders or until their
successors are elected and qualify are:
James W. Becker 999 Third Avenue
Seattle, Washington 98101
Luino Dell'Osso, Jr. 999 Third Avenue
Seattle, Washington 98101
3
<PAGE> 5
ARTICLE 7. BY-LAWS
The Board of Directors shall have the power to adopt, amend or repeal the
By-Laws of this corporation, subject to the power of the stockholders to amend
or repeal such By-Laws. The stockholders having voting power shall also have
the power to adopt, amend or repeal the By-Laws for this corporation.
ARTICLE 8. ELECTION OF DIRECTORS
Except as may be otherwise required by the By-Laws, written ballots are not
required in the election of Directors.
ARTICLE 9. PROVISIONS FOR A COMPROMISE OR ARRANGEMENT
Whenever a compromise or arrangement is proposed between this corporation
and its creditors or any class of them and/or between this corporation and its
stockholders or any class of them, any court of equitable jurisdiction within
the State of Delaware may, on the application in a summary way of this
corporation or of any creditor or stockholder thereof or on the application of
any receiver or receivers appointed for this corporation under the provisions
of section 291 of Title 8 of the Delaware Code or on the application of
trustees in dissolution or of any receiver or receivers appointed for this
corporation under the provisions of section 279 of Title 8 of the Delaware Code
order a meeting of the creditors or class of creditors, and/or of the
stockholders or class of stockholders of this corporation, as the case may be,
to be summoned in such manner as the said court directs. If a majority in
number representing three-fourths in value of the creditors or class of
creditors, and/or of the stockholders or class of stockholders of this
corporation, as the case may be, agree to any compromise or arrangement and to
any reorganization of this corporation as a consequence of such compromise or
arrangement, the said compromise or arrangement and the said reorganization
shall, if sanctioned by the court to which the said application has been made,
be binding on all the creditors or class of creditors, and/or on all the
stockholders or class of stockholders, of this corporation, as the case may be,
and also on this corporation.
ARTICLE 10. PREEMPTIVE RIGHTS
No preemptive rights shall exist with respect to shares of stock or
securities convertible into shares of stock of this corporation.
ARTICLE 11. CUMULATIVE VOTING
The right to cumulate votes in the election of Directors shall not exist
with respect to shares of stock of this corporation.
ARTICLE 12. AMENDMENTS TO CERTIFICATE OF INCORPORATION
This corporation reserves the right to amend or repeal any of the
provisions contained in this Certificate of Incorporation in any manner now or
hereafter permitted by law, and the rights of the stockholders of this
corporation are granted subject to this reservation.
4
<PAGE> 6
ARTICLE 13. LIMITATION OF DIRECTOR LIABILITY
To the full extent that the Delaware General Corporation Law, as it exists
on the date hereof or may hereafter be amended, permits the limitation or
elimination of the liability of directors, a director of this corporation shall
not be liable to this corporation or its stockholders for monetary damages for
breach of fiduciary duty as a director. Any amendment to or repeal of this
Article 13 shall not adversely affect any right or protection of a director of
this corporation for or with respect to any acts or omissions of such director
occurring prior to such amendment or repeal.
ARTICLE 14. ACTION BY STOCKHOLDERS WITHOUT A MEETING
Any action by stockholders of this corporation shall be taken at a meeting
of stockholders and no action may be taken by written consent of stockholders
entitled to vote upon such action.
ARTICLE 15. SPECIAL VOTING REQUIREMENTS
In addition to any affirmative vote required by law, this Certificate of
Incorporation, any agreement with any national securities exchange or
otherwise, any "Business Combination" (as hereinafter defined) involving this
corporation shall be subject to approval in the manner set forth in this
Article 15.
15.1 Definitions
For the purposes of this Article 15:
(a) "Affiliate" and "beneficial owner" are used herein as defined in Rule
12b-2 and Rule 13d-3, respectively, under the Securities Exchange Act of
1934 as in effect on May 25, 1988 (the "1934 Act"). The term "Affiliate"
as used herein shall exclude this corporation, but shall include the
definition of "Associate" as contained in said Rule 12b-2.
(b) An "Interested Stockholder" is a person other than (i) the corporation
or (ii) Burlington Northern Inc., a Delaware corporation ("BNI"), as long
as BNI continues to own at least a majority of the stock of this
corporation entitled to vote for the election of directors ("Voting
Stock") and there has been no Change in Control of BNI since May 25, 1988,
who is (A) the beneficial owner of ten percent or more of the Voting Stock
or (B) an Affiliate of this corporation which (1) at any time within a
two-year period prior to the record date for the vote on a Business
Combination was the beneficial owner of ten percent or more of the Voting
Stock, or (2) at the completion of the Business Combination will be the
beneficial owner of ten percent or more of the Voting Stock.
(c) A "Person" is a natural person or a legal entity of any kind, together
with any Affiliate of such person or entity, or any person or entity with
whom such person, entity or any Affiliate has any agreement or
understanding relating to acquiring, voting or holding Voting Stock.
(d) A "Disinterested Director" is a member of the Board of Directors of
this corporation (other than the Interested Stockholder) who was a
director prior to the time the Interested Stockholder became an Interested
Stockholder, or any director who was recommended for election by the
Disinterested Directors. Any action to be taken by the Disinterested
Directors shall require the affirmative vote of at least two-thirds of the
Disinterested Directors.
5
<PAGE> 7
(e) A "Business Combination" is (i) a merger or consolidation of this
corporation or any of its subsidiaries with an Interested Stockholder;
(ii) the sale, lease, exchange, pledge, transfer or other disposition (A)
by this corporation or any of its subsidiaries of all or a Substantial
Part of the corporation's Assets to an Interested Stockholder, or (B) by
an Interested Stockholder of any of its assets, except in the ordinary
course of business, to this corporation or any of its subsidiaries; (iii)
the issuance of stock or other securities of this corporation or any of
its subsidiaries to an Interested Stockholder, other than on a pro rata
basis to all holders of Voting Stock of the same class held by the
Interested Stockholder pursuant to a stock split, stock dividend or
distribution of warrants or rights; (iv) the adoption of any plan or
proposal for the liquidation or dissolution of this corporation proposed
by or on behalf of an Interested Stockholder; (v) any reclassification of
securities, recapitalization, merger or consolidation or other transaction
which has the effect, directly or indirectly, of increasing the
proportionate share of any Voting Stock beneficially owned by an
Interested Stockholder; or (vi) any agreement, contract or other
arrangement providing for any of the foregoing transactions.
(f) A "Substantial Part of the corporation's Assets" shall mean assets of
this corporation or any of its subsidiaries in an amount equal to twenty
percent or more of the fair market value, as determined by the
Disinterested Directors, of the total consolidated assets of this
corporation and its subsidiaries taken as a whole as of the end of its
most recent fiscal year ended prior to the time the determination is made.
(g) A "Change in Control" shall be deemed to occur (i) if any Person is or
becomes the "beneficial owner" (as defined in Rule 13d-3 of the 1934 Act),
directly or indirectly, of securities of BNI representing twenty percent
or more of the stock of BNI entitled to vote for directors of BNI, (ii)
upon the first purchase of BNI's common stock pursuant to a tender or
exchange offer (other than a tender or exchange offer made by BNI), (iii)
upon the approval by BNI's stockholders of a merger or consolidation, a
sale or disposition of all or substantially all of BNI's assets or a plan
of liquidation or dissolution of BNI, or (iv) if, during any period of two
consecutive years, individuals who at the beginning of such period
constitute the BNI board of directors cease for any reason to constitute
at least a majority thereof, unless the election or nomination for the
election by BNI's stockholders of each new director was approved by a vote
of at least two-thirds of the directors then still in office who were
directors at the beginning of the period.
15.2 Vote Required for Business Combinations
The affirmative vote of not less than fifty-one percent of the Voting
Stock, excluding the Voting Stock of an Interested Stockholder who is a party
to the Business Combination, shall be required for the adoption or
authorization of a Business Combination, unless the Disinterested Directors
determine that:
(a) The Interested Stockholder is the beneficial owner of not less
than eighty percent of the Voting Stock and has declared its intention to
vote in favor of or to approve such Business Combination: or
(b) (i) The fair market value of the consideration per share to be
received or retained by the holders of each class or series of stock of
this corporation in a Business Combination is equal to or greater than the
consideration per share (including brokerage commissions and soliciting
dealer's fees) paid by such Interested Stockholder in acquiring the
largest number of shares of such class of stock previously acquired in any
one transaction or series of related transactions, whether before or after
the Interested Stockholder became an Interested Stockholder and (ii) the
Interested Stockholder shall not have received the benefit, directly or
indirectly (except proportionately as a stockholder), of any loans,
advances, guarantees, pledges or other financial assistance provided by
6
<PAGE> 8
this corporation, whether in anticipation of or in connection with such
Business Combination or otherwise.
15.3 Information Requirements
In the event any vote of holders of Voting Stock is required for the
adoption or approval of any Business Combination, a proxy or information
statement describing the Business Combination and complying with the
requirements of the 1934 Act shall be mailed at a date determined by the
Disinterested Directors to all stockholders of this corporation whether or not
such statement is required under the 1934 Act. The statement shall contain any
recommendations as to the advisability of the Business Combination which the
Disinterested Directors, or any of them, may choose to state and, if deemed
advisable by the Disinterested Directors, an opinion of an investment banking
firm as to the fairness of the terms of such Business Combination. Such firm
shall be selected by the Disinterested Directors and be paid a fee for its
services by this corporation as approved by the Disinterested Directors.
15.4 Amendment
No amendment to this Certificate of Incorporation shall amend, alter,
change or repeal any of the provisions of Article 14 or of this Article 15
unless such amendment shall receive the affirmative vote of not less than
fifty-one percent of the Voting Stock, excluding the Voting Stock of any
Interested Stockholder as defined in Section 15.1 of this Article 15.
OTHER AMENDMENTS
1. SERIES A JUNIOR PARTICIPATING PREFERRED STOCK
Section 1. Designation and Amount. There shall be a series of
Preferred Stock, par value $.0l per share, of the Company which shall be
designated as "Series A Junior Participating Preferred Stock," par value $.01
per share, and the number of shares constituting such series shall be
3,250,000. Such number of shares may be increased or decreased by resolution of
the Board of Directors; provided, that no decrease shall reduce the number of
shares of Series A Junior Participating Preferred Stock to a number less than
that of the shares then outstanding plus the number of shares issuable upon
exercise of outstanding rights, options or warrants or upon conversion of
outstanding securities issued by the Company.
Section 2. Dividends and Distributions.
(A) Subject to the prior and superior rights of the holders
of any shares of any series of Preferred Stock ranking prior and superior to
the Series A Junior Participating Preferred Stock with respect to dividends,
the holders of shares of Series A Junior Participating Preferred Stock in
preference to the holders of shares of Common Stock, par value $.01 per share
(the "Common Stock"), of the Company and any other junior stock, shall be
entitled to receive, when, as and if declared by the Board of Directors out of
funds legally available for the purpose, quarterly dividends payable in cash on
the first day of January, April, July, and October in each year (each such date
being referred to herein as a "Quarterly Dividend Payment Date"), commencing on
the first Quarterly Dividend Payment Date after the first issuance of a share
or fraction of a share of Series A Junior Participating Preferred Stock in an
amount per share (rounded to the nearest cent) equal to the greater of (a) $25,
or (b) subject to the provision for adjustment hereinafter set forth, 100 times
the aggregate per share amount of all cash dividends, and 100 times the
aggregate per share amount (payable in kind) of all non-cash dividends or
7
<PAGE> 9
other distributions other than a dividend payable in shares of Common Stock or
a subdivision of the outstanding shares of Common Stock (by reclassification or
otherwise), declared on the Common Stock since the immediately preceding
Quarterly Dividend Payment Date, or, with respect to the first Quarterly
Dividend Payment Date, since the first issuance of any share or fraction of a
share of Series A Junior Participating Preferred Stock. In the event the
Company shall at any time after December 16, 1998 (the "Rights Declaration
Date") (i) declare any dividend on Common Stock payable in shares of Common
Stock, (ii) subdivide the outstanding Common Stock, or (iii) combine the
outstanding Common Stock into a smaller number of shares, then in each such
case the amount to which holders of shares of Series A Junior Participating
Preferred Stock were entitled immediately prior to such event under clause (b)
of the preceding sentence shall be adjusted by multiplying such amount by a
fraction the numerator of which is the number of shares of Common Stock
outstanding immediately after such event and the denominator of which is the
number of shares of Common Stock that were outstanding immediately prior to
such event.
(B) The Company shall declare a dividend or distribution on
the Series A Junior Participating Preferred Stock as provided in paragraph (A)
above immediately after it declares a dividend or distribution on the Common
Stock (other than a dividend payable in shares of Common Stock); provided that,
in the event no dividend or distribution shall have been declared on the Common
Stock during the period between any Quarterly Dividend Payment Date and the
next subsequent Quarterly Dividend Payment Date, a dividend of $25 per share on
the Series A Junior Participating Preferred Stock shall nevertheless be payable
on such subsequent Quarterly Dividend Payment Date.
(C) Dividends shall begin to accrue and be cumulative on
outstanding shares of Series A Junior Participating Preferred Stock from the
Quarterly Dividend Payment Date next preceding the date of issue of such shares
of Series A Junior Participating Preferred Stock unless the date of issue of
such shares is prior to the record date for the first Quarterly Dividend
Payment Date, in which case dividends on such shares shall begin to accrue from
the date of issue of such shares, or unless the date of issue is a Quarterly
Dividend Payment Date or is a date after the record date for the determination
of holders of shares of Series A Junior Participating Preferred Stock entitled
to receive a quarterly dividend and before such Quarterly Dividend Payment Date
in either of which events such dividends shall begin to accrue and be
cumulative from such Quarterly Dividend Payment Date. Accrued but unpaid
dividends shall not bear interest. Dividends paid on the shares of Series A
Junior Participating Preferred Stock in an amount less than the total amount of
such dividends at the time accrued and payable on such shares shall be
allocated pro rata on a share-by-share basis among all such shares at the time
outstanding. The Board of Directors may fix a record date for the determination
of holders of shares of Series A Junior Participating Preferred Stock entitled
to receive payment of a dividend or distribution declared thereon, which record
date shall be no more than 60 days prior to the date fixed for the payment
thereof.
Section 3. Voting Rights. The holders of shares of Series A Junior
Participating Preferred Stock shall have the following voting rights:
(A) Subject to the provision for adjustment hereinafter set
forth, each share of Series A Junior Participating Preferred Stock shall
entitle the holder thereof to 100 votes on all matters submitted to a vote of
the stockholders of the Company. In the event the Company shall at any time
after the Rights Declaration Date (i) declare any dividend on Common Stock
payable in shares of Common Stock, (ii) subdivide the outstanding Common Stock,
or (iii) combine the outstanding Common Stock into a smaller number of shares,
then in each such case the number of votes per share to which holders of shares
of Series A Junior Participating Preferred Stock were entitled immediately
prior to such event shall be adjusted by multiplying such number by a fraction
the numerator of which is the
8
<PAGE> 10
number of shares of Common Stock outstanding immediately after such event and
the denominator of which is the number of shares of Common Stock that were
outstanding immediately prior to such event.
(B) Except as otherwise provided herein or by law, the
holders of shares of Series A Junior Participating Preferred Stock and the
holders of shares of Common Stock shall vote together as one class on all
matters submitted to a vote of shareholders of the Company.
(C) (i) If at any time dividends on any Series A Junior
Participating Preferred Stock shall be in arrears in an amount equal to six (6)
quarterly dividends thereon, the occurrence of such contingency shall mark the
beginning of a period (herein called a "default period") which shall extend
until such time when all accrued and unpaid dividends for all previous
quarterly dividend periods and for the current quarterly dividend period on all
shares of Series A Junior Participating Preferred Stock then outstanding shall
have been declared and paid or set apart for payment. During each default
period, all holders of Preferred Stock (including holders of the Series A
Junior Participating Preferred Stock) with dividends in arrears in an amount
equal to six (6) quarterly dividends thereon, voting as a class, irrespective
of series, shall have the right to elect two (2) Directors.
(ii) During any default period, such voting right of the holders
of Series A Junior Participating Preferred Stock may be
exercised initially at a special meeting called pursuant to
subparagraph (iii) of this Section 3(C) or at any annual meeting
of shareholders, and thereafter at annual meetings of
stockholders, provided that neither such voting right nor the
right of the holders of any other series of Preferred Stock, if
any, to increase in certain cases, the authorized number of
Directors shall be exercised unless the holders of ten percent
(10%) in number of shares of Preferred Stock outstanding shall
be present in person or by proxy. The absence of a quorum of the
holders of Common Stock shall not affect the exercise by the
holders of Preferred Stock of such voting right. At any meeting
at which the holders of Preferred Stock shall exercise such
voting right initially during an existing default period, they
shall have the right, voting as a class, to elect Directors to
fill such vacancies, if any, in the Board of Directors as may
then exist up to two (2) Directors or, if such right is
exercised at an annual meeting, to elect two (2) Directors. If
the number which may be so elected at any special meeting does
not amount to the required number, the holders of the Preferred
Stock shall have the right to make such increase in the number
of Directors as shall be necessary to permit the election by
them of the required number. After the holders of the Preferred
Stock shall have exercised their right to elect Directors in any
default period and during the continuance of such period, the
number of Directors shall not be increased or decreased except
by vote of the holders of Preferred Stock as herein provided or
pursuant to the rights of any equity securities ranking senior
to or pari passu with the Series A Junior Participating
Preferred Stock.
(iii) Unless the holders of Preferred Stock shall, during an
existing default period, have previously exercised their right
to elect Directors, the Board of Directors may order, or any
stockholder or stockholders owning in the aggregate not less
than ten percent (10%) of the total number of shares of
Preferred Stock outstanding, irrespective of series, may
request, the calling of a special meeting of the holders of
Preferred Stock, which meeting shall thereupon be called by the
Chairman of the Board or the President and Chief Executive
Officer of the Company. Notice of such meeting and of any annual
meeting at which holders of Preferred Stock are entitled to vote
pursuant to this paragraph (C)(iii) shall be given to each
holder of record of Preferred Stock by mailing a copy of such
notice to him at his last address as the same appears on the
books of the Company. Such meeting shall be called for a time
not earlier than 10 days
9
<PAGE> 11
and not later than 60 days after such order or request or in
default of the calling of such meeting within 60 days after such
order or request, such meeting may be called on similar notice
by any stockholder or stockholders owning in the aggregate not
less than ten percent (10%) of the total number of shares of
Preferred Stock outstanding. Notwithstanding the provisions of
this paragraph (C)(iii), no such special meeting shall be called
during the period within 60 days immediately preceding the date
fixed for the next annual meeting of the stockholders.
(iv) In any default period, the holders of Common Stock, and
other classes of stock of the Company if applicable, shall
continue to be entitled to elect the whole number of Directors
until the holders of Preferred Stock shall have exercised their
right to elect two (2) Directors voting as a class, after the
exercise of which right (x) the Directors so elected by the
holders of Preferred Stock shall continue in office until their
successors shall have been elected by such holders or until the
expiration of the default period, and (y) any vacancy in the
Board of Directors may (except as provided in paragraph (C)(ii)
of this Section 3) be filled by vote of a majority of the
remaining Directors theretofore elected by the holders of the
class of stock which elected the Director whose office shall
become vacant. References in this paragraph (C) to Directors
elected by the holders of a particular class of stock shall
include Directors elected by such Directors to fill vacancies as
provided in clause (y) of the foregoing sentence.
(v) Immediately upon the expiration of a default period, (x) the
right of the holders of Preferred Stock as a class to elect
Directors shall cease, (y) the term of any Directors elected by
the holders of Preferred Stock as a class shall terminate, and
(z) the number of Directors shall be such number as may be
provided for in the Restated Certificate of Incorporation or
By-laws irrespective of any increase made pursuant to the
provisions of paragraph (C)(ii) of this Section 3 (such number
being subject, however, to change thereafter in any manner
provided by law or in the Restated Certificate of Incorporation
or By-laws). Any vacancies in the Board of Directors effected by
the provisions of clauses (y) and (z) in the preceding sentence
may be filled by a majority of the remaining Directors.
(D) Except as set forth herein, holders of Series A Junior
Participating Preferred Stock shall have no special voting rights and their
consent shall not be required (except to the extent they are entitled to vote
with holders of Common Stock as set forth herein) for taking any corporate
action.
Section 4. Certain Restrictions.
(A) Whenever quarterly dividends or other dividends or
distributions payable on the Series A Junior Participating Preferred Stock as
provided in Section 2 are in arrears, thereafter and until all accrued and
unpaid dividends and distributions, whether or not declared, on shares of
Series A Junior Participating Preferred Stock outstanding shall have been paid
in full, the Company shall not:
(i) Declare or pay dividends on, make any other distributions
on, or redeem or purchase or otherwise acquire for consideration
any shares of stock ranking junior (either as to dividends or
upon liquidation, dissolution or winding up) to the Series A
Junior Participating Preferred Stock;
(ii) Declare or pay dividends on or make any other distributions
on any shares of stock ranking on a parity (either as to
dividends or upon liquidation, dissolution or
10
<PAGE> 12
winding up) with the Series A Junior Participating Preferred
Stock except dividends paid ratably on the Series A Junior
Participating Preferred Stock and all such parity stock on which
dividends are payable or in arrears in proportion to the total
amounts to which the holders of all such shares are then
entitled;
(iii) Redeem or purchase or otherwise acquire for consideration
shares of any stock ranking on a parity (either as to dividends
or upon liquidation, dissolution or winding up) with the Series
A Junior Participating Preferred Stock provided that the Company
may at any time redeem, purchase or otherwise acquire shares of
any such parity stock in exchange for shares of any stock of the
Company ranking junior (either as to dividends or upon
dissolution, liquidation or winding up) to the Series A Junior
Participating Preferred Stock; or
(iv) Purchase or otherwise acquire for consideration any shares
of Series A Junior Participating Preferred Stock or any shares
of stock ranking on a parity with the Series A Junior
Participating Preferred Stock except in accordance with a
purchase offer made in writing or by publication (as determined
by the Board of Directors) to all holders of such shares upon
such terms as the Board of Directors, after consideration of the
respective annual dividend rates and other relative rights and
preferences of the respective series and classes, shall
determine in good faith will result in fair and equitable
treatment among the respective series or classes.
(B) The Company shall not permit any subsidiary of the Company
to purchase or otherwise acquire for consideration any shares of stock of the
Company unless the Company could, under paragraph (A) of this Section 4,
purchase or otherwise acquire such shares at such time and in such manner.
Section 5. Reacquired Shares. Any shares of Series A Junior
Participating Preferred Stock purchased or otherwise acquired by the Company in
any manner whatsoever shall be retired and cancelled promptly after the
acquisition thereof. All such shares shall upon their cancellation become
authorized but unissued shares of Preferred Stock and may be reissued as part
of a new series of Preferred Stock to be created by resolution or resolutions
of the Board of Directors, subject to the conditions and restrictions on
issuance set forth herein.
11
<PAGE> 13
Section 6. Liquidation, Dissolution or Winding Up.
(A) Upon any liquidation (voluntary or otherwise), dissolution
or winding up of the Company, no distribution shall be made to the holders of
shares of stock ranking junior (either as to dividends or upon liquidation,
dissolution or winding up) to the Series A Junior Participating Preferred Stock
unless, prior thereto, the holders of shares of Series A Junior Participating
Preferred Stock shall have received per share, the greater of 100 times $200 or
100 times the payment made per share of Common Stock, plus an amount equal to
accrued and unpaid dividends and distributions thereon, whether or not
declared, to the date of such payment (the "Series A Liquidation Preference").
Following the payment of the full amount of the Series A Liquidation
Preference, no additional distributions shall be made to the holders of shares
of Series A Junior Participating Preferred Stock unless, prior thereto, the
holders of shares of Common Stock shall have received an amount per share (the
"Common Adjustment") equal to the quotient obtained by dividing (i) the Series
A Liquidation Preference by (ii) 100 (as appropriately adjusted as set forth in
subparagraph C below to reflect such events as stock splits, stock dividends
and recapitalizations with respect to the Common Stock) (such number in clause
(ii), the "Adjustment Number"). Following the payment of the full amount of the
Series A Liquidation Preference and the Common Adjustment in respect of all
outstanding shares of Series A Junior Participating Preferred Stock and Common
Stock, respectively, holders of Series A Junior Participating Preferred Stock
and holders of shares of Common Stock shall receive their ratable and
proportionate share of the remaining assets to be distributed in the ratio of
the Adjustment Number to 1 with respect to such Preferred Stock and Common
Stock, on a per share basis, respectively.
(B) In the event there are not sufficient assets available
to permit payment in full of the Series A Liquidation Preference and the
liquidation preferences of all other series of Preferred Stock, if any, which
rank on a parity with the Series A Junior Participating Preferred Stock then
such remaining assets shall be distributed ratably to the holders of such
parity shares in proportion to their respective liquidation preferences. In the
event there are not sufficient assets available to permit payment in full of
the Common Adjustment, then such remaining assets shall be distributed ratably
to the holders of Common Stock.
(C) In the event the Company shall at any time after the
Rights Declaration Date (i) declare any dividend on Common Stock payable in
shares of Common Stock, (ii) subdivide the outstanding Common Stock, or (iii)
combine the outstanding Common Stock into a smaller number of shares, then in
each such case the Adjustment Number in effect immediately prior to such event
shall be adjusted by multiplying such Adjustment Number by a fraction the
numerator of which is the number of shares of Common Stock outstanding
immediately after such event and the denominator of which is the number of
shares of Common Stock that were outstanding immediately prior to such event.
Section 7. Consolidation, Merger, etc. If the Company shall
enter into any consolidation, merger, combination or other transaction in which
the shares of Common Stock are exchanged for or changed into other stock or
securities, cash and/or any other property then in any such event the shares of
Series A Junior Participating Preferred Stock shall at the same time be
similarly exchanged or changed in an amount per share (subject to the provision
for adjustment hereinafter set forth) equal to 100 times the aggregate amount
of stock, securities, cash and/or any other property (payable in kind), as the
case may be, into which or for which each share of Common Stock is changed or
exchanged. In the event the Company shall at any time after the Rights
Declaration Date (i) declare any dividend on Common Stock payable in shares of
Common Stock, (ii) subdivide the outstanding Common Stock, or (iii) combine the
outstanding Common Stock into a smaller number of shares, then in each such
case the amount set forth in the preceding sentence with respect to the
exchange or change of shares of Series A Junior Participating Preferred Stock
shall be adjusted by multiplying such amount by a fraction the numerator of
which is the number of shares of Common Stock outstanding
12
<PAGE> 14
immediately after such event and the denominator of which is the number of
shares of Common Stock that are outstanding immediately prior to such event.
Section 8. Redemption. The shares of Series A Junior
Participating Preferred Stock shall not be redeemable.
Section 9. Ranking. The Series A Junior Participating
Preferred Stock shall rank junior to all other series of the Company's
Preferred Stock as to the payment of dividends and the distribution of assets,
unless the terms of any such series shall provide otherwise.
Section 10. Fractional Shares. Series A Junior
Participating Preferred Stock may be issued in fractions of a share which shall
entitle the holder, in proportion to such holder's fractional shares, to
exercise voting rights, receive dividends, participate in distributions and to
have the benefit of all other rights of holders of Series A Junior
Participating Preferred Stock. (Added December 15, 1988 and amended January 4,
1999)
2. SPECIAL VOTING STOCK
A series of Preferred Stock is hereby created designated as "Special
Voting Stock." The number of shares constituting such series shall be one (1).
The outstanding share of Special Voting Stock shall be entitled at any relevant
date to the number of votes determined in accordance with the "Plan of
Arrangement" (as that term is defined in that certain "Combination Agreement"
dated as of August 16, 1999, by and between the Corporation and Poco Petroleums
Ltd. ("Poco")) on all matters presented to the stockholders of the Corporation.
Upon the liquidation, dissolution or winding up of the Corporation, the holder
of the Special Voting Stock shall be entitled, prior and in preference to any
distribution to holders of Common Stock and after the distribution to holders
of any class or series of Preferred Stock ranking senior to the Special Voting
Stock of all amounts to which such holders are entitled to receive the sum of
$.01. Except as aforesaid, no dividends or distributions shall be payable to
the holder of Special Voting Stock. The Special Voting Stock shall not be
convertible into any other class or series of the capital stock or into cash,
property or other rights, and may not be redeemed. If the Special Voting Stock
shall be purchased or otherwise acquired by the Corporation, it shall be deemed
retired and shall be canceled and may not thereafter be reissued or otherwise
disposed of by the Corporation. So long as any "Exchangeable Shares" (as that
term is defined in the Combination Agreement) shall be outstanding, the number
of shares comprising the Special Voting Stock shall not be increased or
decreased and no other term of the Special Voting Stock shall be amended,
except upon the unanimous approval of all shares of Common Stock. (Added
November 18, 1999)
13
<PAGE> 1
Exhibit 10.26
The following agreement was entered into by the Company with, among others, John
E. Hagale Executive Vice President and Chief Financial Officer and one other
executive officer, on August 5, 1999.
<PAGE> 2
You were a participant in the Burlington Resources Inc. ("BR") Retention Plan
that was adopted effective March 1, 1992 (the "Retention Plan"). The Retention
Plan offered certain benefits, including a pension enhancement, to those
individuals who were employed at BR's Seattle holding company office on January
1, 1992. In connection with your relocation from Seattle to Houston, you were
asked to sign a waiver of your benefits under the Retention Plan. As you may
know, BR has paid a similar pension enhancement to former eligible BR employees
who relocated from Seattle to Houston, even though they had executed such
waivers. Under these circumstances, it would be inequitable not to treat you
similarly.
The purpose of this letter is to confirm that, upon termination of your
employment and execution by you of BR's customary severance agreement, you will
be paid a lump sum pension enhancement that results from the following
modifications to the provisions of BR's Pension Plan (the "Qualified Plan") and
Supplemental Benefits Plan (the "Supplemental Plan") in effect on the date
hereof:
o The "Lump Sum" calculation assumes you are eligible for and commence early
retirement benefits, including the early retirement supplement, at age 60;
o "Final Average Earnings" at age 60 assumes your base salary increases 6%
per year and you receive your maximum bonus opportunity each year; and
o "Integration Level" at age 60 assumes the Social Security Wage Base
increases 5% per year.
The Lump Sum described above will be determined using the actuarial assumptions
being used at the time of such payment with respect to the Qualified Plan (for
example, the discount rate and mortality assumptions) and will be reduced by the
lump sum value of benefits payable from the Qualified Plan and Supplemental Plan
whether or not such benefits are payable in a lump sum.
BURLINGTON RESOURCES INC.
---------------------------------------
By: Bobby S. Shackouls
Its: Chairman of the Board, President
and Chief Executive Officer
<PAGE> 1
Exhibit 13.1
[BURLINGTON RESOURCES LOGO]
ANNUAL REPORT 1999
OUR FORMULA REMAINS VALUE ADDED GROWTH
[Background Graphics]
<PAGE> 2
BURLINGTON RESOURCES IS ENGAGED IN THE EXPLORATION, DEVELOPMENT, PRODUCTION AND
MARKETING OF OIL AND GAS. THE COMPANY CONDUCTS ACTIVITIES IN SEVERAL STRATEGIC
AREAS WORLDWIDE, AND RANKS FIRST AMONG INDEPENDENT OIL AND GAS COMPANIES IN
TERMS OF PROVED NORTH AMERICAN RESERVES. BR COMBINES THE DIVERSE GLOBAL
OPPORTUNITIES, CRITICAL MASS AND FINANCIAL STRENGTH OF A MAJOR OIL COMPANY WITH
THE ENTREPRENEURIAL SPIRIT, FLEXIBILITY AND RESPONSIVENESS OF AN INDEPENDENT
OPERATOR. OUR HISTORY DATES TO THE 1800'S AND REPRESENTS A HERITAGE OF GROWTH
AND SUCCESS.
CONTENTS
<TABLE>
<S> <C>
Operational Highlights .................................................... 2
Shareholder Letter ........................................................ 4
Review of Operations ...................................................... 7
Financial Review .......................................................... 30
</TABLE>
BURLINGTON RESOURCES
TERMS USED IN THIS REPORT
<TABLE>
<S> <C>
Bbls Barrels
BCF Billion Cubic Feet
BCFE Billion Cubic Feet of Gas Equivalent
MBbls Thousands of Barrels
MMBbls Millions of Barrels
MCF Thousand Cubic Feet
MMCF Million Cubic Feet
MCFE Thousand Cubic Feet of Gas Equivalent
MMCFE Million Cubic Feet of Gas Equivalent
MMBTU Million British Thermal Units
TCF Trillion Cubic Feet
TCFE Trillion Cubic Feet of Gas Equivalent
2-D Two Dimensional
3-D Three Dimensional
NGLs Natural Gas Liquids
DD&A Depreciation, Depletion and Amortization
BR Burlington Resources Inc.
LL&E The Louisiana Land and Exploration Company
Poco Poco Petroleums Ltd.
Shelf Shallow Waters of the Outer Continental Shelf in the Gulf of Mexico
Deepwater Water Depths of 600 Feet or Greater in the Gulf of Mexico
</TABLE>
Proved reserves represent estimated quantities of oil and gas which geological
and engineering data demonstrate, with reasonable certainty, can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Reservoirs are considered proved if shown to be economically
producible by either actual production or conclusive formation tests.
Proved developed reserves are the portion of proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
Proved undeveloped reserves are the portion of proved reserves which can be
expected to be recovered from new wells on undrilled proved acreage, or from
existing wells where a relatively major expenditure is required for completion.
Net acreage and net oil and gas wells are obtained by multiplying gross acreage
and gross oil and gas wells by the Company's working interest percentage in the
properties.
Oil is converted into cubic feet of gas equivalent based on 6 MCF of gas to one
barrel of oil.
[Photo of gas well equipment]
<PAGE> 3
STATISTICAL DATA
OPERATIONAL HIGHLIGHTS
OPERATING DATA
<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C>
YEAR-END PROVED RESERVES
Gas (BCF) 8,280 7,801 7,546
Oil (MMBbls) 329.4 345.6 322.0
Total (BCFE) 10,256 9,875 9,478
PRODUCTION
Gas (MMCF per day) 2,004 2,077 2,052
Oil (MBbls per day) 89.9 104.5 108.1
Total (MMCFE per day) 2,543 2,704 2,701
AVERAGE SALES PRICE
Gas (per MCF) $ 2.01 $1.92 $2.09
Oil (per Bbl) $16.85 $13.00 $19.01
AVERAGE PRODUCTION COSTS (PER MCFE) $ .51 $ .48 $ .50
WELLS DRILLED (NET) 319 520 552
PERCENTAGE SUCCESSFUL 93% 89% 90%
GROSS WELLS BEING DRILLED AT DECEMBER 31, 33 40 74
NET WELLS BEING DRILLED AT DECEMBER 31, 22 26 42
</TABLE>
FINANCIAL DATA
<TABLE>
<CAPTION>
(In Millions, Except per Share Amounts) 1999 1998 1997
<S> <C> <C> <C>
REVENUES $2,065 $2,009 $2,375
OPERATING INCOME (LOSS) (A) 236 (413) 605
NET INCOME (LOSS) (A) 1 (321) 352
BASIC EARNINGS (LOSS) PER COMMON SHARE (A) $ .01 $(1.52) $ 1.69
WEIGHTED AVERAGE COMMON SHARES 216 211 209
CASH FLOWS FROM OPERATIONS $1,102 $ 980 $1,363
CAPITAL EXPENDITURES 989 1,839 1,682
TOTAL ASSETS 7,191 7,086 7,164
TOTAL DEBT 2,820 2,684 2,317
STOCKHOLDERS' EQUITY $3,246 $3,318 $3,550
DEBT TO CAPITAL RATIO 46% 45% 39%
CASH DIVIDENDS PER COMMON SHARE $ .46 $ .46 $ .39
</TABLE>
(A) INCLUDED IN 1999 IS A $225 MILLION NON-CASH, PRETAX CHARGE ($140 MILLION
AFTER TAX OR $.65 PER SHARE) FOR IMPAIRMENT OF OIL AND GAS PROPERTIES. ALSO
INCLUDED IN 1999 IS A $37 MILLION PRETAX CHARGE ($26 MILLION AFTER TAX OR $.12
PER SHARE) FOR MERGER COSTS RELATED TO THE ACQUISITION OF POCO PETROLEUMS LTD.
INCLUDED IN 1998 IS A $706 MILLION ($390 MILLION AFTER TAX OR $1.85 PER SHARE)
NON-CASH, PRETAX CHARGE FOR IMPAIRMENT OF OIL AND GAS PROPERTIES. INCLUDED IN
1997 IS AN $80 MILLION PRETAX CHARGE ($71 MILLION AFTER TAX OR $.34 PER SHARE)
RELATED TO THE LL&E MERGER FOR SEVERANCE AND RELATED TRANSACTION COSTS. ALSO
INCLUDED IN 1997 IS A $50 MILLION PRETAX GAIN ($31 MILLION AFTER TAX OR $.15 PER
SHARE) RELATED TO THE SALES OF OIL AND GAS PROPERTIES ASSOCIATED WITH THE
DIVESTITURE PROGRAM.
[Bar Graphs]
NATURAL GAS RESERVES
December 31,
(TCF)
<TABLE>
<S> <C>
1997 7.5
1998 7.8
1999 8.3
</TABLE>
[ ] = Proved Developed
[ ] = Proved Undeveloped
NATURAL GAS PRODUCTION
Year Ended December 31,
(MMCF per day)
<TABLE>
<S> <C>
1997 2,052
1998 2,077
1999 2,004
</TABLE>
NATURAL GAS PRICES
Year Ended December 31,
($ per MCF)
<TABLE>
<S> <C>
1997 $2.09
1998 $1.92
1999 $2.01
</TABLE>
<PAGE> 4
[Bar Graphs]
OIL RESERVES
December 31,
(MMBbls)
<TABLE>
<S> <C>
1997 322.0
1998 345.6
1999 329.4
</TABLE>
[ ] = Proved Developed
[ ] = Proved Undeveloped
TOTAL RESERVES
December 31,
(TCFE)
<TABLE>
<S> <C>
1997 9.5
1998 9.9
1999 10.3
</TABLE>
RESERVE
REPLACEMENT RATIO *
Year Ended December 31,
(Percent of Production)
<TABLE>
<S> <C>
1997 202%
1998 158%
1999 142%
3 YR. AVG. 168%
</TABLE>
OIL PRODUCTION
Year Ended December 31,
(MBbls per day)
<TABLE>
<S> <C>
1997 108.1
1998 104.5
1999 89.9
</TABLE>
DAILY PRODUCTION
Year Ended December 31,
(MMCFE per day)
<TABLE>
<S> <C>
1997 2,701
1998 2,704
1999 2,543
</TABLE>
RESERVE
REPLACEMENT COSTS*
Year Ended December 31,
($ per MCFE)
<TABLE>
<S> <C>
1997 $ .78
1998 $1.11
1999 $ .70
3 YR. AVG. $ .86
</TABLE>
OIL PRICES
Year Ended December 31,
($ per Bbl)
<TABLE>
<S> <C>
1997 $19.01
1998 $13.00
1999 $16.85
</TABLE>
PROVED RESERVES
BY PRODUCT COMPOSITION
December 31,
<TABLE>
<CAPTION>
1997 1998 1999
<S> <C> <C> <C>
[ ] = Oil 20% 21% 19%
[ ] = Gas 80% 79% 81%
</TABLE>
CAPITAL EXPENDITURES*
Year Ended December 31,
($ Millions)
<TABLE>
<S> <C>
1997 $1,682
1998 $1,839
1999 $ 989
</TABLE>
*Includes Acquisitions
3
<PAGE> 5
[BURLINGTON RESOURCES LOGO]
[Photo of man's Shadow]
TABLES & GRAPHS
<PAGE> 6
TO OUR FELLOW SHAREHOLDERS
WE STRONGLY BELIEVE THAT THE KEY TO THE CREATION OF LASTING, LONG-TERM VALUE IS
EFFECTIVE PORTFOLIO MANAGEMENT RESULTING IN THE DEVELOPMENT OF AN INVENTORY OF
SIGNIFICANT, HIGH QUALITY PROJECTS THAT CAN MAKE A DIFFERENCE TO A COMPANY OF
OUR SIZE.
[BACKGROUND GRAPHICS]
SHAREHOLDER LETTER
[PHOTO OF CHAIRMAN OF THE BOARD, PRESIDENT AND CEO]
Unlike most shareholder letters, I do not plan to devote my comments to our
accomplishments and operating record during the past year. Although we achieved
much in terms of financial, operational and strategic performance, those
achievements are thoroughly addressed in the body of this annual report. It is
my objective to share with you the manner in which our Company is undertaking
fundamental change to improve the financial returns realized by our
shareholders.
Over the past several years, we have made a number of strategic moves,
including the acquisitions of LL&E and Poco, as well as non-core property
divestitures. All of these actions have been designed to transform our Company
into one capable of creating substantial incremental value. This is a goal that
few within the independent segment of our industry have been able to meet. We
coined this new kind of company a "Super Independent" - one that possesses
assets comparable with the large, integrated companies in terms of size and
quality, yet operates with the entrepreneurial mindset of an independent. The
overriding objective in this transformation has been the creation of a platform
for delivering competitive financial returns prospectively. We have
de-emphasized production volume growth in order to concentrate solely on value
enhancement. While this has not been an overwhelmingly popular decision
throughout our investor base, it has been necessary to instill the kind of
capital discipline necessary to meet this singular objective.
We have to deal with certain facts of life in this business. In today's
world, commodity prices are, and will continue to be, volatile. Our financial
results will be impacted by that volatility and our stock is going to react to
commodity price cycles. The types of projects required to generate competitive
returns are, by their very nature, capital intensive and require long cycle
times. There are numerous risks associated with these
4
<PAGE> 7
types of projects, both above and below ground. In order to be successful,
to create value and generate competitive returns, we must proactively manage
these risks and find creative ways to turn these realities into opportunities.
We strongly believe that the key to the creation of lasting, long-term
value is effective portfolio management resulting in the development of an
inventory of significant, high quality projects that can make a difference to a
company of our size. To successfully employ the portfolio management concept, we
must exhibit significant breadth and diversity. We must possess a large
diversified base of high quality production that throws off a substantial volume
of cash flow to fund the numerous projects required to enhance value. We must
control a large inventory of low-risk, predictable development opportunities
that can offset the natural decline that is present in any production base.
Finally, we must explore - we must add high-return reserves through the drill
bit and we must develop an inventory of significant, high quality projects that
can make a difference to a company of our size.
Each property or project must be analyzed independently, including an
assessment of the full range of risks involved. At Burlington Resources, we have
divided our assets into groups of properties and projects that behave similarly
and share common characteristics. We have analyzed each group to identify and
rank those factors which will have the highest impact on the property or
project's potential for future value creation. We then have the ability to mix
and match these properties and projects to balance our risk and maximize our
financial returns in the aggregate. The ability to balance these various aspects
of our business is entirely dependent upon the quality, number and maturity of
the assets and projects that we control.
Our present portfolio of assets possesses a high degree of this breadth and
diversity that is so necessary in order to be a successful independent
exploration and production company. Our high quality production base is
epitomized by the long-lived reserves in the San Juan Basin and the Madden
Field. This is complemented by the vast exploitation opportunities we possess in
western Canada, the San Juan Basin, the East Irish Sea, the Anadarko Basin and
onshore south Louisiana and south Texas. Finally, we have significant
value-adding growth potential through exploration in the Deepwater province of
the Gulf of Mexico, Canada, Algeria and Suriname. I invite you to read more
about each of these areas in the remainder of this report.
[Photo of drilling rig]
[Photo of gas plant separator]
One characteristic that has made the majors successful is that they possess
an enormous inventory of projects which I refer to as a "pipeline." This
pipeline has been filled with opportunities that can be brought to fruition as
needed. Unlike the
[Pie Graphs]
1999 PROVED RESERVES
December 31
Total: 10.3 TCFE
<TABLE>
<S> <C>
US Gas 58%
US Oil 13%
Canadian Gas 14%
Canadian Oil 4%
Other International Gas 9%
Other International Oil 2%
</TABLE>
1999 DAILY PRODUCTION
Year Ended December 31
Total: 2.5 BCFE
<TABLE>
<S> <C>
US Gas 58%
US Oil 14%
Canadian Gas 17%
Canadian Oil 5%
Other International Gas 3%
Other International Oil 3%
</TABLE>
5
<PAGE> 8
ALL OF US AT BURLINGTON RESOURCES ARE COMMITTED TO DELIVERING RELIABLE, ECONOMIC
SOURCES OF ENERGY AS WE MOVE INTO THE 21ST CENTURY.
majors, we have only recently begun to fill our opportunity pipeline. This means
that we are currently spending large sums of capital on projects that won't bear
immediate fruit, but possess tremendous potential for future value creation.
These investments weigh on our current period returns. However, if we don't make
these investments now, we won't be here to compete tomorrow.
[PHOTO OF DRILLING RIG]
We have taken significant steps over the past several years to be the
leading independent in our industry, not just in size but in terms of financial
returns. We have high graded our asset base leaving us with superior core
properties. We have continued to expand our inventory of high quality,
development projects by leveraging our competitive advantages core areas. The
strategic mergers that we have concluded have built upon our organizational
skills and strengths and were both aimed at populating our inventory of projects
for future value creation. We are beginning to see tangible, successful results
from these transactions in places like Madden, Algeria and western Canada.
Finally, we have imposed the capital discipline necessary to preserve our
financial flexibility to take advantage of future opportunities, to see our
current project inventory to fruition and to weather the cyclical downturns for
which our industry has become known. As a result, we believe that we are well
positioned to prosper in the future with significant value generation, despite
the numerous obstacles that face our industry. All of us at Burlington Resources
are committed to delivering reliable, economic sources of energy as we move into
the 21st Century. However, I can assure you that we are all further driven to
achieve this objective only in concurrence with the deliverance of competitive
returns to our shareholders.
In closing, I would like to thank three of our directors who are retiring
from service on our board. John Byrne, Leighton Steward and Bill Wall have
provided valuable advice and unwavering support for many years. We will miss all
three of them and wish them the very best in their future endeavors.
/s/ Bobby S. Shackouls
Bobby S. Shackouls
Chairman, President and Chief Executive Officer
[PHOTO OF COMPUTER]
[PHOTO OF PLATFORM]
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[PHOTO OF MAN'S HAND HOLDING MAP]
REVIEW OF OPERATIONS
NORTH AMERICA
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[PHOTO OF MAN'S HANDS HOLDING MAP]
NORTH AMERICA
BUSINESS AT A GLANCE
Our Company is known first and foremost as a natural gas exploration and
production company. We are the largest independent producer of natural gas in
North America, with proved U.S. and Canadian natural gas reserves of 7.4 TCF, as
of year-end 1999. Our total North American proved reserves at year-end 1999 were
9.1 TCFE. Our North American operations provide the cash flow to fuel the
Company's future growth, as well as a diverse portfolio of value creation
opportunities to achieve that growth.
Our most significant accomplishment in 1999 was the acquisition of Poco
Petroleums Ltd., affording us an entry into the Canadian exploration and
production business and securing a platform for future growth in Canada. Poco's
assets were the perfect complement to our existing North American portfolio.
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Our North American assets play an important role in the balance of our overall
corporate portfolio, providing the largest part of our stable production base.
Our North American production base is complemented by numerous, repeatable
low-risk exploitation opportunities for replacing production and a generous
inventory of high quality exploration plays in the most prospective areas of the
U.S. and Canada.
The San Juan Basin, boasting record production for the thirteenth
consecutive year, best characterizes our stable production base. The Madden
Field in Wyoming is quickly becoming a legacy asset as well. Exploitation
projects in Madden's shallow formations and development of its prolific Deep
Madison Formation are providing opportunities for future production growth and a
substantial, stable cash flow stream that will be used to fund other high growth
opportunities. Exploration plays in the Deepwater of the Gulf of Mexico, western
Canada and the Canadian Northwest Territories provide meaningful opportunities
for value-added growth.
During 1999, oil and gas capital expenditures for our North American
operations totaled $779 million: $185 million for exploration; $459 million for
development projects; and $135 million related to proved reserve acquisitions.
As a result of these investments, we added 923 BCFE to our proved oil and gas
reserves, achieving a reserve replacement ratio of 106 percent. Reserve
replacement costs averaged $.84 per MCFE. Reserve replacement averaged 148
percent over the last three years, with replacement costs averaging $.92 per
MCFE.
Our strategy for North America is to continue to leverage our competitive
strengths to enhance the value of the business. Our engineering capability
allows us to find new ways of reducing drilling and completion costs in
technically challenging areas, such as at the Madden Field in Wyoming; our
natural gas expertise provides us the ability to continue unlocking untapped
hydrocarbon resources in mature basins like the San Juan Basin; and our
financial strength gives us the ability to take advantage of opportunistic
acquisitions and to make prudent capital investments, regardless of commodity
price volatility. These qualities allow our North American operations to
contribute significantly to the overall corporate goal of building long-term
shareholder value.
[PHOTO OF DRILLING RIG]
CANADA
Our entry into Canada through the acquisition of Poco represents a major
milestone in the continuation of a North American natural gas strategy aimed at
delivering competitive returns to our shareholders. The acquisition was a
strategic move that gives us access to one of the largest natural gas resource
bases in North America and provides a platform for significant future growth.
Poco was a logical choice for our debut in Canada because of the nature of its
asset portfolio and its relationship to the core competencies we have developed
at Burlington Resources. Our proven experience and expertise in the areas of
deep drilling, sour gas treating, coalbed methane production and the resolution
of infrastructure, marketing and transportation issues will help us fully
realize the potential of the high quality Canadian assets acquired in the
transaction.
Under the terms of the transaction which closed on November 18, 1999, Poco
shareholders received 0.25 BR common shares or 0.25 BR common equivalent
(exchangeable) shares, at their discretion, for each Poco share held. The
exchangeable shares are Canadian securities, traded on the Toronto Stock
Exchange under the symbol BRX and have the same rights, entitlements and
attributes as shares of BR common stock. The BRX shares are exchangeable at the
shareholder's option for BR common shares on a one for one basis. The
combination of the two companies was accounted for as a pooling of interests and
qualified as a tax-free reorganization.
The Canadian properties we acquired through the Poco transaction represent
an extremely high quality, well-balanced
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CANADIAN EXPLORATION ACTIVITY IS FOCUSED IN THE CENTRAL AND NORTHERN REGIONS OF
ALBERTA AT LOCATIONS SUCH AS HAMBURG, WHITECOURT AND O'CHIESE AND IN NORTHEAST
BRITISH COLUMBIA AT MONKMAN AND MAXHAMISH.
[PHOTO OF MAN ON DRILLING RIG]
asset portfolio that complements our existing asset base. At year-end 1999, our
Canadian proved reserves were approximately 1,870 BCFE; production from our
Canadian properties averaged approximately 429 MMCF per day of gas and 19.4
MBbls per day of oil during 1999. Poco's reserve and production base is
predominantly natural gas, representing respectively 78 and 79 percent of the
total. In addition to producing properties, we also have access to 2.8 million
acres of undeveloped leasehold and the opportunity to take advantage of the
excellent prospect inventory developed by Poco over the last several years.
Viewing the portfolio from a risk profile standpoint, the Canadian asset
base includes low-risk production, located primarily in eastern Alberta and
southeastern Saskatchewan, where the productive horizons are well established
and relatively shallow. Our 1999 program in this region entailed drilling 40
shallow wells and our plans for 2000 call for a similar program. We believe we
can maintain production in this area over the next several years by exploiting
the existing assets through low-cost development and infill drilling. This
region contributed approximately 15 percent of our Canadian production in 1999.
Moving up the risk profile, the majority of the Canadian exploitation
program is located in central Alberta. These exploitation areas are generally
characterized by moderate risk, with multizone hydrocarbon potential and good
access to pipeline and plant infrastructure. The productive reservoirs in these
areas occur in Cretaceous and Jurassic rocks, which are quite similar to the
formations we have efficiently developed for years in the San Juan Basin. We
currently maintain an inventory of over 300 defined drilling locations,
primarily in the Whitecourt, O'Chiese and Harmattan areas of Alberta, and plan
to drill approximately 160 to 170 wells here in 2000. We hold over 1.6 million
undeveloped acres in this trend which contain up to fifteen zones that are gas
productive. This asset base will allow us to continue to generate new projects
for many years to come. This region contributed 65 percent of our Canadian
production in 1999.
[PHOTO OF OIL STORAGE TANKS]
Canadian exploration activity is focused in the central and northern
regions of Alberta at locations such as Hamburg, Whitecourt and O'Chiese and in
northeast British Columbia at Monkman and Maxhamish. These areas present
significant upside potential for us and offer the opportunity to discover world
class natural gas reserves. The risks are greater here and lead-time to
establish production is longer, due to deeper well depths and remote well
locations. In many cases, drilling and completion operations are restricted to
the winter months. Although the deep Devonian plays in this region are higher
risk, single well production rates can be as high as 60 MMCF of gas per day. Our
plans are to drill approximately 76 exploration wells, including 16 deep
Devonian wells in 2000. In 1999, these areas accounted for 20 percent of our
Canadian production
Poco enhanced its position in some of Canada's most exciting natural gas
exploration plays through a farm-in and joint venture negotiated with Chevron
Canada Resources in July 1999. This joint venture involves a multi-well
commitment and
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sharing of operatorship and technical knowledge. The venture gives us access to
800,000 gross acres and all of Chevron's proprietary seismic data, which amounts
to over 7,100 miles of 2-D seismic and 150 square miles of 3-D seismic data. We
have committed to drill 14 wells at our expense over a two-year period ending
June 30, 2001, with an option for a third year. The target formations are at
depths of 11,000 to 15,000 feet. Upon meeting all commitments, we will earn a 50
percent working interest in the Chevron lands.
In September 1999, BR was the successful bidder on two parcels offered in
the Mackenzie Delta area of the Northwest Territories. These land acquisitions
give us a 100 percent working interest in these two parcels located in one of
the most promising exploration areas in North America. In the Mackenzie Delta,
industry has discovered nine TCF of natural gas and one billion Bbls of oil to
date. We have access to lands totaling 364,000 acres for a term of up to nine
years, with a commitment to spend a minimum of $53 million over five years. A
review of existing seismic data began in the fourth quarter of 1999 and a new
seismic program is planned in 2000. The Mackenzie Delta requires a pipeline to
be built to service the region and allow natural gas to reach market.
In terms of key 1999 activity, drilling continued to focus on the deeper
gas-bearing areas of the western Canadian sedimentary basin. During 1999, 153
wells were drilled, with a 93 percent success rate. Of those, 119 were completed
as natural gas wells, 23 as oil wells and 11 were dry and abandoned. Drilling in
1999 included spudding nine deep Devonian exploration wells, seven of which were
still drilling at year-end.
At year-end 1999, the deep drilling program planned for the Kaybob area of
southwestern Alberta is for six wells directed towards deep, large reserve,
Devonian gas prospects. Three more of these wells are currently drilling as a
part of the Chevron/BR joint venture. Our plans are to drill 13 deep gas
prospects in this area during 2000, with half of this exploration program
undertaken on the joint venture lands. We will drill three wells in the
Maxhamish area of northeast British Columbia as part of the joint venture. This
area is a sparsely drilled part of the western Canadian sedimentary basin that
holds significant potential. The area is located south of the Fort Liard area,
where Chevron and other companies have been very successful in drilling for
natural gas.
The acquisition of Poco provided us with a unique opportunity to expand our
North American presence. We added nearly two TCFE of proved reserves to our
base, substantial probable and possible reserve volumes, and a large inventory
of high quality exploration prospects and acreage. We also acquired ownership of
an enormous geological and geophysical database and gained a seasoned,
[PHOTO OF 3 MEN AND DRILLING EQUIPMENT]
THE ACQUISITION OF POCO PROVIDED US WITH A UNIQUE OPPORTUNITY TO EXPAND OUR
NORTH AMERICAN PRESENCE. WHEN YOU ADD THIS TO OUR CORE COMPETENCIES AND
FINANCIAL STRENGTH, YOU HAVE A FORMULA FOR SUCCESS IN DELIVERING LONG-TERM
SHAREHOLDER VALUE.
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ALTHOUGH WE HAVE EXPANDED TO OTHER LOCATIONS AROUND THE GLOBE, THE SAN JUAN
BASIN REMAINS ONE OF OUR MOST IMPORTANT OPERATIONAL AREAS.
[PHOTO OF OIL STORAGE TANK]
knowledgeable Canadian staff. When added to our core competencies and financial
strength, the acquisition of Poco strengthened our formula for successful
delivery of long-term shareholder value.
SAN JUAN BASIN
Our Company had its beginning in the San Juan Basin of New Mexico and today we
are the largest and most active producer in the area, operating over 6,400 wells
in the basin and holding interests in an additional 3,600 non-operated wells. We
also operate the Val Verde gathering system, consisting of the basin's largest
treating plant and approximately 420 miles of gathering lines and 14 compressor
stations.
Although we have expanded to other locations around the globe, the San Juan
Basin remains one of our most important operational areas. At year-end 1999, the
San Juan Basin's 3.8 TCF of proved natural gas reserves represented 46 percent
of our total natural gas assets. The basin is also important because it
generates free cash flow of three to four times the annual investment required
to fund operations in the region. The excess capital generated by our legacy
assets in the San Juan Basin is utilized throughout our Company to help fund our
aggressive worldwide exploration and development program, without unduly taxing
our balance sheet.
Active development of the San Juan Basin began in the early 1950's and many
would consider it to be a mature basin. We continue to defy this view by
consistently using innovative approaches to exploit the basin's multiple zone,
gas reservoirs. Our aggressive program to optimize existing wellbores helps us
remain the lowest cost and most successful operator in the basin. We continually
learn from our experience in this vast "geologic laboratory" and we constantly
pursue new opportunities to apply that knowledge.
Consistent with our history of deriving the maximum value from our assets
in the San Juan Basin, we achieved record production for the thirteenth
consecutive year in 1999. The basin contributed 43 percent of our total daily
net gas production, averaging 864 MMCF per day. The exit volumes at year-end
were even higher, at nearly 900 MMCF per day of natural gas.
Prior to 1998, most of our growth in the basin came from production of
coalbed methane gas from the Fruitland Coal Formation. Beginning in 1997, as the
Fruitland Coal play matured, we began placing greater emphasis on increasing
production from the conventional gas-producing formations, such as the
Mesaverde, the Pictured Cliffs and the Dakota.
The Mesaverde Formation, which consists of the Lewis Shale, Cliffhouse,
Menefee and Point Lookout sands, is the highest producing conventional formation
in the San Juan Basin. It has been extensively developed for over 40 years on
320-acre and 160-acre spacing. In February 1999, the New Mexico Oil Conservation
Division approved our plans for increased density drilling. With regulatory
approval in place to undertake 80-acre infill drilling of the Mesaverde
formation across the entire basin "fairway", we launched an aggressive drilling
program to develop the extensive inventory of development opportunities that
existed. During 1999, we completed 76 of these projects, at a cost of
approximately $23 million. To date we have added over 400 BCFE and developed one
quarter of the reserves. The program's outstanding success calls for development
in 2000 of an additional 90 BCFE at a cost of approximately $30 million. The
remaining program will provide a low cost inventory of opportunities for the
next several years. The 80-acre spacing Mesaverde drilling program also provides
the opportunity to exploit formations that would be less economic to develop on
a stand-alone basis. In 2000, we plan to take advantage of dual development
opportunities with the Pictured Cliffs and Dakota Formations.
Our development program goes beyond the new 80-acre Mesaverde infill
drilling program as we begin exploiting the Lewis Shale. The Lewis Shale
interval is a 1,200 to 1,500 foot thick, organically rich shale found between
the Pictured
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Cliffs sandstone and the Cliffhouse portion of the Mesaverde Formation. The
shale is one of the major hydrocarbon source rocks in the basin, containing a
vast non-traditional gas resource that has been largely overlooked by producers.
Consistent with our never-ending pursuit of new opportunities in the basin, we
started a pilot program in 1998, which was expanded in 1999, to evaluate the
feasibility of commercially developing the Lewis Shale interval. The results
have shown us that commercial quantities of gas can be economically extracted in
areas where the shale is naturally fractured. In 1999, we approached the Lewis
Shale program from two different aspects. We performed 108 completions of the
shale interval in conjunction with new wells drilled as part of the Mesaverde
development program.
Additionally, we successfully completed 62 Lewis payadds in existing well
bores across the basin. Our 1999 program also provided additional data for the
construction of a comprehensive reservoir characterization model, which is being
used to plan for an expanded program for 2000 and beyond. If results continue to
be favorable, we could eventually recomplete over 1,000 wells in the Lewis
Shale.
Using methodology similar to our successful Mesaverde study, we completed a
study of the Dakota formation in 1999. In 2000, we will drill 13 new wells and
deepen over 50 Mesaverde development projects to include the Dakota Formation.
This program strategically tests geological and petrophysical study assumptions
across a wide geographic area and will generate follow-up potential in 2001 and
beyond.
Although production from the Fruitland Coal formation peaked in 1998, we
continue to optimize our coal gas production through the application of
technology. We have an ongoing optimization program that consists of
recavitating existing wells, adding compression and installing artificial lift,
where appropriate, to offset production decline. In 1999 we completed 67
projects throughout the basin and successfully negotiated lower gathering
pressures in the Allison Unit. As a result, coal gas production exceeded our
expectations in 1999, averaging 420 MMCF of gas per day. In 2000, we will
continue to focus on minimizing production decline by completing over 60
projects in the Fruitland Coal Formation.
This Four Corners region is generally thought of as an area for
exploitation and development, but in 1999 we undertook a successful exploration
project in the Paradox Basin of southwestern Colorado. We have substantial
opportunity to capitalize on this exploration success, with a surrounding
acreage position of approximately 150,000 acres. We will undertake additional
drilling on this acreage in 2000.
We aggressively continued to pursue acquisition opportunities in the San
Juan Basin in 1999. We successfully acquired nearly 100 BCFE of proved reserves
in areas that complement our capital programs, much like our Allison Unit
acquisition in 1998. By the end of 1999 we had nearly
[PHOTO OF OIL WELL EQUIPMENT]
THE EXCESS CAPITAL GENERATED BY OUR LEGACY ASSETS IN THE SAN JUAN BASIN IS
UTILIZED THROUGHOUT OUR COMPANY TO HELP FUND OUR AGGRESSIVE WORLDWIDE
EXPLORATION AND DEVELOPMENT PROGRAM, WITHOUT UNDULY TAXING OUR BALANCE SHEET.
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tripled daily production rates in the Allison Unit from the pre-acquisition
average of 40 MMCF of gas per day. We anticipate significant future production
increases from our 1999 acquisition activity.
As evidenced by our aggressive development and exploration programs during
1999, our strategy in the San Juan Basin is to continue doing what we have done
so well. We will relentlessly pursue new opportunities, including acquisitions,
to apply our unsurpassed knowledge of the basin and continue to push our
technological edge in different ways to exploit the enormous untapped natural
gas resource that remains in this 1,000 square mile productive area.
WIND RIVER BASIN
The Madden Field, located in central Wyoming's Wind River Basin, is taking its
place next to the San Juan Basin as a legacy asset which contributes to our
stable production base. This field is a prime example of a property whose value
we are significantly enhancing by creatively using our engineering and marketing
expertise. Application of "best practices" from our other operational areas has
allowed us to reduce drilling costs significantly. Our proactive approach to
gathering and marketing issues, coupled with our innovative hedging program,
assures us of obtaining the maximum financial benefit from our production from
the field.
[PHOTO of drilling rig]
At year-end 1999, total net production from the field stood at 86 MMCF of
gas per day. Although this is only six percent of our current daily production,
the real story of the Madden Field lies with its huge long-lived reserve
potential, the producing characteristics of the deep Madison Formation wells and
the opportunity for continuous growth for a number of years to come.
We operate the Madden Deep Unit and control over 70,000 acres in the area.
The most significant aspect of the field is the deep Madison Formation. In late
1999, we completed drilling of the fourth deep Madison well, the Bighorn 5-6,
which reached a total depth of 25,190 feet. We drilled the well in a record 300
days, 40 percent faster than the last deep Madison well, the Bighorn 4-36. This
operational improvement is a result of applying our innovative engineering
capability to the very complex issues associated with drilling this ultra-deep
well. Drilling, completion and equipment costs are projected at almost $10
million lower than the last well. The Bighorn 4-36, completed in 1997, extended
the lowest known gas in the pool, increasing proved gross reserves to
approximately two TCF. The Bighorn 5-6 further extended downdip the level of
lowest known gas by approximately 210 feet. The incremental increase in the
reservoir's proved reserves will be evaluated in the first quarter of 2000, with
the production testing of the Bighorn 5-6 well. We have begun drilling
operations on the next deep well, the Bighorn 6-27, expecting to achieve total
depth by December 2000. This downdip well provides us the chance to extend the
lowest known gas in this prolific reservoir by an additional 600 feet,
presenting us the opportunity for further substantial increases in proved
reserves.
The three existing deep Madison Formation wells have demonstrated their
ability to sustain production rates in excess of 40 MMCF of gas per day each,
but are constrained by the inlet capacity of the Lost Cabin Gas Plant, which
removes hydrogen sulfide and carbon dioxide from the gas in order to meet
pipeline specifications. During 1999, we doubled the plant capacity from 65 MMCF
to 130 MMCF of gas per day. Existing well performance has been so strong and the
outlook for continued production growth is so positive that we are currently
designing an additional 180 MMCF per day of plant capacity, which should be
completed in mid-2002, bringing total capacity to 310 MMCF of gas per day. We
hold an average working interest in the deep Madison Formation of 48 percent and
own a 51 percent working interest in the Lost Cabin Gas Plant.
In addition to our Madison successes, 1999 was a successful year for the
Madden Field shallow drilling program.
[PHOTO of gas plant]
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During the year, we drilled 14 new wells and accomplished 12 recompletions into
the Lower Fort Union, Lance and Mesaverde Formations. Completed well costs and
drilling time continue to run at about 60 percent of what has been experienced
in prior years. We anticipate a continued active drilling program for the
shallow formations, with 13 new wells and 19 recompletions planned for year
2000.
In March of 1999, we announced a joint venture with Enron Capital and Trade
to build a 124-mile, 24-inch gathering line from the Madden Field to compression
and processing facilities located near Wamsutter, Wyoming. The Lost Creek
Gathering System will relieve the capacity constraints that are being created by
production growth and will provide access to transportation, giving us the
flexibility to move the Madden Field gas to the best available markets. We
anticipate that this project will reduce price differentials and increase
wellhead netbacks, thereby further enhancing the value of the Madden Field gas.
First delivery is anticipated in early fourth quarter of 2000. We hold a 65
percent working interest in the project.
The development of the Madden Field is a work in progress with a very
bright future. We will continue to work on reducing costs to further enhance the
economics, while systematically conducting delineation drilling to ultimately
define the size of the deep Madison Formation reservoir. Our multi-pronged
approach to the Madden Field, which includes continuous drilling, providing
"just in time" processing capacity expansions and proactive solutions for
gathering, transportation and marketing issues, is transforming the Madden Field
into a core asset that will provide an important part of our stable production
base for many years to come.
ANADARKO BASIN
The Anadarko Basin continues to provide numerous low-risk exploitation
opportunities that can contribute to our production base and future growth. The
basin is characterized by stacked productive reservoirs reaching depths over
25,000 feet. We have become highly proficient at drilling these very deep wells,
a skill that will help us in our new endeavors in Canada.
We control over 250,000 net acres in the Anadarko Basin. During 1999, we
completed 31 drilling and workover projects. Average net production for the year
from the basin was 103 MMCF of gas per day.
PERMIAN BASIN
In 1999, we scaled back operations significantly in the Permian Basin as a
result of our ongoing value enhancement program, which dictates that we
constantly evaluate our allocation of capital based on all of the opportunities
available at any given time. In the Permian Basin, this strategy translated into
a high-grading of our activities in 1999.
Most of our 1999 oil & gas capital spent in the basin was focused on the
Sonora, Puckett and Waddell Ranch properties. This activity allowed us to
maintain production, which averaged approximately 74 MMCF of gas per day and 11
MBbls of oil per day.
We will continue to focus on key Permian Basin assets and we have
identified a large inventory of projects for 2000, primarily on the Sonora
properties, which encompass approximately 30,500 net acres. We also plan
increased capital activity on our Waddell Ranch properties, consisting of 37,000
net acres.
WILLISTON BASIN
The Williston Basin, located in western North Dakota and northeast Montana, is
primarily an oil producing region. We have been very successful in this core
area during the past decade by utilizing the horizontal drilling expertise that
we developed in the Bakken shale program of the early 1990's. We continue to
refine this process, drilling many of the current wells with "state of the art"
multilateral drilling technology. These techniques significantly increase the
wellbore's ability to encounter pay, increase wellbore contact to the productive
formation from a single surface location and improve production rates. Our use
of technology, such as advanced horizontal drilling, allows otherwise uneconomic
wells to generate significant additional value.
THE MADDEN FIELD IS A PRIME EXAMPLE OF A PROPERTY WHOSE VALUE WE ARE
SIGNIFICANTLY ENHANCING BY CREATIVELY USING OUR ENGINEERING AND MARKETING
EXPERTISE.
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During 1999, we completed 83 projects in the basin utilizing $34 million of
capital. This is a reduction from the 104 projects we completed in 1998 at a
cost of $89 million. At year end, net daily oil production for the basin was
17.5 MBbls per day compared to an average of 22 MBbls of oil per day in 1998.
Our original plans for the Cedar Hills Field called for construction of
waterflood facilities, infill drilling and conversion of producing wells into
water injectors during 1999. Unitization issues were still pending at year end,
thus delaying the necessary preparatory work for secondary recovery. Our current
plans call for injection well conversions and drilling of 15 wells beginning in
July 2000, with production impact anticipated in 2001.
[PHOTO of platform]
Our efforts in the basin during 1999 were predominantly focused on enhanced
recovery through programs such as East Lookout Butte (ELOB), where horizontal
drilling and waterflood technology provide the opportunity for optimum
production response. During 1999, we drilled 20 wells at ELOB, re-entered four
wells and converted eight wells for water injection. As a result of this
successful project, we are already experiencing production inclines in the ELOB
Waterflood Pilot Area. We will complete the ELOB flood pattern in 2000, with
maximum production response anticipated in 2005.
Our strategy in the Williston Basin is to continue leveraging our technical
competencies of horizontal drilling and enhanced recovery techniques to maximize
the value of the assets contained in the 1,000,000 gross acres we currently
control.
DEEPWATER GULF OF MEXICO
Over the last few years, we have strategically positioned our Company to be a
prime player and operator in what has been deemed as one of the last premier
exploration plays in the U.S. - the Deepwater province of the Gulf of Mexico.
Deepwater growth potential and opportunity for value creation plays an important
role in our future strategy. We maintain one of the largest Deepwater leasehold
positions in the industry, with nearly 200 blocks leased in multiple basins
located in a broad range of water depths.
Our Deepwater exploration program's first full year was 1999. We
participated in drilling six prospects, including our first two operated
prospects, Spoon and Fiesta. The 1999 program, however, did not yield any
commercial discoveries. During 1999 exploration oil and gas capital expenditures
amounted to $60 million, including $4.5 million spent to acquire 11 additional
blocks at lease sales.
In mid-1999, we acquired a 63 percent working interest in the Pluto
Deepwater development project, situated in Mississippi Canyon Blocks 673, 674,
717 and 718 in approximately 2,800 feet of water. The project, completed in
November 1999, entailed drilling a single production well with a subsea
completion tied back to a host platform on South Pass Block 89. Production
operations commenced in late December 1999, with net production of 40 MMCF of
gas per day and 5.8 MBbls of oil per day. The well has produced at gross rates
up to 72 MMCF of gas and 12 MBbls of oil per day. In total, we developed
Deepwater reserves at an acquisition and development cost of $1.04 per MCFE. Our
interest reverts to 49 percent after all costs have been recovered.
We will proceed with our Deepwater drilling program in 2000, continuing to
focus on maturing our portfolio of projects generated by 3-D seismic data. We
anticipate a capital program of approximately $60 million to participate in
drilling at least six Deepwater wells.
Our Deepwater exploration program will provide opportunities over the next
several years to test the numerous prospects we have identified on our extensive
lease block holdings. In addition to exploiting our existing leasehold position,
we will persist in searching for opportunities to participate in high potential
exploration projects on blocks held by others, and in Deepwater development
projects on known discoveries such as Pluto.
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[PHOTO of deepwater drill ship]
THE DEEPWATER GROWTH POTENTIAL AND OPPORTUNITY FOR VALUE CREATION PLAYS AN
IMPORTANT ROLE IN OUR FUTURE STRATEGY. WE MAINTAIN ONE OF THE LARGEST DEEPWATER
LEASEHOLD POSITIONS IN THE INDUSTRY.
Historically, industry commercial success rates in the Deepwater have been about
20 percent, and our high quality acreage position should provide us many
opportunities to be rewarded with future discoveries.
ONSHORE GULF COAST
We maintained a very active exploration and development program in onshore south
Louisiana and south Texas in 1999. Our program is built on the numerous years of
experience accumulated in successfully exploring and developing our 680,000
acres of company-owned fee lands and 100,000 leasehold acres, located primarily
in south Louisiana and South Texas, almost all of which are covered by 3-D
seismic. The fee lands provide us a competitive advantage in an area where lease
acreage costs are high and leasehold positions are difficult to maintain. We
continue to use 3-D seismic to exploit these fee lands and identify additional
exploration potential on third party acreage.
During 1999, we completed approximately 40 projects in south Louisiana,
with almost half of those projects being company-operated. Although much of the
south Louisiana activity is exploitation-oriented, our 1999 exploration program
was extremely encouraging, with a 100 percent success rate.
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We began expanding our onshore Gulf Coast program to south Texas in 1998,
applying the knowledge and expertise we developed in south Louisiana in dealing
with complex faulting, geopressure and depleted sands. We were very active in
south Texas in 1999, drilling a total of nine exploration and development wells.
Much of this activity was located at Armstrong Ranch in Jim Hogg County, in a
field that was first discovered in 1959. Our focus has been on the eighth and
ninth Hinnant Sands in the Wilcox Formation since drilling our first two
successful Armstrong Ranch wells in 1998. A high potential exploration target
was identified at Armstrong Ranch in the Wilcox Fandango section. Preliminary
data from this first Fandango exploration test are very encouraging, with full
results expected early in 2000.
[PHOTO OF MEN AND DRILLING EQUIPMENT]
Following the Wilcox trend northward, we completed a 3-D seismic project in
the Big Thicket area of East Texas during the third quarter of 1999, acquiring
approximately 300 square-miles of 3-D seismic data. At year-end, approximately
one third of the seismic data had been processed and the first exploration well
to test the Lower Wilcox Formation in the Big Thicket was spud.
Our strategy for the onshore Gulf Coast regions of south Louisiana and
south Texas is to continue applying the latest geophysical and drilling
techniques to effectively explore for and develop hydrocarbons on more than
100,000 net acres of leasehold and over 680,000 acres of fee lands under our
control in one of the most prolific producing provinces in the U.S.
GULF OF MEXICO SHELF
During 1999, we decreased our emphasis on the Gulf of Mexico Shelf as part of
our ongoing value enhancement program. The "Shelf Trend", a geographical area
with water depths less than 600 feet, is a mature basin which has begun to offer
smaller reserve potential and to exhibit increasingly steep production decline
rates. Given these circumstances, we reduced capital spending on the Shelf
during 1999 to approximately $24 million, compared to $218 million spent during
1998. Our emphasis has shifted on the Shelf, reducing the number of higher-risk
projects we undertake in favor of lower-risk exploitation and development
projects. We have also shifted our focus to a few core areas on the Shelf where
we operate and maintain a large production infrastructure.
Our 1999 production from the Shelf averaged 218 MMCF of gas per day and 13
MBbls of oil per day, down from the 1998 average of approximately 307 MMCF of
gas per day and 14 MBbls of oil per day of production. These production volume
decreases were, of course, accentuated by reduced capital spending in 1999.
With our substantial core assets and infrastructure on the Shelf, the
historically successful exploitation and development drilling programs will
continue into 2000 and beyond, primarily aimed at maintaining production
volumes. Exploration drilling on the Shelf will play a reduced role in our
future efforts to deliver long-term shareholder value.
OUR PROGRAM IN SOUTH LOUISIANA AND SOUTH TEXAS IS BUILT ON THE NUMEROUS YEARS OF
EXPERIENCE WE HAVE ACCUMULATED IN SUCCESSFULLY EXPLORING AND DEVELOPING ON OUR
FEE LANDS AND LEASEHOLD ACRES, ALMOST ALL OF WHICH ARE COVERED BY 3-D SEISMIC.
18
<PAGE> 21
[MAP AND BACKGROUND GRAPHIC]
REVIEW OF OPERATIONS
INTERNATIONAL
19
<PAGE> 22
[MAP AND BACKGROUND GRAPHIC ON COMPUTER]
INTERNATIONAL
BUSINESS AT A GLANCE
Our strategy to create long-term shareholder value also includes seeking
opportunities in other areas around the world outside of North America.
Significant growth opportunities in North America are limited for a company our
size, because most of the hydrocarbon basins on the continent, with the
exception of parts of Canada, Alaska and the Deepwater Gulf of Mexico, are
extremely mature. We are pursuing high potential exploration and development
opportunities to improve growth prospects through our international operations.
Many of the technical and project management competencies we have developed
through our North American activities are transferable and will enhance our
ability to be successful in the international arena as well.
20
<PAGE> 23
[GRAPHICS]
OUR 1999 EXPERIENCE REINFORCES THE VIABILITY OF A BALANCED APPROACH WHICH
INCLUDES A VALUE-ADDING ACQUISITION PROGRAM, ALONG WITH HIGH IMPACT EXPLORATION
OPPORTUNITIES.
Our international business is charged with building a portfolio of assets
over the next three to five years that can contribute materially to our
financial returns and net asset value. This aggressive goal requires a business
development strategy that includes acquisitions, exploration and exploitation in
order to build a sustainable and growing asset base and production profile. The
key elements in our international strategy are focus, balance and discipline,
and for this reason, we concentrate business development activities in five
focus areas: the Northwest European Shelf; North Africa; Northern South America;
the Far East; and West Africa. We currently have assets and operations in all of
these areas except West Africa.
Our efforts in each of these focus areas continue to be directed toward two
goals: 1) Maximizing the value of our existing asset base through operational
excellence and effective cost management; 2) Recognizing new business
opportunities which will provide materiality, portfolio impact and the
opportunity to progressively grow our international position and influence.
Our 1999 experience reinforces the viability of a balanced approach which
includes a value-adding acquisition program, along with high impact exploration
opportunities. Our goal for 2000 is to bring two of the five focus areas to a
"core area" status through the acquisition of key producing properties that
provide significant exploration upside. Acquisition efforts will be concentrated
in the Northern South America and Far East regions.
International oil and gas capital expenditures totaled $148 million in
1999: $68 million for exploration and $80 million for development. Our
international proved reserves at year-end 1999 totaled 1,136 BCFE, concentrated
primarily in the East Irish Sea, the United Kingdom and Dutch sectors of the
North Sea, Algeria and Egypt. We also have reserves in Colombia and Indonesia.
Proved reserves added during 1999 amounted to 396 BCFE, which equates to a 651
percent reserve replacement ratio in 1999 and an average reserve replacement
ratio of 444 percent for the last three years. Reserves were replaced at a cost
of $.37 per MCFE in 1999, with an average replacement cost of $.61 per MCFE over
the last three years.
Daily gas production from the international business segment grew by 31
percent in 1999, from 67 MMCF of gas per day to 88 MMCF per day, primarily
because of the initiation of production from the East Irish Sea. We have a
series of projects in the East Irish Sea, Algeria and Egypt that should provide
additional production growth over the next several years. Oil production,
primarily from the North Sea, Colombia and Indonesia, accounted for an average
of 13.2 MBbls of oil per day.
At present, international operations represent 11 percent of our total
proved reserves and seven percent of total daily production. Our current
international asset portfolio contains a large inventory of exploration
prospects that provide the opportunity for increasing its relative contribution
to our reserve and production profile. In 1999, we negotiated new exploration
opportunities in Suriname, Ecuador, Peru and Colombia which complement our
existing exploration plays in the North Sea, Algeria and Egypt.
NORTHWEST EUROPEAN SHELF
The Northwest European Shelf provides the majority of our production outside of
North America and includes assets in the United Kingdom, Dutch and Danish
sectors of the North Sea and the East Irish Sea. Prior to 1999, our production
was derived solely from the North Sea. However, we established production from
the East Irish Sea ahead of schedule
[PHOTO OF SUBSEA PRODUCTION EQUIPMENT]
21
<PAGE> 24
[PHOTO OF OIL RIG IN OCEAN]
in the third quarter of 1999, bringing the focus area's average net daily
production to 88 MMCF of gas and 9 MBbls of oil.
U.K. NORTH SEA PRODUCTION COMES FROM TWO PRIMARY LOCATIONS, THE BRAE AND T-BLOCK
COMPLEXES. WE HAVE ESTABLISHED A PROGRAM FOR THESE TWO RELATIVELY MATURE FIELDS
THAT WILL CONTINUE IN 2000.
U.K. North Sea production comes from two primary locations, the Brae and
T-Block Complexes. We have a six percent interest in the Brae Complex and an
eleven percent interest in the T-Block Complex. Both fields are relatively
mature, but in 1999 the operator of the Brae Complex was successful in reducing
the decline rate by drilling low-cost sidetrack wells designed to recover
unswept reserves and implementing pressure maintenance projects. This program
will be continued in 2000.
We currently participate in natural gas exploration and production in the
Dutch sector of the North Sea through our CLAM joint venture. Net gas production
from this area was 33 MMCF per day in 1999, up slightly from the 30 MMCF of gas
per day experienced in 1998. We also participated in the drilling of the Q4-9
exploration well in 1999. This follow-up to a 1998 discovery tested a combined
rate of 54 MMCF of gas per day from two zones and first production is expected
in late 2000.
CLAM has been awarded two exploration licenses in the Danish sector of the
North Sea, the Ribe and Viborg Blocks. During 1999, we acquired 193 square miles
of 3-D seismic data on these blocks, with plans to drill one exploratory well on
each block in 2000.
In late 1997, we acquired ten licenses in the East Irish Sea, covering
267,000 acres. The acquisition included a ninety- percent working interest in
seven operated, undeveloped gas fields with significant recoverable reserve
potential. Phase I of our East Irish Sea project, development of the sweet gas
fields at Dalton and East Millom, began in early 1999. We completed an
aggressive program that called for drilling one new well, re-entering two
existing wells and completing a subsea tieback to Centrica's North Morecambe Bay
platform, ahead of schedule in July 1999. We began production in August 1999,
and the field was producing nearly 90 MMCF of gas per day net to us at year end.
Phase II of the project, development of the West Millom sweet gas field, began
in late 1999. The project timeline calls for a platform to be set in April 2000
and the drilling of three wells, two of which will be multilateral horizontal
wells. First gas production is targeted for November 2000. Phase III,
development of the five sour gas fields to the south, is scheduled to take place
in 2001. Alternatives for processing and transporting gas from these fields are
currently being evaluated and a preferred route is expected to be finalized in
the first quarter of 2000.
During 1999, we identified several new exploration prospects on our
original East Irish Sea acquisition acreage. We plan to drill one of these
prospects in 2000. We also acquired additional properties in the East Irish Sea
containing several promising exploration prospects.
22
<PAGE> 25
WE HAVE EXPLORATION AND DEVELOPMENT ACTIVITIES IN BOTH ALGERIA AND EGYPT THAT
SHOULD PROVIDE GROWING PRODUCTION AND FINANCIAL RETURNS OVER THE NEXT SEVERAL
YEARS.
NORTH AFRICA
Our North African focus area is currently concentrated in Algeria and Egypt. We
have exploration and development activities in both countries that should
provide growing production and financial returns over the next several years.
Algeria represents one of our key entrees into international oil and gas
exploration and our most successful international exploration venture to date.
Since 1989, industry activity in this highly prospective area has discovered in
excess of three billion Bbls of recoverable oil reserves. We first established a
presence in the Berkine Basin of Algeria in 1993 when we signed a Production
Sharing Contract (PSC) for an interest in two exploration blocks. The focus of
our activity is on Menzel Lejmat Block 405, where we are the operator and hold a
65 percent working interest. We have made at least four separate field
discoveries on the block.
Capital and exploration expenditures in Algeria totaled $42 million in
1999. Of this total, we devoted $30 million to exploratory, development and
appraisal drilling, $6 million was related to seismic evaluation and $6 million
was committed to production facility design and construction. We continued to
experience encouraging results in 1999, drilling two successful wildcat
discovery wells and four appraisal wells that delineated previous discoveries.
Our first discovery well in 1999, the MLC-1, tested a separate fault block
located to the east of our main field on Block 405, the MLN Field. The well
flowed at almost 8 MBbls of crude oil per day and 2 MMCF of natural gas per day.
An appraisal well, the MLC-2, was also productive and successfully defined the
reservoir boundary.
The second 1999 wildcat well and potentially the most important, the
MLNW-1, discovered oil in the Strunian F1 zone of a Devonian-age reservoir. The
well tested at 8.5 MBbls of oil per day and 13 MMCF of gas per day. In addition
to its productive capacity, this well was significant because it was the fourth
successful penetration of Devonian-age sandstones on Block 405 where stable,
high quality crude oil was found. This led us to conclude that hydrocarbon
trapping is stratigraphic in nature and possibly widespread. We spudded an
appraisal well, the MLNW-2, in late December 1999 that should provide
[PHOTO of people, trucks and oil field equipment]
23
<PAGE> 26
SIGNIFICANT EXPLORATION POTENTIAL REMAINS ON OUR ALGERIAN ACREAGE. WITH THREE
YEARS REMAINING ON OUR EXPLORATION CONTRACT, WE ARE ACCELERATING EFFORTS TO
IDENTIFY EXPLOITABLE HYDROCARBON DEPOSITS.
additional information regarding the nature and extent of the reservoir.
Our most mature discovery on Block 405, which is nearest to commercial
production, is the MLN Field in the central portion of the block. During 1999,
we continued delineation work on the field by drilling two appraisal wells,
MLN-5 and MLN-6. We completed the MLN-5 well in January 1999 and tested it at
6.8 MBbls of oil per day and 7 MMCF of gas per day from the Devonian-age
Strunian Formation that appears to be productive on a large area of the block.
[PHOTO of jeep and sand dune]
We completed the MLN-6 appraisal well in May 1999. It was the thirteenth
successful well we have drilled on Block 405 and the last appraisal well to be
drilled in the MLN Field prior to the field's first phase of development. The
well tested and flowed at 3.6 MBbls of oil per day and 5 MMCF of gas per day
from the Triassic-age TAG-I Formation.
In late 1999, we prepared to make the transition from exploration and
appraisal to development on Block 405. We filed the application for an
exploitation license agreement (ELA) for development of the MLN Field with
Sonatrach in August 1999. We will develop the field in phases and the first
application relates to the MLN-1, MLN-2, MLN-4 and MLN-5 wells. We anticipate
that first production from the MLN Field should be initiated in late 2001 or
early 2002.
We made a significant discovery on the southeast portion of Block 405 in
1998 at the MLSE Field. The MLSE-1, flow tested at a combined rate of 14.6 MBbls
of oil and 107 MMCF of gas per day from four intervals with a combined net pay
of 190 feet. We completed the drilling of an appraisal well, the MLSE-3, in
January 2000. This well tested at a combined rate of 21.9 MBbls of high quality
oil per day from 131 feet of net pay from three zones. This constituted the
largest production test encountered to date on our block. Our appraisal drilling
has confirmed that this area will be pursued for development and production. We
intend to file an ELA application following final appraisal.
Our other field development on Block 405 is the MLNE discovery in the
northeast corner of the block. The MLNE Field is actually an extension of the
giant Ourhoud Field, discovered on an adjacent block. Based on current plans, we
anticipate first production from the Ourhoud in mid-2002. Development drilling
has been ongoing in 1999, along with base camp construction and front-end
engineering.
Significant exploration potential remains on our Algerian acreage. With
three years remaining on our exploration contract, we are continuing our efforts
to identify exploitable hydrocarbon deposits. We completed the world's largest
contiguous land 3-D seismic survey over a portion of Block 405 in 1999, giving
us nearly full 3-D seismic coverage over the block. This data will be invaluable
in completing the exploration effort and fully evaluating the discoveries that
we have already made. We plan a continuous two-rig drilling program in 2000.
24
<PAGE> 27
We are currently earning a 50 percent working interest in 870,000 gross
acres at the Egyptian Offshore North Sinai Block, located in the Nile River
Delta area of the Mediterranean Sea. The block contains three proved undeveloped
Pliocene gas fields and several additional prospects which are similar in nature
to these Pliocene accumulations.
We have agreed to fund a disproportionate share of development costs in
order to earn our working interest. During 1999, we signed a gas sales agreement
with the Egyptian General Petroleum Company (EGPC) to begin production from our
offshore concession. Production is contracted for the domestic Egyptian market
beginning in 2004 at a daily contract rate of 110 MMCF of gas per day (40 MMCF
per day, net).
Three fields, Tao, Kamose and Seti, will be developed to supply gas through
a new offshore pipeline to the West Harbour onshore processing plant near Port
Said. The total gross investment in this project is expected to be $150 million,
with development activities scheduled to begin in 2002.
NORTHERN SOUTH AMERICA
We continued to pursue opportunities during 1999 that could transform our
northern South American focus area into a core area that would contribute
significantly to our production profile and future growth potential. Currently,
we have non-operated production in Colombia, but the majority of our South
American assets consist of exploration acreage in Venezuela, Peru, Ecuador,
Colombia and Suriname.
Our Colombian production is derived from a 14 percent interest in the
Casanare Association Contract, which covers twelve producing fields. Our net
production from these fields averaged 1.6 MBbls of oil per day in 1999.
In eastern Venezuela, we operate the 525,000 acre Delta Centro Block,
located in the Orinoco River Basin. Our obligation at Delta Centro is to shoot
seismic and drill three exploratory wells before the end of 2001. We have
completed seismic work and drilled our first exploratory well on the block in
early 1999, which proved unsuccessful. The future prospectivity of the block is
greatly diminished, based on the results from our first well. Comprehensive
analysis of the block is ongoing to determine our future course of action.
We hold a 58 percent non-operated interest in Peru's Block 32. The first
exploratory well on Block 32 is planned for drilling in 2000. If successful,
production is anticipated in 2002. The well will test the Guineayacu prospect,
which was identified as a result of the acquisition and processing of 2-D
seismic data in 1998.
In October 1999, we announced that we were negotiating to acquire ARCO's
Ecuadorian assets, which consisted of Block 10 and Block 24, as well as
exploration blocks in Peru and Colombia. A third party exercised its preemptive
purchase right on Ecuador's Block 10, which contains the producing area known as
the Villano Field. We will still acquire the remaining properties at minimal
cost, with closing anticipated in 2000. The remaining properties consist of a
100 percent working interest in Ecuador's Block 24, a 25 percent operated
working interest in Peru's Block 64 and a 50 percent working interest in the
BP/Amoco-operated Los Galeones and La Fragata blocks in Colombia.
In 1999, we became part of a multinational consortium that signed a
contract
[PHOTO OF MEN AND AIR BOAT]
WE CONTINUED TO PURSUE OPPORTUNITIES DURING 1999 THAT COULD TRANSFORM OUR
NORTHERN SOUTH AMERICAN FOCUS AREA INTO A CORE AREA THAT WOULD CONTRIBUTE
SIGNIFICANTLY TO OUR PRODUCTION PROFILE AND FUTURE GROWTH POTENTIAL.
25
<PAGE> 28
with Suriname's state-run oil company to explore for oil off of the country's
Atlantic coast. The contract gives us, as operator, and the other members of the
consortium, exploration rights covering over 18,000 square miles. During 1999,
we acquired and processed 4,100 miles of 2-D seismic covering much of the area.
Interpretation and reprocessing of seismic data through the second quarter of
2000 is aimed at selecting the location for a first well to be spud in early
2001. This frontier exploration play is very exciting because of the geologic
similarities of Suriname to the coasts of West Africa and Brazil, two areas
where numerous large Deepwater hydrocarbon discoveries have been made in recent
years.
[PHOTO OF COMPUTER]
THE FAR EAST IS ONE OF THE TWO INTERNATIONAL FOCUS AREAS WE HAVE SELECTED FOR
MAJOR GROWTH OVER THE NEXT TWO OR THREE YEARS. ACQUISITION OPPORTUNITIES IN THE
SUMATRA AND JAVA BASINS OF INDONESIA OFFER THE BEST POSSIBILITY TO ELEVATE THIS
FOCUS AREA TO "CORE AREA" STATUS.
FAR EAST
We have selected the Far East as a focus area for potential growth. The Far East
is primarily a gas prone region and, except for liquified natural gas (LNG),
regional gas markets are in an early stage of development. We are currently
evaluating acquisition and exploration opportunities in the region that would
capitalize on our expertise in transportation and marketing. Regional gas
markets are expected to show strong growth during the next 20 years as Asia
recovers from its financial slump and large population centers begin using
natural gas.
The Far East is one of the two international focus areas we have selected
for major growth over the next two or three years. Acquisition opportunities in
the Sumatra and Java Basins of Indonesia offer the best possibility to elevate
this focus area to "core area" status. The concept is to use an acquisition to
gain a foothold in highly prospective gas basins and build a value-adding
business through associated exploration and aggressive gas marketing.
Currently, our sole asset in Indonesia is a 15 percent non-operated working
interest in the KAKAP concession in the West Natuna Sea. During 1999, production
averaged 2.2 MBbls of oil per day. Gas production from the concession is
anticipated to commence in April 2001, but could start as early as November
2000. The gas will be transported to the Singapore market under a 22-year sales
agreement. This long-term arrangement enhances the value of our KAKAP reserves,
which historically have had limited marketability.
Our Far East team continues to seek opportunities to add to our current
asset portfolio.
WEST AFRICA
West Africa is the fifth focus area we have selected as a potential platform for
international growth. We chose this region on the basis of the tremendous upside
potential that exists in this prolific hydrocarbon province. During 1999, our
West Africa Business Development Team continued to pursue exploration and
production opportunities that could provide a foundation for future growth. At
year-end 1999, we had developed our play strategy, acquired a significant
technical database within the region and high-graded several possible
exploration entry opportunities.
26
<PAGE> 29
[BACKGROUND GRAPHICS]
REVIEW OF OPERATIONS OF COMPUTERS AND MAN
STATISTICAL DATA
27
<PAGE> 30
RESERVES December 31, 1999
<TABLE>
<CAPTION>
TOTAL
PROVED PROVED PROVED
DEVELOPED UNDEVELOPED RESERVES
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
USA
Gas (BCF) 4,715 1,240 5,955
Oil (MMBbls) 168.3 47.9 216.2
Total USA (BCFE) 5,725 1,527 7,252
- --------------------------------------------------------------------------------
CANADA
Gas (BCF) 1,180 273 1,453
Oil (MMBbls) 57.5 11.6 69.1
Total Canada (BCFE) 1,525 343 1,868
- --------------------------------------------------------------------------------
OTHER INTERNATIONAL
Gas (BCF) 314 558 872
Oil (MMBbls) 13.5 30.6 44.1
Total Other International (BCFE) 395 741 1,136
- --------------------------------------------------------------------------------
WORLDWIDE
Gas (BCF) 6,209 2,071 8,280
Oil (MMBbls) 239.3 90.1 329.4
Total Worldwide (BCFE) 7,645 2,611 10,256
================================================================================
</TABLE>
PRODUCTIVE WELLS December 31, 1999
<TABLE>
<CAPTION>
GROSS NET
- -------------------------------------------------------------------------------
<S> <C> <C>
USA
Oil 5,835 2,900
Gas 10,924 6,106
- --------------------------------------------------------------------------------
CANADA
Oil 1,875 1,243
Gas 2,292 1,519
- --------------------------------------------------------------------------------
OTHER INTERNATIONAL
Oil 391 55
Gas 159 21
- --------------------------------------------------------------------------------
WORLDWIDE
Oil 8,101 4,198
Gas 13,375 7,646
================================================================================
</TABLE>
CAPITAL EXPENDITURES Year Ended December 31 ($ Millions)
<TABLE>
<CAPTION>
1999 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
USA
Oil and Gas Activities $ 488 $ 921 $ 927
Plants & Pipelines 14 60 50
Administration 38 45 40
- --------------------------------------------------------------------------------
Total USA 540 1,026 1,017
- --------------------------------------------------------------------------------
CANADA
Oil and Gas Activities 291 671 405
Plants & Pipelines 4 1 27
Administration 4 2 5
- --------------------------------------------------------------------------------
Total Canada 299 674 437
- --------------------------------------------------------------------------------
OTHER INTERNATIONAL
Oil and Gas Activities 148 136 228
Administration 2 3 -
- --------------------------------------------------------------------------------
Total Other International 150 139 228
- --------------------------------------------------------------------------------
WORLDWIDE
Oil and Gas Activities 927 1,728 1,560
Plants & Pipelines 18 61 77
Administration 44 50 45
- --------------------------------------------------------------------------------
Total Worldwide $ 989 $ 1,839 $ 1,682
===============================================================================
</TABLE>
ACREAGE December 31, 1999
<TABLE>
<CAPTION>
GROSS NET
- --------------------------------------------------------------------------------
<S> <C> <C>
USA
Developed Acres 5,642,763 3,090,045
Undeveloped Acres 11,776,341 9,423,755
- --------------------------------------------------------------------------------
CANADA
Developed Acres 1,034,291 588,761
Undeveloped Acres 4,889,675 2,822,878
- --------------------------------------------------------------------------------
OTHER INTERNATIONAL
Developed Acres 112,435 22,087
Undeveloped Acres 19,264,353 7,392,562
- --------------------------------------------------------------------------------
WORLDWIDE
Developed Acres 6,789,489 3,700,893
Undeveloped Acres 35,930,369 19,639,195
================================================================================
</TABLE>
28
<PAGE> 31
PRODUCTION & PRICES Year Ended December 31,
<TABLE>
<CAPTION>
1999 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
USA
PRODUCTION
Gas (MMCF per day) 1,487 1,580 1,592
Oil (MBbls per day) 57.3 66.2 68.3
AVERAGE SALES PRICE
Gas (per MCF) $ 2.08 $ 1.94 $ 2.16
Oil (per Bbl) $ 16.31 $ 13.31 $ 19.32
- --------------------------------------------------------------------------------
CANADA
PRODUCTION
Gas (MMCF per day) 429 430 383
Oil (MBbls per day) 19.4 21.8 20.9
AVERAGE SALES PRICE
Gas (per MCF) $ 1.76 $ 1.74 $ 1.68
Oil (per Bbl) $ 18.25 $ 11.90 $ 18.00
- --------------------------------------------------------------------------------
OTHER INTERNATIONAL
PRODUCTION
Gas (MMCF per day) 88 67 77
Oil (MBbls per day) 13.2 16.5 18.9
AVERAGE SALES PRICE
Gas (per MCF) $ 1.93 $ 2.56 $ 2.69
Oil (per Bbl) $ 16.80 $ 13.16 $ 18.95
- --------------------------------------------------------------------------------
WORLDWIDE
PRODUCTION
Gas (MMCF per day) 2,004 2,077 2,052
Oil (MBbls per day) 89.9 104.5 108.1
AVERAGE SALES PRICE
Gas (per MCF) $ 2.01 $ 1.92 $ 2.09
Oil (per Bbl) $ 16.85 $ 13.00 $ 19.01
================================================================================
</TABLE>
NET WELLS DRILLED Year Ended December 31,
<TABLE>
<CAPTION>
1999 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
USA
PRODUCTIVE
Exploratory 9.3 16.3 29.0
Development 183.1 297.7 247.5
DRY
Exploratory 9.4 27.5 26.5
Development 4.4 12.5 8.5
- --------------------------------------------------------------------------------
TOTAL NET WELLS
USA 206.2 354.0 311.5
- --------------------------------------------------------------------------------
CANADA
PRODUCTIVE
Exploratory 67.4 71.2 64.7
Development 30.6 72.2 150.1
DRY
Exploratory 3.6 7.3 13.1
Development 4.2 8.4 7.3
- --------------------------------------------------------------------------------
TOTAL NET WELLS
CANADA 105.8 159.1 235.2
- --------------------------------------------------------------------------------
OTHER INTERNATIONAL
PRODUCTIVE
Exploratory 2.1 3.5 2.4
Development 3.2 1.8 1.3
DRY
Exploratory 2.0 2.0 1.3
Development - - 0.1
- --------------------------------------------------------------------------------
TOTAL NET WELLS
OTHER INTERNATIONAL 7.3 7.3 5.1
- --------------------------------------------------------------------------------
WORLDWIDE
PRODUCTIVE
Exploratory 78.8 91.0 96.1
Development 216.9 371.7 398.9
DRY
Exploratory 15.0 36.8 40.9
Development 8.6 20.9 15.9
- --------------------------------------------------------------------------------
TOTAL NET WELLS
WORLDWIDE 319.3 520.4 551.8
================================================================================
</TABLE>
UNIT COSTS Year Ended December 31, ($ per MCFE)
<TABLE>
<CAPTION>
1999 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
USA
Average Production Costs $ .50 $ .48 $ .50
DD&A Rates .65 .59 .58
- --------------------------------------------------------------------------------
CANADA
Average Production Costs .51 .44 .46
DD&A Rates .54 .77 .77
- --------------------------------------------------------------------------------
OTHER INTERNATIONAL
Average Production Costs .54 .71 .60
DD&A Rates .88 1.06 1.08
- --------------------------------------------------------------------------------
WORLDWIDE
Average Production Costs .51 .48 .50
DD&A Rates $ .64 $ .66 $ .65
================================================================================
</TABLE>
29
<PAGE> 32
[BACKGROUND GRAPHICS]
BURLINGTON RESOURCES 1999
Financial Review
<PAGE> 33
BURLINGTON RESOURCES INC.
SELECTED FINANCIAL DATA
The selected financial data for Burlington Resources Inc. set forth below
for the five years ended December 31, 1999 should be read in conjunction with
the consolidated financial statements. Prior year amounts have been restated to
include Poco Petroleums Ltd.
<TABLE>
<CAPTION>
(In Millions, Except per Share Amounts) 1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA
Revenues $ 2,065 $ 2,009 $ 2,375 $ 2,477 $ 1,905
Operating Income (Loss) 236 (413) 605 643 (508)
Net Income (Loss) 1 (321) 352 354 (332)
Basic Earnings (Loss) per Common Share .01 (1.52) 1.69 1.72 (1.65)
Diluted Earnings (Loss) per Common Share $ -- $(1.52) $ 1.67 $ 1.70 $(1.65)
- -------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA
Total Assets $ 7,191 $ 7,086 $ 7,164 $ 6,790 $ 6,169
Long-term Debt 2,769 2,684 2,317 2,223 2,306
Stockholders' Equity 3,246 3,318 3,550 3,320 2,848
Cash Dividends Declared per Common Share $ .46 $ .46 $ .39 $ .37 $ .38
Common Shares Outstanding 216 216 209 209 201
</TABLE>
31
<PAGE> 34
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACQUISITION OF POCO
On August 16, 1999, the Company entered into a definitive agreement to
acquire Poco Petroleums Ltd. ("Poco"), a corporation existing under the laws of
the Province of Alberta, Canada (the "Acquisition"). The Acquisition was
consummated on November 18, 1999.
Under the terms of the Acquisition, Poco shareholders received .25 BR common
equivalent shares ("exchangeable shares"), totaling 38,393,135 BR shares, for
each Poco share held. The exchangeable shares are Canadian securities, which
began trading on The Toronto Stock Exchange November 23, 1999 under the symbol
BRX. These shares have the same voting rights, dividend entitlements and other
attributes as shares of BR Common Stock and are exchangeable, at each
shareholder's option, for to BR Common Stock on a one for one basis. The
Acquisition was accounted for as a pooling of interests.
All operational and financial information contained herein includes the
business activities of Poco for all periods presented.
FINANCIAL CONDITION AND LIQUIDITY
The Company's long-term debt to capital ratio at December 31, 1999 and 1998
was 46 percent and 45 percent, respectively.
The Company has unused credit commitments in the form of revolving
facilities ("revolvers") as of December 31, 1999. These revolvers are available
to cover debt due within one year, therefore, commercial paper, credit facility
notes and a portion of fixed-rate debt due within one year are classified as
long-term debt. During 1999, due to debt covenant violations, the Company
obtained waivers related to certain of its Canadian debt. In addition, the
Company has the capacity to issue $1 billion of securities under a shelf
registration statement filed with the Securities and Exchange Commission. The
revolvers are comprised of agreements for $600 million, $400 million, $310
million, $121 million and $52 million. The $600 million revolver expires in
February 2003. The other credit facilities expire in March 2000 unless renewed
by mutual consent, with the exception of the $52 million revolver which is
cancelable by the creditor upon demand. Balances outstanding on the $310 million
revolver automatically become five year amortizing notes at expiration of the
agreement.
In March 1999 and April 1999, the Company issued $450 million of 7 3/8
percent fixed-rate debt and $19 million of 6.40 percent fixed-rate debt,
respectively. During 1999, the Company repaid $474 million of fixed-rate debt.
The Company has a total of $961 million of debt to be repaid in 2000. Of this
amount, $362 million represents fixed-rate debt which the Company intends to
refinance with other fixed-rate long-term debt. The remaining $599 million is
comprised of $267 million of commercial paper outstanding at December 31, 1999
with an average interest rate of 7 percent and $332 million of credit facility
notes with interest rates between 5 and 6 percent.
In July 1998, the Company's Board of Directors approved the repurchase of
up to two million shares of its Common Stock. During 1999, the Company
repurchased 250,000 shares of its Common Stock for $9 million. Since December
1988, the Company has repurchased approximately 32 million shares.
Net cash provided by operating activities for 1999 was $1,102 million
compared to $980 million and $1,363 million in 1998 and 1997, respectively. The
increase in 1999 compared to 1998 was primarily due to higher operating income
and working capital and other changes. The decrease in 1998 compared to 1997 was
primarily due to significantly lower operating income and lower working capital
and other changes.
The Company and its subsidiaries are named defendants in numerous lawsuits
and named parties in numerous governmental and other proceedings arising in the
ordinary course of business. While the outcome of lawsuits and other proceedings
cannot be predicted with certainty, management believes these matters will not
have a material adverse effect on the consolidated financial position of the
Company, although results of operations and cash flows could be significantly
impacted in the reporting periods in which such matters are resolved.
The Company has certain other commitments and uncertainties related to its
normal operations. Management believes that there are no other commitments or
uncertainties that will have a material adverse effect on the consolidated
financial position, results of operations or cash flows of the Company.
CAPITAL EXPENDITURES AND RESOURCES
Capital expenditures during 1999 totaled $989 million compared to $1,839
million and $1,682 million in 1998 and 1997, respectively. The Company invested
$792 million on internal development and exploration during 1999 compared to
$1,291 million and $1,220 million in 1998 and 1997, respectively. The Company
invested $135
32
<PAGE> 35
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
million for proved property acquisitions in 1999 compared to $437 million and
$340 million in 1998 and 1997, respectively.
Capital expenditures for 2000, excluding proved property acquisitions, are
projected to be approximately $1 billion. Capital expenditures are expected to
be primarily for internal development and exploration of oil and gas properties
and plant and pipeline expenditures. Capital expenditures will be funded from
internal cash flows, supplemented, if needed, by external financing.
MARKETING
North America
The Company's marketing strategy is to maximize the value of its production
by developing marketing flexibility from the wellhead to its ultimate sales. The
Company's natural gas production is gathered, processed, exchanged and
transported utilizing various firm and interruptible contracts and routes to
access the highest value market hubs. The Company's customers include local
distribution companies, electric utilities, industrial users and marketers. The
Company maintains the capacity to ensure its production can be marketed either
at the wellhead or downstream at market sensitive prices.
All of the Company's crude oil production is sold to third parties at the
wellhead or transported to market hubs where it is sold or exchanged. NGLs are
typically sold at field plants or transported to market hubs and sold to third
parties.
International
The Company's international production is marketed to third parties either
directly by the Company or by the operators of the properties. Production is
sold at the platforms or local sales points based on spot or contract prices.
COMMODITY RISK
Substantially all of the Company's crude oil and natural gas production is
sold on the spot market or under short-term contracts at market sensitive
prices. Spot market prices for domestic crude oil and natural gas are subject to
volatile trading patterns in the commodity futures market, including among
others, the New York Mercantile Exchange ("NYMEX"). Quality differentials,
worldwide political developments and the actions of the Organization of
Petroleum Exporting Countries also affect crude oil prices.
There is also a difference between the NYMEX futures contract price for a
particular month and the actual cash price received for that month in a U.S.
producing basin or at a U.S. market hub, which is referred to as the "basis
differential."
The Company utilizes over-the-counter price and basis swaps as well as
options to hedge its production in order to decrease its price risk exposure.
The gains and losses realized as a result of these derivative transactions are
substantially offset when the hedged commodity is delivered. In order to
accommodate the needs of its customers, the Company also uses price swaps to
convert natural gas sold under fixed price contracts to market prices.
The Company uses a sensitivity analysis technique to evaluate the
hypothetical effect that changes in the market value of crude oil and natural
gas may have on the fair value of the Company's derivative instruments. At
December 31, 1999, the potential decrease in fair value of derivative
instruments assuming a 10 percent adverse movement (an increase in the
underlying commodities price) would result in a $65 million increase in the net
deferred amount.
For purposes of calculating the hypothetical change in fair value, the
relevant variables include the type of commodity, the commodity futures prices,
the volatility of commodity prices and the basis and quality differentials. The
hypothetical change in fair value is calculated by multiplying the difference
between the hypothetical price (adjusted for any basis or quality differentials)
and the contractual price by the contractual volumes.
FOREIGN CURRENCY RISK
The Company's reported cash flows related to Canadian operations is based
on cash flows measured in Canadian dollars converted to the U.S. dollar
equivalent based on the average of the Canadian and U.S. dollar exchange rates
for the period reported. The Company's Canadian subsidiary has financial
obligations that are denominated in U.S. dollars. A decrease in value of 10
percent in Canadian dollars relative to the U.S. dollar from the year-end
exchange rate would result in a foreign currency loss of $20 million based on
December 31, 1999 amounts. The Company considers its current risk exposure to
exchange rate movements, based on net cash flows, to be immaterial.
33
<PAGE> 36
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
DIVIDENDS
On January 19, 2000, the Board of Directors declared a common stock
quarterly cash dividend of $.1375 per share, payable April 3, 2000 to
shareholders of record on March 10, 2000. Dividend levels are determined by the
Board of Directors based on profitability, capital expenditures, financing and
other factors. The Company declared cash dividends on Common Stock totaling
approximately $103 million during 1999.
RESULTS OF OPERATIONS
Year Ended December 31, 1999 Compared With Year Ended December 31, 1998
The Company reported net income of $1 million or $.01 basic earnings per
common share in 1999 compared to a net loss of $321 million or $1.52 basic loss
per common share in 1998. The 1999 and 1998 results included a non-cash per
share charge of $.65 and $1.85, respectively, related to the impairment of oil
and gas properties. The Company evaluates the impairment of its oil and gas
properties on a field-by-field basis whenever events or changes in circumstances
indicate an asset's carrying amount may not be recoverable. Unamortized capital
costs are reduced to fair value if the sum of the expected undiscounted future
cash flows is less than the assets' net book value. Cash flows are determined
based upon proved reserves using prices and costs consistent with those used for
internal decision making. In the fourth quarter of 1999, the Company determined
there would be performance related downward reserve adjustments associated with
certain properties located on the Gulf of Mexico shelf and in the Permian Basin.
As a result, the Company recognized a pretax impairment charge of $225 million
($140 million after tax) related to those properties. In the fourth quarter of
1998, the market experienced a weakness in commodity prices. The Company
subjected all properties to impairment testing and subsequently recognized a
pretax impairment charge related to certain Canadian properties of $706 million
($390 million after tax). The 1999 results also included a $.12 per share charge
related to severance and transaction costs associated with the Acquisition.
Revenues were $2,065 million in 1999 compared to $2,009 million in 1998.
Average oil prices increased 30 percent to $16.85 per barrel in 1999 and average
gas prices increased 5 percent to $2.01 per MCF which increased revenues $126
million and $65 million, respectively. Oil sales volumes decreased 14 percent in
1999 to 89.9 MBbls per day and gas sales volumes decreased 4 percent to 2,004
MMCF per day which decreased revenues $69 million and $51 million, respectively.
Oil sales volumes decreased primarily due to natural production declines in the
Gulf Coast, Mid-Continent and North Sea areas.
Costs and Expenses were $1,829 million in 1999 compared to $2,422 million
in 1998. Costs and expenses in 1999 and 1998 included a $225 million and $706
million charge, respectively, related to the impairment of oil and gas
properties. Costs and expenses in 1999 also included a charge of $37 million
related to severance and transaction costs associated with the Acquisition.
Excluding the $262 million of charges in 1999 and the $706 million charge in
1998, costs and expenses in 1999 decreased $149 million compared to 1998. The
decrease was primarily due to a $114 million decrease in exploration costs and a
$48 million decrease in depreciation, depletion and amortization ("DD&A").
Exploration costs decreased due to lower exploratory spending resulting in lower
geological and geophysical ("G&G") expenses of $58 million and lower exploratory
dry hole expense of $69 million partially offset by higher impairment expense of
$13 million. DD&A decreased due to lower production volumes and a lower unit
rate resulting in reduced expenses of $38 million and $16 million, respectively,
partially offset by higher fixed-rate expense of $6 million.
Interest Expense was $211 million in 1999 compared to $193 million in 1998.
The increase was primarily due to higher outstanding fixed-rate debt and higher
outstanding commercial paper borrowings during 1999.
Other Expense (Income) -- Net was an expense of $2 million in 1999 compared
to income of $8 million in 1998. The decrease in other income is primarily due
to lower interest income in 1999.
Income taxes were an expense of $22 million, a rate of 95 percent in 1999
compared to a benefit of $277 million, a rate of 46 percent in 1998. The
increased tax expense in 1999 compared to 1998 was primarily a result of
substantially higher pretax income and lower benefits from nonconventional fuel
tax credits.
Year Ended December 31, 1998 Compared With Year Ended December 31, 1997
The Company reported a net loss of $321 million or $1.52 basic loss per
common share in 1998 compared to
34
<PAGE> 37
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
net income of $352 million or $1.69 basic earnings per common share in 1997. The
1998 results included a non-cash per share charge of $1.85 related to the
impairment of oil and gas properties. The 1997 results included a $.34 per share
charge for severance and transaction costs related to the 1997 merger ("Merger")
with The Louisiana Land and Exploration Company ("LL&E"). The 1997 results also
included a per share gain of $.15 related to the sales of oil and gas properties
associated with the divestiture program.
Revenues were $2,009 million in 1998 compared to $2,375 million in 1997.
Average oil prices decreased 32 percent to $13.00 per barrel in 1998 and average
gas prices decreased 8 percent to $1.92 per MCF which decreased revenues $229
million and $129 million, respectively. Oil sales volumes decreased 3 percent to
104.5 MBbls per day which decreased revenues $25 million. Oil sales volumes
decreased primarily due to natural declines in the Gulf Coast and Mid-Continent
areas. Gas sales volumes increased 1 percent to 2,077 MMCF per day which
increased revenues $19 million.
Costs and Expenses were $2,422 million in 1998 compared to $1,770 million
in 1997. Costs and expenses in 1998 included a $706 million charge related to
the impairment of oil and gas properties. Costs and expenses in 1997 included an
$80 million charge for severance and transaction costs associated with the
Merger. Excluding the $706 million charge in 1998 and the $80 million charge in
1997, costs and expenses in 1998 increased $26 million from 1997. The increase
was primarily due to a $44 million increase in exploration costs partially
offset by a $19 million decrease in production taxes. Exploration costs
increased due to higher exploratory spending resulting in higher G&G expenses.
Production taxes decreased primarily due to lower oil and gas revenues.
Interest Expense was $193 million in 1998 compared to $174 million in 1997.
The increase was primarily due to higher outstanding fixed-rate debt and higher
outstanding commercial paper borrowings during 1998.
Other Expense (Income) -- Net was income of $8 million in 1998 compared to
income of $39 million in 1997. The decrease in other income was primarily
related to lower gains on sales of oil and gas properties and higher losses
related to foreign exchange transactions.
Income taxes were a benefit of $277 million, a rate of 46 percent in 1998
compared to an expense of $118 million, a rate of 25 percent in 1997. The
decrease in tax expense in 1998 compared to 1997 is primarily a result of lower
pretax income partially offset by lower benefits from nonconventional fuel tax
credits.
OTHER MATTERS
Year 2000 Compliance
The year 2000 issue is the result of computer systems and other equipment
with embedded chips or processors using two digits instead of four to define a
specific year and potentially being unable to process accurately certain data
before, during or after the year 2000. This could result in system failures or
miscalculations, causing disruptions to various activities and operations.
During 1999, the Company completed its year 2000 readiness plan for its
critical information technology and operating systems. The readiness plan
involved four phases: assessment, remediation, testing and implementation. Since
entering the year 2000, the Company has not experienced any significant year
2000 failures in its own information technology or operating systems or those of
its vendors. The Company will continue to monitor these systems throughout the
year but does not anticipate any material disruptions.
The year 2000 readiness plan was funded through operating cash flows at an
approximate cost of $3 million.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued Statement No.
133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging
Activities." SFAS 133, as amended, establishes accounting and reporting
standards for derivative instruments and for hedging activities. It requires
enterprises to recognize all derivatives as either assets or liabilities in the
balance sheet and measure those instruments at fair value. The requisite
accounting for changes in the fair value of a derivative will depend on the
intended use of the derivative and the resulting designation. The Company must
adopt SFAS 133 effective January 1, 2001. Based on the Company's outstanding
derivatives contracts, the Company believes that the impact of adopting this
standard would not have a material adverse effect on the Company's operations or
consolidated financial condition. However, no assurances can be given with
regard to the level of the Company's derivatives activities at the time SFAS 133
is adopted or the resulting effect on the Company's operations or consolidated
financial condition.
[BACKGROUND GRAPHIC]
35
<PAGE> 38
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
Year Ended December 31,
- ------------------------------------------------------------------------------------------------------------------------
(In Millions, Except per Share Amounts) 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES $ 2,065 $ 2,009 $ 2,375
- ------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Production Taxes 109 100 119
Production and Processing 472 478 471
Depreciation, Depletion and Amortization 631 679 671
Exploration Costs 214 328 284
Impairment of Oil and Gas Properties 225 706 --
Merger Costs 37 -- 80
Administrative 141 131 145
- ------------------------------------------------------------------------------------------------------------------------
Total Costs and Expenses 1,829 2,422 1,770
- ------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) 236 (413) 605
Interest Expense 211 193 174
Other Expense (Income) -- Net 2 (8) (39)
- ------------------------------------------------------------------------------------------------------------------------
Income (Loss) Before Income Taxes 23 (598) 470
Income Tax Expense (Benefit) 22 (277) 118
- ------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ 1 $ (321) $ 352
========================================================================================================================
BASIC EARNINGS (LOSS) PER COMMON SHARE $ .01 $ (1.52) $ 1.69
========================================================================================================================
DILUTED EARNINGS (LOSS) PER COMMON SHARE $ -- $ (1.52) $ 1.67
========================================================================================================================
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
[BACKGROUND GRAPHIC]
36
<PAGE> 39
BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
- ------------------------------------------------------------------------------------------------------------------------------
(In Millions, Except Share Data) 1999 1998
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents $ 89 $ --
Accounts Receivable 499 468
Inventories 53 53
Other Current Assets 26 22
- ------------------------------------------------------------------------------------------------------------------------------
667 543
- ------------------------------------------------------------------------------------------------------------------------------
Oil and Gas Properties (Successful Efforts Method) 12,834 11,943
Other Properties 935 898
- ------------------------------------------------------------------------------------------------------------------------------
13,769 12,841
Accumulated Depreciation, Depletion and Amortization 7,412 6,494
- ------------------------------------------------------------------------------------------------------------------------------
Properties -- Net 6,357 6,347
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Income Taxes 32 61
- ------------------------------------------------------------------------------------------------------------------------------
Other Assets 135 135
- ------------------------------------------------------------------------------------------------------------------------------
Total Assets $ 7,191 $ 7,086
========================================================================================================================------
LIABILITIES
Current Liabilities
Accounts Payable $ 449 $ 457
Taxes Payable 93 53
Accrued Interest 36 30
Other Current Liabilities 19 41
Current Maturities of Long-term Debt 51 --
- ------------------------------------------------------------------------------------------------------------------------------
648 581
- ------------------------------------------------------------------------------------------------------------------------------
Long-term Debt 2,769 2,684
- ------------------------------------------------------------------------------------------------------------------------------
Deferred Income Taxes 105 121
- ------------------------------------------------------------------------------------------------------------------------------
Other Liabilities and Deferred Credits 423 371
- ------------------------------------------------------------------------------------------------------------------------------
Put Options on Common Stock -- 11
- ------------------------------------------------------------------------------------------------------------------------------
Commitments and Contingent Liabilities
STOCKHOLDERS' EQUITY
Preferred Stock, Par Value $.01 per Share
(Authorized 75,000,000 Shares; One Share Issued) -- --
Common Stock, Par Value $.01 per Share
(Authorized 325,000,000 Shares; Issued 241,188,770
and 241,083,924 Shares for 1999 and 1998, respectively) 2 2
Paid-in Capital 3,966 3,953
Retained Earnings 345 446
Deferred Compensation -- Restricted Stock (3) (2)
Accumulated Other Comprehensive Loss (54) (74)
Cost of Treasury Stock (25,219,025 and 25,420,562 Shares for 1999 and 1998, respectively) (1,010) (1,007)
- ------------------------------------------------------------------------------------------------------------------------------
Stockholders' Equity 3,246 3,318
- ------------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $ 7,191 $ 7,086
==============================================================================================================================
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
37
<PAGE> 40
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
==============================================================================================================================
(In Millions) 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss) $ 1 $ (321) $ 352
Adjustments to Reconcile Net Income (Loss) to Net Cash
Provided By Operating Activities
Depreciation, Depletion and Amortization 631 679 671
Deferred Income Taxes 13 (295) 58
Exploration Costs 214 328 284
Gain on Sales of Oil and Gas Properties -- (13) (50)
Impairment of Oil and Gas Properties 225 706 --
Working Capital Changes
Accounts Receivable (31) (45) 99
Inventories -- -- (7)
Other Current Assets (4) 7 1
Accounts Payable (8) 4 40
Taxes Payable 40 (18) (4)
Accrued Interest 6 (1) 2
Other Current Liabilities (22) (3) (21)
Other 37 (48) (62)
- ------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided By Operating Activities 1,102 980 1,363
- ------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Properties (989) (1,839) (1,682)
Short-term Investments -- 83 (83)
Proceeds from Sales and Other (4) 241 467
- ------------------------------------------------------------------------------------------------------------------------------
Net Cash Used In Investing Activities (993) (1,515) (1,298)
- ------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-term Debt 632 410 213
Reduction in Long-term Debt (528) (15) (115)
Dividends Paid (127) (97) (74)
Common Stock Purchases (9) (15) (58)
Common Stock Issuances 7 114 3
Other 5 (14) 32
- ------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used In) Financing Activities (20) 383 1
- ------------------------------------------------------------------------------------------------------------------------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS -- -- 9
- ------------------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 89 (152) 75
CASH AND CASH EQUIVALENTS
Beginning of Year -- 152 77
- ------------------------------------------------------------------------------------------------------------------------------
End of Year $ 89 $ -- $ 152
==============================================================================================================================
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
38
<PAGE> 41
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Deferred Accumulated
Compensation -- Other Cost of
Common Paid-in Retained Restricted Comprehensive Treasury Stockholders'
Stock Capital Earnings Stock Loss Stock Equity
(In Millions, Except Share Data)
====================================================================================================================================
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1996 $ 2 $ 3,741 $595 $ -- $ (29) $ (989) $3,320
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income
Net Income 352 352
Foreign Currency Translation (22) (22)
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income 330
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Dividends ($.39 per Share) (82) (82)
Common Stock Purchases
(1,312,500 Shares) (58) (58)
Common Stock Issuances 3 3
Stock Option Activity and Other 28 9 37
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1997 2 3,772 865 -- (51) (1,038) 3,550
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive Loss
Net Loss (321) (321)
Foreign Currency Translation (23) (23)
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive Loss (344)
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Dividends ($.46 per Share) (98) (98)
Common Stock Purchases
(435,000 Shares) (15) (15)
Common Stock Issuances 188 188
Stock Option Activity and Other (7) (2) 46 37
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 2 3,953 446 (2) (74) (1,007) 3,318
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income
Net Income 1 1
Foreign Currency Translation 20 20
- ------------------------------------------------------------------------------------------------------------------------------------
Comprehensive Income 21
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Dividends ($.46 per Share) (103) (103)
Common Stock Purchases
(250,000 Shares) (9) (9)
Common Stock Issuances 7 7
Stock Option Activity and Other 6 1 (1) 6 12
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999 $ 2 $ 3,966 $345 $(3) $ (54) $(1,010) $3,246
====================================================================================================================================
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
[BACKGROUND GRAPHIC]
39
<PAGE> 42
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION AND REPORTING
The consolidated financial statements include the accounts of Burlington
Resources Inc. ("BR") and its majority-owned subsidiaries (the "Company"). All
significant intercompany transactions have been eliminated in consolidation. Due
to the nature of financial reporting, management makes estimates and assumptions
in preparing the consolidated financial statements. Actual results could differ
from estimates. The consolidated financial statements include certain
reclassifications that were made to conform to current presentation. All
operational and financial information contained herein includes the business
activities of Poco Petroleums Ltd. ("Poco") for all periods presented.
CASH AND CASH EQUIVALENTS
All short-term investments purchased with a maturity of three months or less
are considered cash equivalents. Cash equivalents are stated at cost, which
approximates market value.
SHORT-TERM INVESTMENTS
Short-term investments consist of highly-liquid debt securities with a
maturity of more than three months. The securities are available for sale and
are carried at fair value based on quoted market prices. Unrealized gains and
losses, net of tax, are included as a component of other comprehensive income.
Realized gains and losses are based on specific identification of the securities
sold.
INVENTORIES
Inventories of materials, supplies and products are valued at the lower of
average cost or market.
PROPERTIES
Oil and gas properties are accounted for using the successful efforts
method. Under this method, all development costs and acquisition costs of proved
properties are capitalized and amortized on a units-of-production basis over the
remaining life of proved developed reserves and proved reserves, respectively.
Costs of drilling exploratory wells are initially capitalized, but charged to
expense if and when a well is determined to be unsuccessful. In addition,
unamortized capital costs at a field level are reduced to fair value if the sum
of expected undiscounted future cash flows is less than net book value.
Costs of retired, sold or abandoned properties that constitute a part of an
amortization base are charged or credited, net of proceeds, to accumulated
depreciation, depletion and amortization. Gains or losses from the disposal of
other properties are recognized currently. Expenditures for maintenance, repairs
and minor renewals necessary to maintain properties in operating condition are
expensed as incurred. Major replacements and renewals are capitalized. Estimated
dismantlement and abandonment costs for oil and gas properties are capitalized
at their estimated net present value and amortized net of salvage value. The
Company's abandonment liability was $154 million and $93 million at December 31,
1999 and 1998, respectively.
REVENUE RECOGNITION
Gas revenues are recorded on the entitlement method. Under the entitlement
method, revenue is recorded based on the Company's net interest.
FUNCTIONAL CURRENCY
The assets, liabilities and operations of BR's Canadian subsidiaries are
measured using the Canadian dollar as the functional currency. The foreign
exploration and production operations of BR other than in Canada are considered
an extension of the Company's domestic operations. The assets, liabilities and
operations of these locations are therefore measured using the United States
dollar as the functional currency. Foreign currency transaction gains of $9
million in 1999 and losses of $17 million and $11 million in 1998 and 1997,
respectively, are included in net income.
Foreign currency translation adjustments are reported as other comprehensive
income.
HEDGING AND RELATED ACTIVITIES
In order to mitigate the risk of market price fluctuations, the Company
utilizes options and swaps to hedge future crude oil and natural gas production.
Changes in the market value of these contracts and premiums paid for option
contracts are deferred until the gain or loss is recognized on the hedged
commodity. If the contract is not a hedge, changes in market value are recorded
currently. To qualify as a hedge, these transactions must be designated as a
hedge and changes in their fair value must correlate with changes in the price
of anticipated future production such that the Company's exposure to
40
<PAGE> 43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the effects of commodity price changes is reduced. These hedging instruments are
measured for effectiveness on an enterprise basis both at the inception of the
contract and on an ongoing basis. If these instruments are terminated prior to
maturity, resulting gains or losses continue to be deferred until the hedged
item is recognized in income.
The Company also enters into swap agreements to convert fixed price gas
sales contracts to market-sensitive contracts. Gains or losses resulting from
these transactions are included in revenue as the related physical production is
delivered.
Treasury lock agreements are used to hedge interest rate exposure on
specific anticipated debt issuances of the Company. Accordingly, the
differential paid or received by the Company on maturity of a treasury lock
agreement is recognized as an adjustment to interest expense over the term of
the underlying financing transaction.
CREDIT AND MARKET RISKS
The Company manages and controls market and counterparty credit risk through
established formal internal control procedures which are reviewed on an ongoing
basis. The Company attempts to minimize credit risk exposure to counterparties
through formal credit policies, monitoring procedures and through establishment
of valuation reserves related to counterparty credit risk. In the normal course
of business, collateral is not required for financial instruments with credit
risk.
INCOME TAXES
Income taxes are provided based on earnings reported for tax return purposes
in addition to a provision for deferred income taxes. Deferred income taxes are
provided to reflect the tax consequences in future years of differences between
the financial statement and tax basis of assets and liabilities. Tax credits are
accounted for under the flow-through method, which reduces the provision for
income taxes in the year the tax credits are earned. A valuation allowance is
established to reduce deferred tax assets if it is more likely than not that the
related tax benefits will not be realized.
STOCK-BASED COMPENSATION
The Company uses the intrinsic value based method of accounting for
stock-based compensation. Under this method, the Company records no compensation
expense for stock options granted when the exercise price for options granted is
equal to the fair market value of the Company's stock on the date of the grant.
EARNINGS PER COMMON SHARE
Basic earnings per common share ("EPS") is computed by dividing income
available to common stockholders by the weighted-average number of common shares
outstanding for the period. The weighted average number of common shares
outstanding for computing basic EPS was 216 million, 211 million and 209 million
for the years ended December 31, 1999, 1998 and 1997, respectively. Diluted EPS
reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock.
The weighted average number of common shares outstanding for computing diluted
EPS, including dilutive stock options, was 217 million, 211 million and 211
million for the years ended December 31, 1999, 1998 and 1997, respectively. For
the years ended December 31, 1999, 1998 and 1997, approximately 4 million, 4
million and 700 thousand shares, respectively, attributable to the exercise of
outstanding options were excluded from the calculation of diluted EPS because
the effect was antidilutive. No adjustments were made to reported net income in
the computation of EPS.
2. BUSINESS COMBINATIONS
POCO
On August 16, 1999, the Company entered into a definitive agreement to
acquire Poco Petroleums Ltd. ("Poco"), a corporation existing under the laws of
the Province of Alberta, Canada (the "Acquisition"). The Acquisition was
consummated on November 18, 1999.
Under the terms of the Acquisition, Poco shareholders received .25 BR common
equivalent shares ("exchangeable shares"), totaling 38,393,135 BR shares, for
each Poco share held. The exchangeable shares are Canadian securities, which
began trading on the Toronto Stock Exchange on November 23, 1999 under the
symbol BRX. These shares have the same voting rights, dividend entitlements and
other attributes as shares of BR Common Stock and are exchangeable, at each
shareholder's option, for BR Common Stock on a one for one basis. The
Acquisition was accounted for as a pooling of interests.
During the fourth quarter of 1999, the Company recorded a pretax charge of
$37 million ($26 million after tax) for direct costs associated with the
Acquisition. These costs consist of $10 million for severance related to certain
executives, and $27 million for direct transaction costs. Approximately $25
million of severance and direct transaction costs remained unpaid as of December
31, 1999.
41
<PAGE> 44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The historical consolidated financial statements of Poco were prepared in
Canadian dollars. The historical financial information of Poco presented here
has been converted to U.S. dollars. The historical consolidated financial
statements of Poco were prepared under Canadian GAAP using the full cost method
of accounting for oil and gas properties. Conforming adjustments consist
primarily of conversion of Poco financial information to the successful efforts
method of accounting for oil and gas properties. The separate results of
operations of BR and Poco are as follow.
<TABLE>
<CAPTION>
(Unaudited)
Nine Months Ended
September 30, Year Ended December 31,
(In Millions) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues
BR $ 1,162 $ 1,637 $ 2,000
Poco 276 372 375
- ---------------------------------------------------------------------------------------------------------------------
Combined $ 1,438 $ 2,009 $ 2,375
=====================================================================================================================
Net Income (Loss)
BR $ 47 $ 86 $ 319
Poco 16 34 53
Conforming adjustments 22 (441) (20)
- ---------------------------------------------------------------------------------------------------------------------
Combined $ 85 $ (321) $ 352
=====================================================================================================================
Stockholders' Equity
BR $ 3,008 $ 3,018 $ 3,016
Poco 839 780 592
Conforming adjustments (483) (480) (58)
- ---------------------------------------------------------------------------------------------------------------------
Combined $ 3,364 $ 3,318 $ 3,550
=====================================================================================================================
</TABLE>
THE LOUISIANA LAND AND EXPLORATION COMPANY
On July 17, 1997, BR and The Louisiana Land and Exploration Company
("LL&E") announced that they had entered into an Agreement and Plan of Merger
(the "Merger"). On October 22, 1997, the Merger was completed and LL&E became a
wholly-owned subsidiary of the Company. Pursuant to the Merger, BR issued
52,795,635 shares of its Common Stock based on an exchange ratio of 1.525 for
each outstanding share of LL&E stock. The Merger was accounted for as a pooling
of interests and qualified as a tax-free reorganization.
[BACKGROUND GRAPHIC]
42
<PAGE> 45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. INCOME TAXES
The jurisdictional components of income (loss) before income taxes follow.
<TABLE>
<CAPTION>
Year Ended December 31,
- ------------------------------------------------------
(In Millions) 1999 1998 1997
- ------------------------------------------------------
<S> <C> <C> <C>
Domestic $ (30) $ 139 $ 369
Foreign 53 (737) 101
- ------------------------------------------------------
Total $ 23 $ (598) $ 470
======================================================
</TABLE>
The provision for income taxes follows.
<TABLE>
<CAPTION>
Year Ended December 31,
- --------------------------------------------------------
(In Millions) 1999 1998 1997
- --------------------------------------------------------
<S> <C> <C> <C>
Current
Federal $ 4 $ 10 $ 44
State -- 5 2
Foreign 5 3 14
- --------------------------------------------------------
9 18 60
- --------------------------------------------------------
Deferred
Federal (20) 8 30
State 5 1 11
Foreign 28 (304) 17
- --------------------------------------------------------
13 (295) 58
- --------------------------------------------------------
Total $ 22 $ (277) $ 118
========================================================
</TABLE>
Reconciliation of the federal statutory income tax rate to the effective
income tax rate follows.
<TABLE>
<CAPTION>
Year Ended December 31,
- -------------------------------------------------------
1999 1998 1997
- -------------------------------------------------------
<S> <C> <C> <C>
U.S. statutory rate 35.0% 35.0% 35.0%
State income taxes 13.7 4.1 2.1
Taxes on foreign income
in excess of U.S.
statutory rate 36.0 37.6 4.1
Tax credits (8.6) (33.4) (18.5)
Merger costs 17.2 -- 4.6
Other 2.1 3.0 (2.2)
- -------------------------------------------------------
Effective rate 95.4% 46.3% 25.1%
=======================================================
</TABLE>
Deferred income tax liabilities (assets) follow.
<TABLE>
<CAPTION>
December 31,
- ---------------------------------------------------------
(In Millions) 1999 1998
- ---------------------------------------------------------
<S> <C> <C>
Deferred income tax liabilities
Excess of book over tax
basis of properties $ 488 $ 453
- ---------------------------------------------------------
Deferred income tax assets
AMT credit carryforward (302) (308)
Deferred foreign tax credits (75) (71)
Net operating loss
carryforward (37) (3)
Foreign tax credit carryforward (2) (2)
Financial accruals and other (36) (44)
- ---------------------------------------------------------
(452) (428)
- ---------------------------------------------------------
Less valuation allowance 37 35
- ---------------------------------------------------------
$ 73 $ 60
=========================================================
Net Canadian deferred income
tax asset $ (32) $ (61)
- ---------------------------------------------------------
Net deferred income tax liability $ 105 $ 121
=========================================================
</TABLE>
The above net deferred income tax liabilities, as of December 31, 1999 and
1998, include deferred state income tax liabilities of approximately $21 million
and $15 million, respectively. The net deferred income tax liabilities also
include foreign tax liabilities of approximately $56 million and $55 million as
of December 31, 1999 and 1998, respectively.
The Alternative Minimum Tax ("AMT") credit carryforward, related primarily
to nonconventional fuel tax credits, is available to offset future federal
income tax liabilities. The AMT credit carryforward has no expiration date. The
benefit of these tax credits is recognized in net income for accounting purposes
and is reflected in the current tax provision to the extent the Company is able
to utilize the credits for tax return purposes.
The foreign tax credit carryforward is available to offset future federal
income taxes and will expire between 2001 and 2004 if not used. The federal
income tax net operating loss carryforward as of December 31, 1999 is available
through the year 2019 to offset expected future taxable income.
A valuation allowance is provided for uncertainties surrounding the
realization of certain non-Canadian deferred foreign tax credits. The Company
expects to realize the deferred income tax assets through future Canadian
taxable income. No deferred U.S. income tax liability has been recognized on the
undistributed earnings of foreign subsidiaries that have been retained for
reinvestment.
43
<PAGE> 46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. COMMODITY HEDGING AND RELATED ACTIVITIES
NATURAL GAS SWAPS
The Company enters into gas swap agreements to fix the price of anticipated
future natural gas production. As of December 31, 1999, the Company had the
following volumes hedged.
<TABLE>
<CAPTION>
Total Hedged Deferred
Production Volume Hedge/Strike Gain/(Loss)
Period (MMBTU) Price (In Millions)
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
2000 164,065,000 $2.43 $ 2
2001 91,345,000 2.35 (15)
2002 2,530,000 $2.57$ $ --
</TABLE>
The Company also enters into swap agreements that, when matched against
fixed price gas sales, convert our production back to a market sensitive
position. These arrangements are recorded as a revision to gas price in the
period the production is sold. As of December 31, 1999, the unrealized loss on
these positions was approximately $4 million.
NATURAL GAS OPTIONS
The Company purchases call option agreements that allow the Company to
participate in market price increases that exceed hedge prices established when
the Company enters into a swap. Approximately 15 percent of the 164,065,000
MMBTU of year 2000 hedged natural gas production was matched with call options
that strike at an average price of $2.76 per MMBTU. The deferred loss on call
option agreements as of December 31, 1999 was approximately $1 million. The
Company also enters into producer collars to establish a floor and ceiling price
on anticipated future natural gas production. As of December 31, 1999, the
Company had 5.5 million MMBTU of year 2000 natural gas production hedged at a
floor price of $2.70 per MMBTU. Approximately 67 percent of that 5.5 million
MMBTU of collar floor volumes had a ceiling of $3.30 per MMBTU. The deferred
gain on these producer collar positions as of December 31, 1999 was
approximately $2 million.
NATURAL GAS BASIS SWAPS
The Company enters into natural gas basis swap agreements to fix a component
of the sales price of anticipated future natural gas production. This component
is expressed as the differential between CIG Rockies and Henry Hub. These
transactions are accounted for as hedges of the Company's underlying production.
As of December 31, 1999, the Company had 10.1 million MMBTU of year 2000 natural
gas production hedged at a fixed differential of approximately ($.28) per MMBTU.
There was no deferred gain or loss on these transactions.
CRUDE OIL SWAPS
The Company enters into crude oil swap agreements to fix the price of
anticipated future crude oil production. As of December 31, 1999, the Company
had the following volumes hedged.
<TABLE>
<CAPTION>
Total Hedged Deferred
Production Volume Hedge/Strike Gain/(Loss)
Period (Bbls) Price (In Millions)
- --------------------------------------------------------------------
<S> <C> <C> <C>
2000 16,535,500 $20.33 $(30)
2001 3,365,000 $19.57 $ 1
</TABLE>
CRUDE OIL OPTIONS
The Company purchases call option agreements that allow the Company to
participate in market price increases that exceed hedge prices established when
the Company enters into a swap. Approximately 66 percent of the 16,535,500 Bbl
of year 2000 hedged crude oil production was matched with call options that
strike at an average price of $20.28 per Bbl. All of the year 2001 hedged crude
oil production was matched with call options that strike at an average price of
$19.57 per Bbl. The deferred gain on these transactions as of December 31, 1999
was $32 million. The Company had an additional 7,585,000 Bbl of year 2001
purchased call options agreements and 180,000 Bbl of year 2002 purchased call
option agreements that had not been matched with crude oil swaps that strike at
an average price of $19.79 per Bbl and $19.89 per Bbl, respectively. The $12
million unrealized gain on unmatched call option agreements had been recognized
in income. Unmatched options are marked to market until matched with swap
agreements.
Due to a change in oil and gas prices, the deferred loss on all positions as
of February 22, 2000 was a loss of $78 million.
[BACKGROUND GRAPHIC]
44
<PAGE> 47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. LONG-TERM DEBT
Long-term debt follows.
<TABLE>
<CAPTION>
December 31,
- ---------------------------------------------------------
(In Millions) 1999 1998
- ---------------------------------------------------------
<S> <C> <C>
Commercial Paper $ 267 $ 320
Credit Facility Notes 332 151
Capitalized Lease Obligations 56 50
Notes 7.15%, due 1999 -- 300
Notes 6 7/8%, due 1999 -- 150
Notes, 9 5/8%, due 2000 150 150
Notes, 8 1/2%, due 2001 150 150
Notes, 8.54%, due 2001 40 60
Notes, 6.20%, due 2001 34 33
Notes, 8 1/4%, due 2002 100 100
Notes, 6.40%, due 2003 69 47
Notes, 7.12%, due 2005 47 50
Notes, 6.60%, due 2007 103 98
Notes, 6.91%, due 2008 50 50
Debentures, 9 7/8%, due 2010 150 150
Notes, 7.00%, due 2011 75 75
Debentures, 7 5/8%, due 2013 100 100
Debentures, 9 1/8%, due 2021 150 150
Debentures, 7.65%, due 2023 200 200
Debentures, 8.20%, due 2025 150 150
Debentures, 6 7/8%, due 2026 150 150
Debentures, 7 3/8%, due 2029 450 --
Other, including discounts -- net (3) --
- ---------------------------------------------------------
2,820 2,684
Less current maturities 51 --
- ---------------------------------------------------------
Total long-term debt $ 2,769 $ 2,684
- ---------------------------------------------------------
</TABLE>
The Company has debt maturities of $961 million, $185 million, $101 million,
$123 million, $0 million and $1,453 million due in 2000, 2001, 2002, 2003, 2004
and thereafter, respectively. The Company's commercial paper borrowings at
December 31, 1999 and 1998 had average interest rates of 7 percent and 6
percent, respectively. The credit facility notes bear interest at rates between
5 and 6 percent. The capitalized lease obligations have an imputed interest rate
of 6 percent and expire in 2003.
The Company has unused credit commitments in the form of revolving
facilities ("revolvers") as of December 31, 1999. These revolvers are available
to cover debt due within one year, therefore, commercial paper, credit facility
notes and a portion of fixed-rate debt due within one year are classified as
long-term debt. During 1999, due to debt covenant violations, the Company
obtained waivers related to certain of its Canadian debt. In addition, the
Company has the capacity to issue $1 billion of securities under a shelf
registration statement filed with the Securities and Exchange Commission. The
revolvers are comprised of agreements for $600 million, $400 million, $310
million, $121 million and $52 million. The $600 million revolver expires in
February 2003. The other revolvers expire in March 2000, unless renewed by
mutual consent, with the exception of the $52 million revolver which is
cancellable by the creditor upon demand. Balances outstanding on the $310
million revolver automatically become five year amortizing notes at expiration
of the agreement.
At the Company's option, interest on borrowings under the $600 million and
$400 million revolvers is based on the prime rate or Eurodollar rates. The other
revolvers bear interest at rates based on prime, Eurodollar rates or bankers'
acceptances in Canada, also at the Company's option. Under the covenants of the
revolvers, Company debt cannot exceed 60 percent of capitalization (as defined
in the agreements). Also, the Company's Canadian subsidiary must limit the ratio
of debt net of working capital to pre-tax funds from operations to 3 3/4 to 1
and maintain tangible net worth in excess of a specified amount.
Outstanding borrowings of $103 million and $93 million as of December 31,
1999 and 1998, respectively, on Company-owned life insurance policies were
reported as a reduction to the cash surrender value.
6. TRANSPORTATION ARRANGEMENTS WITH EL PASO NATURAL GAS COMPANY
In 1999, 1998 and 1997, approximately 27 percent, 29 percent and 33 percent,
respectively, of the Company's gas production was transported to direct sale
customers through El Paso Natural Gas Company's ("EPNG") pipeline systems. These
transportation arrangements are pursuant to EPNG's approved Federal Energy
Regulatory Commission tariffs applicable to all shippers. The Company expects to
continue to transport a substantial portion of its future gas production through
EPNG's pipeline system. See Note 9 for demand charges paid to EPNG which provide
the Company with firm and interruptible transportation capacity rights on
interstate and intrastate pipeline systems.
45
<PAGE> 48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. CAPITAL STOCK
STOCK OPTIONS
The Company's 1993 Stock Incentive Plan (the "1993 Plan") succeeds its 1988
Stock Option Plan which expired by its terms in May 1993 but remains in effect
for options granted prior to May 1993. The 1993 Plan provides for the grant of
stock options, restricted stock, stock purchase rights and stock appreciation
rights or limited stock appreciation rights (together "SARs"). The Company
issued 110,250, 24,625 and 76,078 shares of restricted stock in 1999, 1998 and
1997, respectively.
Under the 1993 Plan, options may be granted to officers and key employees at
fair market value on the date of grant, exercisable in whole or part by the
optionee after completion of at least one year of continuous employment from the
grant date and have a term of ten years. At December 31, 1999, 5,516,459 shares
were available for grant under the 1993 Plan.
In 1997, the Company adopted the 1997 Employee Stock Incentive Plan (the
"1997 Plan") from which stock options and restricted stock ("Awards") may be
granted to employees who are not eligible to participate in the 1993 Plan. The
options are granted at fair market value on the grant date, become exercisable
in whole or part by the optionee after completion of at least one year of
continuous employment and have a term of ten years. The 1997 Plan limits Awards,
in aggregate, to a maximum of one million shares annually.
Activity in the Company's stock option plans follows.
<TABLE>
<CAPTION>
Weighted Average
Options Exercise Price
- ------------------------------------------------------------------------------------------
<S> <C> <C>
Balance, December 31, 1996 9,140,307 $34.78
Granted 2,976,177 39.27
Exercised (1,283,326) 24.82
Cancelled (344,823) 41.00
- ------------------------------------------------------------------------------------------
Balance, December 31, 1997 10,488,335 36.98
Granted 1,125,050 36.77
Exercised (1,578,818) 24.42
Cancelled (889,485) 44.69
- ------------------------------------------------------------------------------------------
Balance, December 31, 1998 9,145,082 37.84
Granted 822,880 33.35
Exercised (424,089) 30.50
Cancelled (645,075) 38.32
- ------------------------------------------------------------------------------------------
Balance, December 31, 1999 8,898,798 $37.80
- ------------------------------------------------------------------------------------------
</TABLE>
The following table summarizes information related to stock options
outstanding and exercisable at December 31, 1999.
<TABLE>
<CAPTION>
Weighted Average
Options Range of Weighted Average Remaining Options Weighted Average
Outstanding Exercise Prices Exercise Price Contractual Life Exercisable Exercise Price
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
4,730,438 $19.51-35.38 $30.43 4.2 4,245,838 $29.87
4,168,360 35.43-52.03 46.16 6.7 3,392,526 45.88
- ------------------------------------------------------------------------------------------------------------------------
8,898,798 $19.51-52.03 $37.80 5.3 7,638,364 $36.98
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
Exercisable stock options and weighted average exercise prices at December
31, 1998 and 1997 follow.
<TABLE>
<CAPTION>
Options Weighted Average
Exercisable Exercise Price
- ----------------------------------------------------------------------
<S> <C> <C>
December 31, 1998 5,255,473 $37.22
December 31, 1997 4,681,281 $32.41
</TABLE>
[BACKGROUND GRAPHIC]
46
<PAGE> 49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The weighted average fair values of options granted during the years 1999,
1998 and 1997 were $11.13, $16.54 and $12.27, respectively. The fair values of
employee stock options were calculated using a variation of the Black-Scholes
stock option valuation model with the following weighted average assumptions for
grants in 1999, 1998 and 1997: stock price volatility of 27 percent, 25 percent
and 20 percent, respectively; risk free rate of return ranging from 5 percent to
6 percent; dividend yield of .88 percent, .33 percent and .81 percent,
respectively; and an expected term of between 4 and 6 years. If the fair value
based method of accounting had been applied, the Company's net income and EPS
would have been reduced to the pro forma amounts indicated below. The fair value
of stock options included in the pro forma amounts is not necessarily indicative
of future effects on net income and EPS.
<TABLE>
<CAPTION>
Year Ended December 31,
- ----------------------------------------------------------------------
(In Millions, Except per Share Amounts) 1999 1998 1997
- ----------------------------------------------------------------------
<S> <C> <C> <C>
Net income (loss) -- as reported $ 1 $ (321) $ 352
Net income (loss) -- pro forma (30) (340) 339
Basic EPS -- as reported .01 (1.52) 1.69
Basic EPS -- pro forma (.14) (1.61) 1.62
Diluted EPS -- as reported -- (1.52) 1.67
Diluted EPS -- pro forma $ (.14) $(1.61) $1.61
</TABLE>
STOCK APPRECIATION RIGHTS
The Company has granted SARs in connection with certain outstanding options
under the 1988 Stock Option Plan. SARs are subject to the same terms and
conditions as the related options. A SAR entitles an option holder, in lieu of
exercise of an option, to receive a cash payment equal to the difference between
the option price and the fair market value of the Company's Common Stock based
upon the plan provisions. To the extent the SAR is exercised, the related option
is cancelled and to the extent the option is exercised, the related SAR is
cancelled. The outstanding SARs are exercisable only under certain circumstances
related to significant changes in the ownership of the Company or its holdings,
or certain changes in the constitution of its Board of Directors. At December
31, 1999, there were 46,890 SARs outstanding related to stock options with a
weighted average exercise price of $34.68 per share. In January 2000, all
outstanding SARs expired.
PREFERRED STOCK AND PREFERRED STOCK PURCHASE RIGHTS
The Company is authorized to issue 75,000,000 shares of preferred stock, par
value $.01 per share. As of December 31, 1999, one share of preferred stock was
issued and designated as Special Voting Stock in connection with the Poco
acquisition. On December 9, 1998, the Company's Board of Directors designated
3,250,000 of the authorized preferred shares as Series A Junior Participating
Preferred Stock. Upon issuance, each one-hundredth of a share of Series A Junior
Participating Preferred Stock will have dividend and voting rights approximately
equal to those of one share of Common Stock of the Company. In addition, on
December 9, 1998, the Board of Directors declared a dividend distribution of one
Right for each outstanding share of Common Stock of the Company to shareholders
of record on December 16, 1998. The Rights become exercisable if, without the
Company's prior consent, a person or group acquires securities having 15 percent
or more of the voting power of all of the Company's voting securities (an
"Acquiring Person") or ten days following the announcement of a tender offer
which would result in such ownership. Each Right, when exercisable, entitles the
registered holder to purchase from the Company one-hundredth of a share of
Series A Junior Participating Preferred Stock at a price of $200 per one
hundredth of a share, subject to adjustment. If, after the Rights become
exercisable, the Company were to be involved in a merger or other business
combination in which its Common Stock was exchanged or changed or 50 percent or
more of the Company's assets or earning power were sold, each Right would permit
the holder to purchase, for the exercise price, stock of the acquiring company
having a value of twice the exercise price. In addition, except for certain
permitted offers, if any person or group becomes an Acquiring Person, each Right
would permit the purchase, for the exercise price, of Common Stock of the
Company having a value of twice the exercise price. Rights owned by an Acquiring
Person are void. The Rights may be redeemed by the Company under certain
circumstances until their expiration date for $.01 per Right.
On November 8, 1999 (effective November 18, 1999), the Company's Board of
Directors designated one of the authorized preferred shares as Special Voting
Stock. The Special Voting Stock is entitled to a number of votes equal to the
number of outstanding Exchangeable Shares of
47
<PAGE> 50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Burlington Resources Canada Inc. (other than Exchangeable Shares held by the
Company), on all matters presented to the stockholders of the Company. Upon the
liquidation, dissolution or winding up of the Company, the holder of the Special
Voting Stock shall be entitled, prior and in preference to any distribution to
the holders of Common Stock and after the distribution to the holders of any
class or series of Preferred Stock ranking senior to the Special Voting Stock of
all amounts to which such holders are entitled, to receive the sum of $.01.
Except as aforesaid, no dividends or distributions shall be payable to the
holder of the Special Voting Stock. The Special Voting Stock is not convertible
into any other class or series of the capital stock or to cash, property or
other rights, and may not be redeemed. If the Special Voting Stock shall be
purchased or otherwise acquired by the Company, it shall be deemed retired and
shall be cancelled and may not thereafter be reissued or otherwise disposed of
by the Company. As long as any Exchangeable Shares of Burlington Resources
Canada Inc. are outstanding, the number of shares comprising the Special Voting
Stock shall not be increased or decreased and no other term of the Special
Voting Stock shall be amended, except upon the unanimous approval of all shares
of Common Stock. On November 18, 1999, the one share of Special Voting Stock was
issued to CIBC Mellon Trust Company, as trustee pursuant to the Voting and
Exchange Trust Agreement among the Company, Burlington Resources Canada Inc. and
CIBC Mellon Trust Company, for the benefit of the holders of the Exchangeable
Shares of Burlington Resources Canada Inc.
8. RETIREMENT BENEFITS
The Company's pension plans are non-contributory defined benefit plans
covering all United States' employees. The benefits are based on years of
credited service and final average compensation. Contributions to the tax
qualified plans are limited to amounts that are currently deductible for tax
purposes. Contributions are intended to provide not only for benefits attributed
to service to date but also for those expected to be earned in the future.
The following tables set forth the amounts recognized in the Consolidated
Balance Sheet and Statement of Income.
<TABLE>
<CAPTION>
Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
- -------------------------------------------------------------------------------------------------------------------------
(In Millions) 1999 1998 1999 1998
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at beginning of year $ 182 $ 178 $ 32 $ 33
Service cost 10 9 -- --
Interest cost 12 12 2 2
Amendments -- 2 (4) 1
Actuarial loss (gain) (15) 8 (3) (2)
Benefits paid (28) (27) (3) (2)
- -------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year 161 182 24 32
- -------------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year 172 161 -- --
Actual return on plan assets 22 30 -- --
Employer contribution 5 8 3 2
Benefits paid (28) (27) (3) (2)
- -------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year 171 172 -- --
- -------------------------------------------------------------------------------------------------------------------------
Funded status 10 (10) (24) (32)
Unrecognized net actuarial gain (loss) (11) 16 (1) 1
Unrecognized net transition obligation 1 1 -- --
Unrecognized prior service cost 1 2 (3) 2
- -------------------------------------------------------------------------------------------------------------------------
Net prepaid (accrued) benefit cost $ 1 $ 9 $ (28) $ (29)
=========================================================================================================================
</TABLE>
48
<PAGE> 51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
- -------------------------------------------------------------------------------------------------------------------------
(In Millions) 1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Benefit cost for the plans includes the following components
Service cost $ 10 $ 9 $ 9 $ -- $ -- $ 1
Interest cost 12 12 12 2 2 3
Expected return on plan assets (14) (13) (12) -- -- --
Amortization of prior service cost -- -- 1 -- -- --
Recognized net actuarial loss (gain) 1 2 1 -- (1) --
- -------------------------------------------------------------------------------------------------------------------------
Net benefit cost $ 9 $ 10 $ 11 $ 2 $ 1 $ 4
=========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
- -------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Weighted average assumptions
Discount rate 7.75% 6.75% 7.25% 7.75% 6.75% 7.25%
Expected return on plan assets 9.00% 9.00% 9.00% -- -- --
Rate of compensation increase 5.00% 5.00% 5.00% -- -- --
</TABLE>
The Company provides postretirement medical, dental and life insurance
benefits for a closed group of retirees and their dependents. The Company also
provides limited retiree life insurance benefits to employees who retire under
the pension plan. The postretirement benefit plans are unfunded and the Company
funds claims on a cash basis.
During 1998, the Company recognized a settlement expense of approximately
$800 thousand related to the employee reduction associated with the Merger in
the fourth quarter of 1997.
A 5 percent annual rate of increase in the per capita cost of covered health
care benefits was assumed for 1999. The rate is assumed to decrease gradually to
4 percent for 2003 and remain at that level thereafter. Assumed health care cost
trends have a significant effect on the amounts reported for the postretirement
medical and dental care plans. A one-percentage point change in assumed health
care cost trend rates would have the following effects.
<TABLE>
<CAPTION>
1-Percentage 1-Percentage
(In Thousands) Point Increase Point Decrease
- --------------------------------------------------------------------------------
<S> <C> <C>
Effect on total service and interest cost $ 167 $ (145)
Effect on postretirement benefit obligation $ 1,807 $ (1,578)
</TABLE>
[BACKGROUND GRAPHICS]
49
<PAGE> 52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. COMMITMENTS AND CONTINGENT LIABILITIES
DEMAND CHARGES
The Company has entered into contracts which provide firm transportation
capacity rights on interstate and intrastate pipeline systems. The remaining
terms on these contracts range from 1 to 23 years and require the Company to pay
transportation demand charges regardless of the amount of pipeline capacity
utilized by the Company. The Company paid $122 million, $109 million and $89
million of demand charges of which $36 million, $44 million and $34 million was
paid to EPNG for the years ended December 31, 1999, 1998 and 1997, respectively.
Future transportation demand charge commitments at December 31, 1999 follow.
<TABLE>
<CAPTION>
(In Millions) Year Ended December 31,
- ------------------------------------------------------------------
<S> <C>
2000 $ 101
2001 99
2002 94
2003 90
2004 89
Thereafter 346
- ------------------------------------------------------------------
Total $ 819
==================================================================
</TABLE>
LEASE OBLIGATIONS
The Company has operating leases for office space and other property and
equipment. The Company incurred lease rental expense of $24 million, $19 million
and $20 million for the years ended December 31, 1999, 1998 and 1997,
respectively.
Future minimum annual rental commitments at December 31, 1999 follow.
<TABLE>
<CAPTION>
(In Millions) Year Ended December 31,
- ------------------------------------------------------------------
<S> <C>
2000 $ 23
2001 21
2002 20
2003 20
2004 19
Thereafter 82
- ------------------------------------------------------------------
Total $ 185
==================================================================
</TABLE>
DRILLING RIG COMMITMENTS
During 1998, the Company entered into agreements to lease or participate in
the use of various drilling rigs. The exposure with respect to these commitments
ranges from $142 million to $270 million depending on partner participation.
These agreements extend through the year 2004.
LEGAL PROCEEDINGS
The Company is involved in several proceedings challenging the payment of
royalties for its crude oil and natural gas production.
On November 20, 1997, the Company and numerous other defendants entered into
a settlement agreement in a lawsuit styled as The McMahon Foundation, et al. v.
Amerada Hess Corporation, et al. This lawsuit is a proposed class action
consisting of both working interest owners and royalty owners against numerous
defendants, all of which are oil companies and/or purchasers of oil from oil
companies, including Burlington Resources Oil & Gas Company, formerly known as
Meridian Oil Inc. ("BROG") and LL&E. The plaintiffs allege that the defendants
conspired to fix, depress, stabilize and maintain at artificially low levels the
prices paid for oil by, among other things, setting their posted prices at
arbitrary levels below competitive market prices. Cases involving similar
allegations have been filed in federal courts in other states. On January 14,
1998, the United States Judicial Panel on Multidistrict Litigation issued an
order consolidating these cases and transferring the McMahon case to the United
States District Court for the Southern District of Texas in Corpus Christi (In
Re Lease Oil Antitrust Litigation, MDL No. 1206). The Company and other
defendants have entered into a Settlement Agreement which received preliminary
approval by the Court on October 28, 1998. Following an evidentiary hearing, the
Court issued a final order dated September 10, 1999 finding that class
certification was appropriate and that the Settlement Agreement was fair,
adequate and reasonable. The Court further ordered the dismissal of all claims
against the Company and other designated defendants. Several appeals have been
filed and are pending.
The Company is also involved in several governmental proceedings relating to
the payment of royalties. Various administrative proceedings are pending before
the Minerals Management Service ("MMS") of the United States Department of the
Interior with respect to the proper valuation of oil and gas produced on federal
and Indian lands for purposes of paying royalties on production sold
[BACKGROUND GRAPHICS]
50
<PAGE> 53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
by BROG to its affiliate, Burlington Resources Trading Inc. ("BRTI"), or
gathered by its affiliate, Burlington Resources Gathering, Inc. In general,
these proceedings stem from regular MMS audits of the Company's royalty payments
over various periods of time and involve the interpretation of the relevant
federal regulations.
In late February 1998, the Company and numerous other oil and gas companies
received a complaint filed in the United States District Court for the Eastern
District of Texas in Lufkin in a lawsuit styled as United States of America ex
rel J. Benjamin Johnson, Jr., et al. v. Shell Oil Company, et al. alleging
violations of the civil False Claims Act. The United States has intervened in
this lawsuit as to some of the defendants, including the Company, and has filed
a separate complaint. This suit alleges that the Company underpaid royalties for
crude oil produced on federal and Indian lands through the use of below-market
posted prices in the sale of oil from BROG to BRTI. The suit alleges that
royalties paid by BROG based on these posted prices were lower than the
royalties allegedly required to be paid under federal regulations, and that the
forms filed by BROG with the MMS reporting the royalties paid were false,
thereby violating the civil False Claims Act.
The Company and others have also received document subpoenas and other
inquiries from the Department of Justice relating to the payment of royalties to
the federal government for natural gas production. These requests and inquiries
have been made in the context of one or more other False Claims Act cases
brought by individuals which remain under seal and are now being investigated by
the Civil Division of the Department of Justice. The Company has responded and
continues to respond to these requests and inquiries, but the Company does not
know what action, if any, the Department of Justice will take with regard to
these other cases. If the government chooses not to intervene and pursue these
cases, the individuals who initially brought these cases are free to pursue them
in return for a share, if any, of any final settlement or judgment. In addition,
the Company has been advised that it is a target of a criminal investigation by
the United States Attorney for the District of Wyoming into the alleged
underpayment of oil and gas royalties. The United States Attorney for the
District of Wyoming has also inquired into certain historical oil and gas
accounting and financial reporting practices of the Company. The Company has
responded to numerous grand jury document subpoenas in connection with the
investigation and is otherwise cooperating with the investigation. Management
cannot predict when the investigation will be completed or its ultimate outcome.
In April 1999, the court unsealed and the Company was served with the
petition in the False Claims Act lawsuits styled United States of America ex
rel. Jack J. Grynberg v. Burlington Resources Oil & Gas Company, et al. and
United States of America ex rel. Jack J. Grynberg v. The Louisiana Land and
Exploration Company, et al., filed in the United States District Court of the
District of Wyoming (the "Grynberg lawsuits"). In both cases the United States
Department of Justice declined to intervene following its investigation,
resulting in these claims being pursued by Grynberg individually. Grynberg has
filed seventy similar suits against more than three hundred defendants. On
October 20, 1999, the Judicial Panel on Multidistrict Litigation consolidated
sixty-six of the Grynberg False Claims Act lawsuits, including the referenced
suits against the Company, and transferred all cases to the United States
District Court for the District of Wyoming. The Grynberg lawsuits generally
allege that the Company and other defendants improperly measured and otherwise
undervalued natural gas in connection with the payment of royalties on
production from federal and Indian lands. Motions to Dismiss have been filed by
the Company and numerous other defendants and are pending before the Court.
Based on the Company's present understanding of the various governmental and
False Claims Act proceedings described above, the Company believes that it has
substantial defenses to these claims and intends to vigorously assert such
defenses. However, in the event that the Company is found to have violated the
civil False Claims Act or is indicted or convicted on criminal charges, the
Company could be subject to a variety of sanctions, including treble damages,
substantial monetary fines, civil and/or criminal penalties and a temporary
suspension from entering into future federal mineral leases and other federal
contracts for a defined period of time. While the ultimate outcome and impact on
the Company cannot be predicted with certainty, management believes that the
resolution of these proceedings will not have a material adverse effect on the
consolidated financial position of the Company, although results of operations
and cash flow could be significantly impacted in the reporting periods in which
such matters are resolved.
In addition to the foregoing, the Company and its subsidiaries are named
defendants in numerous other lawsuits and named parties in numerous governmental
and other
51
<PAGE> 54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
proceedings arising in the ordinary course of business. While the outcome of
these other lawsuits and proceedings cannot be predicted with certainty,
management believes these matters, other than the above-described proceedings,
will not have a material adverse effect on the consolidated financial position,
results of operations or cash flows of the Company.
10. SUPPLEMENTAL CASH FLOW INFORMATION
The following is additional information concerning supplemental disclosures
of cash payments.
<TABLE>
<CAPTION>
Year Ended December 31,
- --------------------------------------------------------
(In Millions) 1999 1998 1997
- --------------------------------------------------------
<S> <C> <C> <C>
Interest paid $ 206 $ 192 $ 177
Income taxes paid -- net 13 26 60
</TABLE>
The following is additional information concerning supplemental disclosure
of non-cash investing and financing activities.
<TABLE>
<CAPTION>
Year Ended December 31,
- --------------------------------------------------------
(In Millions) 1999 1998 1997
- --------------------------------------------------------
<S> <C> <C> <C>
Issuance of Common Stock
in exchange for oil
and gas properties -- $ 74 --
Capitalized lease obligations -- 53 --
</TABLE>
11. IMPAIRMENT OF OIL AND GAS PROPERTIES
The Company evaluates the impairment of its oil and gas properties on a
field-by-field basis whenever events or changes in circumstances indicate an
asset's carrying amount may not be recoverable. Unamortized capital costs are
reduced to fair value if the sum of the expected undiscounted future cash flows
is less than the assets' net book value. Cash flows are determined based upon
proved reserves using prices and costs consistent with those used for internal
decision making.
In the fourth quarter of 1999, the Company determined there would be
performance related downward reserve adjustments associated with certain
properties located on the Gulf of Mexico shelf and in the Permian Basin. As a
result, the Company recognized a pretax impairment charge of $225 million ($140
million after tax) related to those properties.
In the fourth quarter of 1998, the market experienced a weakness in
commodity prices. The Company subjected all properties to impairment testing and
subsequently recognized a pretax impairment charge related to certain Canadian
properties of $706 million ($390 million after tax).
12. DIVESTITURE PROGRAM AND REORGANIZATION
In June 1997, the Company completed its divestiture program of non-strategic
assets which was announced in July 1996. As planned, the Company sold
approximately 27,000 wells and related facilities. Before closing adjustments,
gross proceeds for 1997 from the sales of oil and gas properties related to this
divestiture program were approximately $450 million. During 1997, the Company
recorded a pretax gain of approximately $50 million related to the sales of oil
and gas properties. This program allowed the Company to reorganize and resulted
in a reduction of 456 employees. As of December 31, 1997, this program was
complete.
[BACKGROUND GRAPHICS]
52
<PAGE> 55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. SEGMENT AND GEOGRAPHIC INFORMATION
The Company's reportable segments are North America and International. Both
segments are engaged principally in the exploration, development, production and
marketing of oil and gas. The North America segment is responsible for the
Company's operations in the USA and Canada and the International segment is
responsible for all operations outside that geographical region. The accounting
policies for the segments are the same as those described in Note 1 to the
consolidated financial statements. There are no significant intersegment sales
or transfers.
The following tables present information about reported segment operations.
<TABLE>
<CAPTION>
Year Ended December 31, 1999
- ----------------------------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $ 1,934 $ 131 $ 2,065
Depreciation, depletion and amortization 560 57 617
Impairment of oil and gas properties 225 -- 225
Operating income (loss) 449 (21) 428
Additions to properties $ 797 $ 148 $ 945
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1999
- ----------------------------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $ 1,860 $ 149 $ 2,009
Depreciation, depletion and amortization 601 67 668
Impairment of oil and gas properties 706 -- 706
Operating income (233) (38) (271)
Additions to properties $ 1,653 $ 136 $ 1,789
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
[BACKGROUND GRAPHICS]
53
<PAGE> 56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Year Ended December 31, 1997
- ---------------------------------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $ 2,170 $ 205 $ 2,375
Depreciation, depletion and amortization 579 75 654
Operating income 794 53 847
Additions to properties $ 1,409 $ 228 $ 1,637
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
The following is a reconciliation of segment operating income (loss) to
consolidated income (loss) before income taxes.
<TABLE>
<CAPTION>
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------------
(In Millions) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Total operating income (loss) for reportable segments $ 428 $ (271) $ 847
Merger costs 37 -- 80
Corporate expenses 155 142 162
Interest expense 211 193 174
Other expense (income)-- net 2 (8) (39)
- ---------------------------------------------------------------------------------------------------------------------------
Consolidated income (loss) before income taxes $ 23 $ (598) $ 470
===========================================================================================================================
</TABLE>
The following is a reconciliation of segment additions to properties to
consolidated amounts.
<TABLE>
<CAPTION>
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------------
(In Millions) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Total additions to properties for reportable segments $ 945 $ 1,789 $ 1,637
Administrative expenditures 44 50 45
- ---------------------------------------------------------------------------------------------------------------------------
Consolidated additions to properties $ 989 $ 1,839 $ 1,682
===========================================================================================================================
</TABLE>
The following table presents revenues by geographic location.
<TABLE>
<CAPTION>
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------------
In Millions 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
USA $1,527 $1,488 $1,795
Canada 407 372 375
Other International 131 149 205
- ---------------------------------------------------------------------------------------------------------------------------
Consolidated revenues $2,065 $2,009 $2,375
===========================================================================================================================
</TABLE>
[BACKGROUND GRAPHICS]
54
<PAGE> 57
REPORT OF MANAGEMENT
The management of Burlington Resources is responsible for the preparation
and integrity of all information contained in this Annual Report. The
accompanying financial statements have been prepared in conformity with
generally accepted accounting principles. The financial statements include
amounts that are management's best estimates and judgments.
BR maintains a system of internal control and a program of internal auditing
that provides management with reasonable assurance that BR's assets are
protected and that published financial statements are reliable and free of
material misstatement. Management is responsible for the effectiveness of
internal controls. This is accomplished through established codes of conduct,
accounting and other control systems, policies and procedures, employee
selection and training, appropriate delegation of authority and segregation of
responsibilities.
The Audit Committee of the Board of Directors, composed solely of directors
who are not officers or employees, meets regularly with the independent
certified public accountants, financial management, counsel and corporate audit.
To ensure complete independence, the certified public accountants and corporate
audit have full and free access to the Audit Committee to discuss the results of
their audits, the adequacy of internal controls and the quality of financial
reporting.
Our independent certified public accountants provide an objective
independent review by their audit of the Company's financial statements. Their
audit is conducted in accordance with generally accepted auditing standards and
includes a review of internal accounting controls to the extent deemed necessary
for the purposes of their audit.
/s/ John E. Hagale /s/ Philip W. Cook
John E. Hagale Philip W. Cook
Executive Vice President and Vice President, Controller and
Chief Financial Officer Chief Accounting Officer
[BACKGROUND GRAPHICS]
55
<PAGE> 58
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF BURLINGTON RESOURCES INC.
In our opinion, based on our audits and the report of other auditors, the
accompanying consolidated balance sheet and the related consolidated statements
of income, cash flows and stockholders' equity present fairly, in all material
respects, the financial position of Burlington Resources Inc. and its
subsidiaries at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999 in conformity with accounting principles generally accepted in the
United States. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. The consolidated financial statements
give retroactive effect to the merger of Poco Petroleums Ltd. on November 18,
1999 in a transaction accounted for as a pooling of interests, as described in
Note 2 to the consolidated financial statements. We did not audit the financial
statements of Poco Petroleums Ltd., which statements reflect total assets of
$1.3 billion and $1.1 billion as of December 31, 1999 and 1998, respectively,
and total revenues of $407 million, $372 million and $375 million for the years
ended December 31, 1999, 1998 and 1997, respectively. Those statements were
audited by other auditors whose report thereon has been furnished to us, and our
opinion expressed herein, insofar as it relates to the amounts included for Poco
Petroleums Ltd., is based solely on the report of the other auditors. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits and the report of other auditors provide a reasonable
basis for the opinion expressed above.
/s/PricewaterhouseCoopers LLP
March 3, 2000
Houston, Texas
[BACKGROUND GRAPHICS]
56
<PAGE> 59
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTAL OIL AND GAS DISCLOSURES -- UNAUDITED
- --------------------------------------------------------------------------------
The supplemental data presented herein reflects information for all of the
Company's oil and gas producing activities. Capitalized costs for oil and gas
producing activities follow.
<TABLE>
<CAPTION>
December 31,
- -------------------------------------------------------------------------------------------
(In Millions) 1999 1998
- -------------------------------------------------------------------------------------------
<S> <C> <C>
Proved properties $ 12,516 $ 11,617
Unproved properties 318 326
- -------------------------------------------------------------------------------------------
12,834 11,943
Accumulated depreciation, depletion and amortization 6,765 6,107
- -------------------------------------------------------------------------------------------
Net capitalized costs $ 6,069 $ 5,836
===========================================================================================
</TABLE>
Costs incurred for oil and gas property acquisition, exploration and
development activities follow.
<TABLE>
<CAPTION>
Year Ended December 31, 1999
- ---------------------------------------------------------------------------------------------------------------------------
Other
(In Millions) USA Canada International Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Property acquisition
Unproved $ 12 $ 18 $ 2 $ 32
Proved 69 66 -- 135
Exploration 88 67 66 221
Development 319 140 80 539
- ---------------------------------------------------------------------------------------------------------------------------
Total costs incurred $ 488 $ 291 $ 148 $ 927
===========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1998
- ---------------------------------------------------------------------------------------------------------------------------
Other
(In Millions) USA Canada International Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Property acquisition
Unproved $ 92 $ 16 $ 6 $ 114
Proved 23 410 4 437
Exploration 315 95 96 506
Development 491 150 30 671
- ---------------------------------------------------------------------------------------------------------------------------
Total costs incurred $ 921 $ 671 $ 136 $ 1,728
===========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1997
- ---------------------------------------------------------------------------------------------------------------------------
Other
(In Millions) USA Canada International Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Property acquisition
Unproved $ 93 $ 41 $ 5 $ 139
Proved 54 126 160 340
Exploration 241 74 48 363
Development 539 164 15 718
- ---------------------------------------------------------------------------------------------------------------------------
Total costs incurred $ 927 $ 405 $ 228 $ 1,560
===========================================================================================================================
</TABLE>
57
<PAGE> 60
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
Results of operations for oil and gas producing activities follow.
<TABLE>
<CAPTION>
Year Ended December 31, 1999
- ---------------------------------------------------------------------------------------------------------------------------
Other
(In Millions) USA Canada International Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues $ 1,479 $ 404 $ 124 $ 2,007
- ---------------------------------------------------------------------------------------------------------------------------
Production costs 336 102 33 471
Exploration costs 129 39 46 214
Operating expenses 188 28 27 243
Depreciation, depletion and amortization 435 107 54 596
Impairment of oil and gas properties 225 -- -- 225
- ---------------------------------------------------------------------------------------------------------------------------
1,313 276 160 1,749
- ---------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 166 128 (36) 258
Income tax provision (benefit) 63 61 (11) 113
- ---------------------------------------------------------------------------------------------------------------------------
Results of operations for oil and gas
producing activities $ 103 $ 67 $ (25) $ 145
===========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1998
- ---------------------------------------------------------------------------------------------------------------------------
Other
(In Millions) USA Canada International Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues $ 1,448 $ 367 $ 149 $ 1,964
- ---------------------------------------------------------------------------------------------------------------------------
Production costs 343 90 43 476
Exploration costs 239 30 59 328
Operating expenses 177 18 32 227
Depreciation, depletion and amortization 429 157 64 650
Impairment of oil and gas properties -- 706 -- 706
- ---------------------------------------------------------------------------------------------------------------------------
1,188 1,001 198 2,387
- ---------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 260 (634) (49) (423)
Income tax provision (benefit) 64 (259) (11) (206)
- ---------------------------------------------------------------------------------------------------------------------------
Results of operations for oil and gas
producing activities $ 196 $ (375) $ (38) $ (217)
===========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1997
- ---------------------------------------------------------------------------------------------------------------------------
Other
(In Millions) USA Canada International Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues $ 1,747 $ 372 $ 205 $ 2,324
- ---------------------------------------------------------------------------------------------------------------------------
Production costs 363 86 42 491
Exploration costs 234 25 25 284
Operating expenses 220 18 10 248
Depreciation, depletion and amortization 422 143 75 640
- ---------------------------------------------------------------------------------------------------------------------------
1,239 272 152 1,663
- ---------------------------------------------------------------------------------------------------------------------------
Operating income 508 100 53 661
Income tax provision 103 43 27 173
- ---------------------------------------------------------------------------------------------------------------------------
Results of operations for oil and gas
producing activities $ 405 $ 57 $ 26 $ 488
===========================================================================================================================
</TABLE>
58
<PAGE> 61
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
The following table reflects estimated quantities of proved oil and gas
reserves. These reserves have been reduced for royalty interests owned by
others. These reserves have been estimated by the Company's petroleum engineers.
The Company considers such estimates to be reasonable, however, due to inherent
uncertainties, estimates of underground reserves are imprecise and subject to
change over time as additional information becomes available.
<TABLE>
<CAPTION>
Oil (MMBbls) Gas (BCF)
- ---------------------------------------------------------------------------------------------------------------------------
Other Other
Interna- World- Interna- World-
USA Canada tional wide USA Canada tional wide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PROVED DEVELOPED AND
UNDEVELOPED RESERVES
December 31, 1996 275.0 61.4 30.8 367.2 5,908 892 323 7,123
Revisions of previous estimates (15.6) 3.2 (2.6) (15.0) 68 (15) (4) 49
Extensions, discoveries
and other additions 44.9 9.9 .3 55.1 913 231 1 1,145
Production (24.6) (7.7) (7.2) (39.5) (583) (140) (26) (749)
Purchases of reserves in place 1.4 2.0 -- 3.4 116 178 240 534
Sales of reserves in place (48.7) (0.5) -- (49.2) (538) (18) -- (556)
- ---------------------------------------------------------------------------------------------------------------------------
December 31, 1997 232.4 68.3 21.3 322.0 5,884 1,128 534 7,546
Revisions of previous estimates (8.4) (.4) 1.6 (7.2) (94) (66) (6) (166)
Extensions, discoveries
and other additions 26.7 11.6 29.7 68.0 636 235 35 906
Production (24.2) (7.9) (6.0) (38.1) (577) (157) (24) (758)
Purchases of reserves in place .1 3.7 -- 3.8 81 338 8 427
Sales of reserves in place -- (2.9) -- (2.9) (72) (57) (25) (154)
- ---------------------------------------------------------------------------------------------------------------------------
December 31, 1998 226.6 72.4 46.6 345.6 5,858 1,421 522 7,801
Revisions of previous estimates (9.0) (1.9) 0.3 (10.6) (52) (20) (2) (74)
Extensions, discoveries
and other additions 19.0 4.7 2.0 25.7 554 164 384 1,102
Production (20.9) (7.1) (4.8) (32.8) (543) (156) (32) (731)
Purchases of reserves in place .5 1.0 -- 1.5 138 53 -- 191
Sales of reserves in place -- -- -- -- -- (9) -- (9)
- ---------------------------------------------------------------------------------------------------------------------------
December 31, 1999 216.2 69.1 44.1 329.4 5,955 1,453 872 8,280
===========================================================================================================================
PROVED DEVELOPED RESERVES
December 31, 1996 242.0 57.7 25.4 325.1 4,870 837 265 5,972
December 31, 1997 203.9 62.8 15.6 282.3 4,641 1,053 233 5,927
December 31, 1998 199.2 61.2 14.5 274.9 4,564 1,134 258 5,956
December 31, 1999 168.3 57.5 13.5 239.3 4,715 1,180 314 6,209
</TABLE>
59
<PAGE> 62
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
A summary of the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves is shown below. Future net cash flows
are computed using year end sales prices, costs and statutory tax rates
(adjusted for tax credits and other items) that relate to the Company's existing
proved oil and gas reserves.
<TABLE>
<CAPTION>
Year Ended December 31, 1999
- ---------------------------------------------------------------------------------------------------------------------------
Other
(In Millions) USA Canada International Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Future cash inflows $ 17,568 $ 4,184 $ 2,840 $ 24,592
Less related future
Production costs 4,778 1,140 778 6,696
Development costs 661 279 604 1,544
Income taxes 3,281 685 423 4,389
- ---------------------------------------------------------------------------------------------------------------------------
Future net cash flows 8,848 2,080 1,035 11,963
10% annual discount for estimated timing
of cash flows 4,374 788 508 5,670
- ---------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows $ 4,474 $ 1,292 $ 527 $ 6,293
===========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1998
- ---------------------------------------------------------------------------------------------------------------------------
Other
(In Millions) USA Canada International Worldwide
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Future cash inflows $ 13,840 $ 3,363 $ 1,912 $ 19,115
Less related future
Production costs 3,761 1,076 773 5,610
Development costs 617 282 296 1,195
Income taxes 2,113 287 190 2,590
- ---------------------------------------------------------------------------------------------------------------------------
Future net cash flows 7,349 1,718 653 9,720
10% annual discount for estimated timing
of cash flows 3,643 632 301 4,576
- ---------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows $ 3,706 $ 1,086 $ 352 $ 5,144
===========================================================================================================================
</TABLE>
60
<PAGE> 63
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves follows.
<TABLE>
<CAPTION>
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------------------------
(In Millions) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
January 1 $ 5,144 $ 5,789 $ 8,593
- ---------------------------------------------------------------------------------------------------------------------------
Revisions of previous estimates
Changes in prices and costs 1,844 (1,017) (4,723)
Changes in quantities (83) (135) 16
Changes in rate of production (92) (274) (422)
Additions to proved reserves
resulting from extensions,
discoveries and improved
recovery, less related costs 723 547 741
Purchases of reserves in place 168 183 396
Sales of reserves in place (6) (102) (691)
Accretion of discount 628 737 1,206
Sales of oil and gas, net of production costs (1,536) (1,488) (1,833)
Net change in income taxes (815) 435 1,888
Other 318 469 618
- ---------------------------------------------------------------------------------------------------------------------------
Net change 1,149 (645) (2,804)
- ---------------------------------------------------------------------------------------------------------------------------
December 31 $ 6,293 $ 5,144 $ 5,789
===========================================================================================================================
</TABLE>
QUARTERLY FINANCIAL DATA -- UNAUDITED
<TABLE>
<CAPTION>
1999(c) 1998(c)
- --------------------------------------------------------------------------------------------------------------------------------
(In Millions, Except
per Share Amounts) 4th 3rd 2nd 1st 4th 3rd 2nd 1st
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues $ 627 $ 547 $ 455 $ 436 $ 499 $ 478 $492 $540
Operating Income (Loss)(a)(b) (59) 155 86 54 (671) 58 73 127
Net Income (Loss)(a)(b) (84) 61 24 -- (411) 13 16 61
Basic Earnings (Loss) per
Common Share (.38) .28 .11 -- (1.95) .07 .07 .29
Diluted Earnings (Loss) per
Common Share (.38) .27 .11 -- (1.95) .07 .07 .29
Cash Dividends Declared per
Common Share .12 .11 .12 .11 .11 .12 .11 .12
Common Stock Price Range
High 39 1/4 46 3/4 47 5/8 42 5/16 43 1/8 44 1/2 49 5/8 49 1/2
Low $ 29 1/2 $ 35 5/8 $ 38 3/8 $ 29 1/2 $ 32 $ 29 7/16 $ 38 3/16 $ 38 15/16
================================================================================================================================
</TABLE>
(a) During the fourth quarter of 1999, as a result of the Acquisition, the
Company recorded a pretax charge of $37 million for severance and
transaction costs ($26 million after tax).
(b) During the fourth quarter of 1999, as a result of a downward adjustment
associated with the performance of certain properties, the Company
recognized a non-cash, pretax charge of $225 million ($140 million after
tax). During the fourth quarter of 1998, as a result of a weak market for
oil and gas, the Company recognized a non-cash, pretax charge of $706
million ($390 million after tax).
(c) Amounts in periods prior to the Acquisition have been restated to include
Poco.
61
<PAGE> 64
BOARD OF DIRECTORS
John V. Byrne (1)
President Emeritus
Oregon State University
S. Parker Gilbert (2)
Former Chairman
Morgan Stanley Group Inc.
Laird I. Grant (1)
Former President, Chief Executive Officer
and Chief Investment Officer
Rockefeller & Co., Inc.
John T. LaMacchia (2) (3)
President and Chief Executive Officer
CellNet Data Systems, Inc.
James F. McDonald (1) (3)
President and Chief Executive Officer
Scientific-Atlanta, Inc.
Kenneth W. Orce (1)
Senior Partner
Cahill Gordon & Reindel
Donald M. Roberts (1)
Retired Vice Chairman and Treasurer
United States Trust Company of New York
and U.S. Trust Corporation
John F. Schwarz (2)
Chairman, President and Chief
Executive Officer
Entech Enterprises, Inc.
Walter Scott, Jr. (2) (3)
Chairman
Level 3 Communications, Inc.
Bobby S. Shackouls (3)
Chairman of the Board, President and
Chief Executive Officer
Burlington Resources Inc.
H. Leighton Steward (3)
Vice Chairman of the Board
Burlington Resources Inc.
William E. Wall (2)
Of Counsel
Siderius Lonergan
(1) Audit Committee
(2) Compensation and Nominating Committee
(3) Executive Committee
OFFICERS
Bobby S. Shackouls
Chairman of the Board, President and
Chief Executive Officer
H. Leighton Steward
Vice Chairman of the Board
John E. Hagale
Executive Vice President and Chief
Financial Officer
L. David Hanower
Senior Vice President, Law and
Administration
Randy L. Limbacher
President and Chief Executive Officer
Burlington Resources North America
John A. Williams
President and Chief Executive Officer
Burlington Resources International
Lee B. Backsen
Vice President, Domestic Exploration
Suzanne V. Baer
Vice President and Treasurer
Philip W. Cook
Vice President and Controller
Richard D. Dole
Vice President and Chief Financial Officer
Burlington Resources International
Mark E. Ellis
Vice President, San Juan Division
Richard E. Fraley
Vice President, London
C. Scott Kirk
Vice President, Marketing
Gregory M. Larberg
Executive Vice President and
Chief Operating Officer
Burlington Resources International
Hunter L. Malson
Vice President, Gulf Coast Division
J. Terry McCoy
President
Burlington Resources Canada Energy Ltd.
Thomas B. Nusz
Vice President, Strategic Planning and
Engineering
Frederick J. Plaeger
Vice President and General Counsel
Gavin H. Smith
Vice President, Corporate Affairs
William B. Usher
Vice President, Human Resources and
Administration
Barry J. Winstead
Vice President, Mid-Continent Division
62
<PAGE> 65
FORWARD-LOOKING STATEMENTS
The Company may, in discussions of its future plans, objectives and expected
performance in periodic reports filed by the Company with the Securities and
Exchange Commission (or documents incorporated by reference therein) and in
written and oral presentations made by the Company, include projections or other
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 or Section 21E of the Securities Exchange Act of 1934, as amended.
Such projections and forward-looking statements are based on assumptions which
the Company believes are reasonable, but are by their nature inherently
uncertain. In all cases, there can be no assurance that such assumptions will
prove correct or that projected events will occur, and actual results could
differ materially from those projected.
CORPORATE INFORMATION
Principal Corporate Office
Burlington Resources Inc.
5051 Westheimer, Suite 1400
Houston, Texas 77056
(713) 624-9500
http://www.br-inc.com
Annual Meeting
The Annual Meeting of Stockholders will be in Houston, Texas on April 19, 2000.
Formal notice of the meeting will be mailed in advance.
Common Stock
Stock Exchange Listing
New York Stock Exchange
Symbol: BR
Stock Transfer Agent and Registrar
BankBoston, N.A.
c/o EquiServe
P.O. Box 8040
Boston, Massachusetts
02266-8040
(800) 736-3001
http://www.equiserve.com
Exchangeable Shares
Stock Exchange Listing
Toronto Stock Exchange
Symbol: BRX
Stock Transfer Agent and Registrar
CIBC Mellon Trust Company
P.O. Box 2517
Calgary, Alberta T2P 4P4
(800) 387-0825
http://www.cibcmellon.com
Additional copies of this Annual Report and the Company's Form 10-K filed with
the Securities and Exchange Commission are available, without charge, by writing
or calling:
Investor Relations
Burlington Resources Inc.
P.O. Box 4239
Houston, Texas 77210
(800) 262-3456
[PHOTO]
<PAGE> 66
[photo of a hardhat & Background Graphics]
[BURLINGTON RESOURCES LOGO]
5051 WESTHEIMER, SUITE 1400
HOUSTON, TEXAS 77056
<PAGE> 1
EXHIBIT 21.1
BURLINGTON RESOURCES INC.
SUBSIDIARIES OF THE REGISTRANT
The following is a list of the significant subsidiaries of Burlington
Resources Inc. showing the place of incorporation and the percentage of voting
securities owned.
<TABLE>
<CAPTION>
PERCENTAGE
OF VOTING
SECURITIES OWNED
DIRECTLY OR
JURISDICTION OF INDIRECTLY BY
NAME OF COMPANY INCORPORATION IMMEDIATE PARENT
--------------- --------------- ----------------
<S> <C> <C>
Burlington Resources North America Inc. .................. Delaware 100%
Burlington Resources International Inc.................... Delaware 100%
Burlington Resources Hydrocarbons Inc. ................... Delaware 100%
Burlington Resources Oil & Gas Company.................... Delaware 100%
Burlington Resources Trading Inc. ........................ Delaware 100%
Glacier Park Company...................................... Delaware 100%
The Louisiana Land and Exploration Company................ Maryland 100%
Burlington Resources Canada Inc. ......................... Alberta, Canada 100%
Burlington Resources Canada Energy Ltd. .................. Alberta, Canada 100%
</TABLE>
The names of certain subsidiaries are omitted as such subsidiaries,
considered as a single subsidiary, would not constitute a significant
subsidiary.
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statement on Form S-3 (Registration Nos. 33-54477, 333-24999, 333-52213 and
333-83163) and on Form S-8 (Registration Nos. 33-22493, 33-25807, 33-26024 (as
amended in Registration No. 2-97533), 33-33626, 33-46518, 33-53973, 333-02029,
333-32603, 333-40565, 333-60081, 333-91247 and 333-95071) of Burlington
Resources Inc. of our report dated March 3, 2000 relating to the financial
statements, which appears in the 1999 Annual Report to Shareholders, which is
incorporated in this Annual Report on Form 10-K.
PricewaterhouseCoopers LLP
Houston, Texas
March 15, 2000
<PAGE> 1
EXHIBIT 23.2
The Board of Directors
Burlington Resources Inc.
We consent to the incorporation by reference in the registration statements on
Form S-8 (Nos. 33-22493, 33-25807, 33-26024, as amended in 2-97533, 33-33626,
33-46518, 33-53973, 333-02029, 333-32603, 333-4056, 333-60081, 333-91247 and
333-90571) and on Form S-3 (Nos. 33-54477, 333-24999, 333-52213 and 333-83163)
of Burlington Resources Inc. of our report dated March 3, 2000 with respect to
the consolidated balance sheets of Burlington Resources Canada Energy Ltd. as
of December 31, 1999 and 1998 and the related consolidated statements of
income, retained earnings and cash flows for each of the three years in the
period ended December 31, 1999 which report is filed as an exhibit to the
Annual Report of Burlington Resources Inc. on Form 10-K for the year ended
December 31, 1999.
KPMG LLP
Calgary, Canada
March 15, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<EXCHANGE-RATE> 1
<CASH> 89
<SECURITIES> 0
<RECEIVABLES> 499
<ALLOWANCES> 0
<INVENTORY> 53
<CURRENT-ASSETS> 667
<PP&E> 13,769
<DEPRECIATION> 7,412
<TOTAL-ASSETS> 7,191
<CURRENT-LIABILITIES> 648
<BONDS> 2,769
0
0
<COMMON> 2
<OTHER-SE> 3,244
<TOTAL-LIABILITY-AND-EQUITY> 7,191
<SALES> 2,065
<TOTAL-REVENUES> 2,065
<CGS> 1,829
<TOTAL-COSTS> 1,829
<OTHER-EXPENSES> 2
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 211
<INCOME-PRETAX> 23
<INCOME-TAX> 22
<INCOME-CONTINUING> 1
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1
<EPS-BASIC> .01
<EPS-DILUTED> 0
</TABLE>
<PAGE> 1
Exhibit 99.1
REPORT TO THE SHAREHOLDER OF BURLINGTON RESOURCES CANADA ENERGY LTD.
We have audited the consolidated balance sheets of Burlington Resources Canada
Energy Ltd. as at December 31, 1999 and 1998 and the consolidated statements of
income, stockholders' equity and cash flows for each of the years in the three
year period ended December 31, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 1999
and 1998 and the results of its operations and cash flows for each of the years
in the three year period ended December 31, 1999 in accordance with United
States generally accepted accounting principles.
KPMG LLP
Chartered Accountants
Calgary, Canada
March 3, 2000
