SFP PIPELINE HOLDINGS INC, 10-K405, 1997-03-27

SFP PIPELINE HOLDINGS INC
10-K405, 1997-03-27
PIPE LINES (NO NATURAL GAS)

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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, 1996

[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NUMBER 1-10595
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SFP PIPELINE HOLDINGS, INC.
(Exact name of registrant as specified in its charter)

DELAWARE 36-3713699
(State of incorporation) (I.R.S. Employer Identification No.)

301 NUGGET AVENUE
SPARKS, NEVADA 89431
(Address of principal executive offices, including zip code)

(702) 358-6971
(Registrant's telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of each class Name of each exchange on which registered
- ----------------------------- ------------------------------------------------
VARIABLE RATE EXCHANGEABLE NEW YORK STOCK EXCHANGE
DEBENTURES

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: [X]

State the aggregate market value of the voting stock held by non-affiliates of
the registrant: All voting stock of the registrant is held by an affiliate,
Burlington Northern Santa Fe Corporation.

Number of shares outstanding of the registrant's common stock ($0.01 par value)
as of March 21, 1997: 1,000.

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION J (1)(a)
AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K WITH THE REDUCED
DISCLOSURE FORMAT PERMITTED BY GENERAL INSTRUCTION J.

List hereunder the documents from which parts thereof have been incorporated by
reference and the Part of the Form 10-K into which such information is
incorporated:

<TABLE>
<CAPTION>
<S> <C>
1996 Form 10-K of Santa Fe Pacific
Pipeline Partners, L.P. ......................... Parts I, II and IV
</TABLE>
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TABLE OF CONTENTS

<TABLE>
<CAPTION>
Page
----
PART I

<S> <C> <C>
Item 1. Business............................................................... 1
Item 2. Properties............................................................. 4
Item 3. Legal Proceedings...................................................... 4

PART II

Item 5. Market for Registrant's Common Stock and Related Stockholder Matters... 9
Item 7. Management's Discussion and Analysis of the Results of Operations...... 9
Item 8. Financial Statements and Supplementary Data............................ 10
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................................... 10

PART III

Item 10. Directors and Executive Officers of the Registrant.................... 11

PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...... 12
Signatures..................................................................... 15
</TABLE>
<PAGE>

SFP PIPELINE HOLDINGS, INC.

PART I

ITEM 1. BUSINESS.

SFP Pipeline Holdings, Inc. ("Holdings") was formed in June 1990 and commenced
operations in September 1990, at which time it acquired 100% of the outstanding
capital stock of Santa Fe Pacific Pipelines, Inc. and issued Variable Rate
Exchangeable Debentures Due 2010 (the "Debentures") in the aggregate principal
amount of $219.0 million. Holdings and Santa Fe Pacific Pipelines, Inc. are both
wholly owned subsidiaries of Santa Fe Pacific Corporation ("Santa Fe") and are
collectively referred to herein as the "Company" unless the context requires
otherwise. In September 1995, Santa Fe and Burlington Northern Inc. consummated
a business combination pursuant to which Santa Fe became a subsidiary of a new
publicly-held company, Burlington Northern Santa Fe Corporation ("BNSF").

Santa Fe Pacific Pipelines, Inc. ("SFPPI" or the "General Partner") serves as
the general partner of Santa Fe Pacific Pipeline Partners, L.P. (the "Trading
Partnership"), a Delaware limited partnership formed in December 1988 to acquire
and operate, through SFPP, L.P. (the "Operating Partnership"), the refined
petroleum products pipeline business of Santa Fe. Such business was previously
owned by Southern Pacific Pipe Lines, Inc. and San Diego Pipeline Company, two
indirect wholly owned subsidiaries of Santa Fe (the "Predecessor Companies").
SFPPI also directly owns a 1% general partner interest in the Operating
Partnership. Collectively, the Trading Partnership and the Operating Partnership
are referred to as the "Partnership".

In December 1988, SFPPI acquired 8,148,148 common limited partner interests in
the Partnership (the "common units") in return for its contribution to the
Partnership of a portion of the assets of the Predecessor Companies. These
common units and the general partner interest owned by the General Partner
represent approximately 42% and 2% interests in the Partnership, respectively.
The remaining approximate 56% limited partner ownership in the Partnership is
represented by 11,000,000 publicly traded units.

The Debentures are exchangeable under certain circumstances, at the option of
the holders, for an aggregate of 8,148,130 of the common units. Generally, each
$1,000 original principal amount of a debenture will be exchangeable for 37.2093
common units, during a period following the first to occur of the following
events: (i) May 17, 2010 (90 days prior to final maturity); (ii) the liquidation
of the Partnership; (iii) the sale or other disposition by the Partnership of
all or substantially all of its assets or any merger, consolidation or
recapitalization of the Partnership (other than any such transaction in which
the Partnership survives and its only outstanding equity securities are the
preference units and common units); and (iv) the occurrence of an Event of
Default under the indenture relating to the Debentures and acceleration of all
amounts due and owing under the Debentures. In lieu of delivering common units
to debentureholders at such time, the Company may elect to pay cash to the
debentureholders in an amount equal to the market price of the Debentures.

The Partnership is one of the largest independent pipeline common carriers of
refined petroleum products ("products") in the United States, and the largest in
the western United States, in terms of product deliveries, barrel miles, and
pipeline mileage, with approximately 3,300 miles of pipeline serving six states.
The Partnership transports products, including gasoline, diesel fuel and
commercial and military jet fuels, primarily for integrated petroleum companies,
independent refiners, the United States military, and marketers and distributors
of such products. The Partnership also operates 14 truck

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loading terminals and provides pipeline service to 44 customer-owned terminals,
three commercial airports, and 11 military bases. The Partnership's pipelines
are: (1) the South Line, which is composed of two segments, the West Line, which
transports products from Los Angeles to Phoenix and Tucson, Arizona and various
intermediate points, and the East Line, which transports products from El Paso,
Texas to Tucson, Phoenix and various intermediate points; (2) the North Line,
which transports products primarily from the San Francisco Bay area to various
cities in northern California and western Nevada; (3) the Oregon Line, which
transports products between Portland and Eugene, Oregon, and one intermediate
point; and (4) the San Diego Line, which transports products from Los Angeles to
San Diego, California and various intermediate points.

Substantially all of the Partnership's pipeline operations are common carrier
operations that are subject to federal or state rate regulation. The
Partnership's interstate common carrier pipeline operations are subject to rate
regulation by the Federal Energy Regulatory Commission ("FERC") under the
Interstate Commerce Act which requires, among other things, that petroleum
product pipeline rates be "just and reasonable" and nondiscriminatory. In
general, the FERC has evaluated the justness and reasonableness of petroleum
product pipeline rates under a "cost of service" approach that permits a
pipeline to establish its tariffs, based on projected volumes, at levels
sufficient to recover its cost of service. Under this approach, a pipeline's
cost of service includes the following components: (a) operating expenses, (b)
depreciation and amortization, (c) federal and state income taxes and (d) an
overall allowed rate of return on the pipeline's "rate base." Generally, rate
base is a measure of the investment in, and value of, the common carrier assets
of a petroleum products pipeline.

Under a "trended original cost" ("TOC") methodology adopted by the FERC in 1985
for establishing a liquid petroleum pipeline's tariffs, after a starting rate
base has been determined, a pipeline's rate base is to be (i) increased by an
amount equal to the equity portion of the rate base multiplied or "trended" by
an inflation factor, (ii) increased by property additions at cost and (iii)
decreased by property retirements, depreciation and amortization of the rate
base write-ups reflecting inflation. A petroleum product pipeline's capital
structure (i.e., the relative proportions of debt and equity in its total
capitalization) affects (i) its starting rate base, (ii) the proportion of the
rate base that is trended to reflect inflation under the TOC methodology and
(iii) other factors that bear on the determination of just and reasonable
pipeline rates.

Effective January 1995, the FERC established a new rate-making methodology under
which oil pipelines may also be allowed to increase, or required to decrease,
their interstate rates in accordance with an inflation index (the Producer Price
Index for Finished Goods minus one percent) published annually by the FERC.
Under this methodology, pipelines may apply for cost of service-based rates in
those cases where the carrier can demonstrate that a "substantial divergence"
exists between the rates that would be allowed under cost-based rate-making and
the rates produced by indexation. In addition, carriers may establish market-
based rates for those markets in which it can be demonstrated that they do not
have significant market power. The access to cost-based and market-based rates
is significant because the Company believes the index selected by the FERC does
not adequately reflect historical cost of service increases and, accordingly,
the Partnership may need to pursue cost-based or selective market-based rate
adjustments in future rate filings.

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Intrastate common carrier operations of the Pipeline System in California are
subject to regulation by the California Public Utilities Commission ("CPUC")
under a "depreciated book plant" methodology, which is based on an original cost
measure of investment. Intrastate tariffs filed by the Partnership with the CPUC
have been established on the basis of revenues, expenses and investments
allocated as applicable to the intrastate portion of the Partnership's business.
Tariff rates with respect to intrastate pipeline service in California are
subject to challenge by complaint by interested parties or by independent action
of the CPUC. A variety of factors can affect the rates of return permitted by
the CPUC and certain other issues similar to those which have arisen with
respect to the Partnership's FERC regulated rates could also arise with respect
to the Partnership's intrastate rates.

In 1996, rates subject to FERC and CPUC regulation accounted for approximately
57% and 43% of total transportation revenues, respectively.

The Partnership's operations are subject to federal, state and local laws and
regulations relating to protection of the environment, including laws and
regulations relating to water, air, solid waste and hazardous substances. The
discharge of, or contamination of property by, hazardous materials may arise
from the transportation and storage of such materials in the ordinary course of
operations and may expose the Partnership to claims and potential liability for
injuries to employees, other persons, property, and the environment. The
Partnership's operations are also subject to operating and safety regulation by
the Department of Transportation and various other federal, state and local
agencies.

The Partnership is managed by the General Partner and does not have any
employees, officers or directors. Regular, full-time employees of the Company,
all of whom are employees of the General Partner, numbered 435 as of December
31, 1996.

In addition to its 44% interest in the refined petroleum pipeline operations
conducted by the Partnership, Santa Fe is a holding company that presently owns
subsidiaries engaged primarily in railroad transportation operations, conducted
principally by The Burlington Northern and Santa Fe Railway Company, serving the
western, central, midwestern and southeastern regions of the United States. On
September 22, 1995, Burlington Northern Inc. and Santa Fe consummated a business
combination pursuant to which each became direct or indirect wholly owned
subsidiaries of a new publicly-held company, Burlington Northern Santa Fe
Corporation ("BNSF").

The Partnership and BNSF are both subject to the informational requirements of
the Securities Exchange Act of 1934, and in accordance therewith file reports
and other information with the Securities and Exchange Commission, to which
reference is made for detailed financial and other information regarding their
respective businesses.

ITEM 2. PROPERTIES.

As discussed above, the Company, through SFPPI, has owned an approximate 44%
interest in the Partnership since December 1988. The net book value of the
Partnership's pipeline system, truck loading terminals and other properties
aggregated approximately $630 million at December 31, 1996. Descriptions of
these properties, appearing under the captions "Description of the Pipeline
System" and "Description of the Truck Loading Terminals" on pages 4 through 5 of
the Partnership's 1996 Form 10-K, are incorporated herein by reference. The
Company itself does not own any significant properties or facilities.

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ITEM 3. LEGAL PROCEEDINGS.

PARTNERSHIP'S EAST LINE LITIGATION AND FERC PROCEEDINGS
In August 1992, two East Line refiners, Navajo Refining Company ("Navajo") and
El Paso Refinery, L.P. ("El Paso"), filed separate, though similar, civil
lawsuits (the "East Line Civil Litigation") against the Partnership arising from
the Partnership's alleged failure to provide additional pipeline capacity from
El Paso, Texas to Tucson and Phoenix, Arizona. In addition, El Paso filed a
protest/complaint with the FERC in September 1992 seeking to block the reversal
of the direction of flow of the six-inch pipeline between Phoenix and Tucson and
challenging the Partnership's proration policy, as well as the Partnership's
existing East Line rates (the "FERC Proceeding").

EAST LINE CIVIL LITIGATION
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The civil actions brought by Navajo and El Paso (El Paso Refining, Inc., and El
Paso Refinery, L.P. v. Santa Fe Pacific Pipelines, Inc. and Santa Fe Pacific
Pipeline Partners, L.P., No. 92-9144, County Court No. 5, El Paso County, filed
August 1992) were filed in New Mexico and Texas, respectively, seeking actual,
punitive and consequential damages alleged to have been caused by the
Partnership's failure to provide additional pipeline capacity from El Paso to
Tucson and Phoenix. Generally, the lawsuits allege that the refiners proceeded
with significant refinery expansions under the belief that the Partnership would
provide additional pipeline capacity to transport their product into Arizona,
and that they were damaged by their inability to ship additional volumes into
that highly competitive market when the Partnership did not provide such
additional capacity. The belief of Navajo and El Paso was purportedly based on
alleged oral representations made by General Partner personnel and from language
contained in a January 1989 settlement agreement with Navajo, relating to a 1985
FERC rate case.

In July 1993, the Partnership reached a settlement with Navajo whereby Navajo
agreed to dismiss its civil litigation in New Mexico and the Partnership agreed
to make certain cash payments to Navajo over three years and to undertake and
complete an additional pipeline capacity expansion between El Paso and Phoenix
if certain events related to volume levels and proration of pipeline capacity
should occur within five years of the date of the agreement.

El Paso's August 1992 civil action, as amended, claims unspecified actual
damages, which appear to include the alleged $190 million cost of its refinery
expansion, plus punitive and consequential damages. In addition, in October
1995, El Paso's general partner, El Paso Refining, Inc. ("EPRI"), filed a Second
Amended Petition seeking unspecified damages arising from alleged unfulfilled
representations of Partnership management with respect to future East Line
capacity, alleging that such representations had been relied upon in negotiating
the terms by which EPRI exchanged its refinery assets for ownership interests in
El Paso in 1989.

In October 1992, El Paso filed a petition for reorganization under Chapter 11 of
the federal bankruptcy laws and halted refinery operations and, in November
1993, the bankruptcy was converted to a Chapter 7 liquidation proceeding. During
1994, the bankruptcy trustee for El Paso retained legal counsel for purposes of
pursuing El Paso's litigation against the Partnership. Depositions and written
discovery have been conducted by both parties since late 1994. To date, there
have been no hearings before the court and there is no pre-trial schedule.

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installments. This proposed settlement was submitted to the bankruptcy court
overseeing the estates of El Paso and EPRI for approval on March 18, 1997.

FERC PROCEEDINGS
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At various dates following El Paso's September 1992 filing, other shippers on
the Partnership's South System, including Chevron U.S.A. Products Company
("Chevron"), Navajo, ARCO Products Company ("ARCO"), Texaco Refining and
Marketing Inc. ("Texaco"), Refinery Holding Company, L.P. (a partnership formed
by El Paso's long-term secured creditors that purchased El Paso's refinery in
May 1993), Mobil Oil Corporation and Tosco Corporation, have filed separate
complaints, and/or motions to intervene in proceedings initiated by others,
challenging the Partnership's rates on its East and West Lines. Certain of these
parties also claim that a gathering enhancement charge at the Partnership's
Watson, California pump station is in violation of the Interstate Commerce Act.
In subsequent procedural rulings, the FERC has consolidated these challenges
(Docket Nos. OR92-8-000, et al.) and ruled that they must proceed as a complaint
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proceeding, with the burden of proof being placed on the complaining parties.
Such parties must show that the Partnership's rates and practices at issue
violate the requirements of the Interstate Commerce Act.

On August 30, 1996, Ultramar Inc. ("Ultramar") filed a complaint concerning
charges associated with the use of the Partnership's Watson gathering
enhancement facilities (Docket No. OR96-15-000) and, on October 21, 1996, filed
an additional complaint against the Partnership's West Line rates (Docket No.
OR97-2-000), presenting largely the same issues raised by the West Line shippers
in the existing FERC proceedings. Management does not believe these complaints
raise significant additional issues. These complaints have been held in abeyance
pending a ruling in Docket Nos. OR92-8-000, et al.
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In June 1994, the complainants filed their cases-in-chief with the FERC, seeking
reparations for shipments between 1990 and 1993 aggregating in the range of $15
million to $20 million, as well as tariff rate reductions of between 40% and 50%
for future shipments. In August 1994, the FERC Staff submitted its case-in-chief
in the FERC proceeding, employing rate-making methodologies similar in several
respects to those presented by the complainants. In subsequent filings, the
complainants revised their requested relief to seek reparations for shipments
between 1990 and 1994 aggregating approximately $35 million, as well as rate
reductions of between 30% and 40% for shipments in 1995 and thereafter.

Both the FERC Staff and several of the complainants argued, among other things,
against the Partnership's entitlement to an income tax allowance in its cost of
service. They also utilized the Partnership's capital structure at the time of
its formation in December 1988, or a hypothetical capital structure, for the
purpose of establishing the Partnership's 1985 starting rate base under FERC
Opinion 154-B. In addition, the FERC Staff and the complainants would generally
exclude most or all of the Partnership's civil and regulatory litigation expense
from its cost of service calculations. Each of these positions is adverse to the
Partnership's position regarding its existing rate structure.

As discussed in the Partnership's 1995 Form 10-K, in June 1995, the FERC issued
a decision in an unrelated rate proceeding involving Lakehead Pipe Line Company,
Limited Partnership ("Lakehead"), ruling that Lakehead could not include an
income tax allowance in its cost of service with respect to partnership income
that is attributable to limited partnership interests held by individuals. On
May 17, 1996, the FERC issued an order on rehearing in that proceeding (the
"Lakehead Order") that reaffirmed and clarified the June 1995 decision and
further limited Lakehead's entitlement to an income tax allowance by excluding
from Lakehead's cost of service the taxes attributable to curative allocations
of income to Lakehead's general partner under Section 704 (c) of the Internal
Revenue Code. If upheld

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and applied in the Partnership's FERC Proceeding, the Partnership's entitlement
to an income tax allowance in its cost of service could also be limited by the
principles stated in the Lakehead Order.

Successive rounds of testimony were filed by the respective parties, including
the Partnership, regarding the above summarized issues and other matters
relevant to the appropriateness of the Partnership's tariffs and rates. Among
other things, certain of the parties submitted revised cases based on the
Partnership's 1994 costs and revenues. The Partnership's surrebuttal
presentation responded to those cases, defending the Partnership's current rates
based on 1994 data, with certain normalizing adjustments, including a
significant adjustment to reflect an extensive pipe reconditioning program that
was begun in 1994.

Hearings in the FERC Proceeding commenced on April 9, 1996 and concluded on July
19, 1996. The parties completed the filing of their post-hearing briefs on
December 9, 1996. An initial decision by the FERC Administrative Law Judge is
expected in 1997.

The Energy Policy Act of 1992 ("EPACT") provided that existing oil pipeline
rates that were in effect without challenge for 365 days prior to the bill's
enactment in October 1992 are deemed to be "just and reasonable," with an
exception being allowed for parties, such as Navajo, that were prohibited from
filing challenges during that period due to the terms of settlement agreements.
In October 1993, with respect to Chevron's complaint, the FERC ruled that the
Partnership's West Line rates are deemed "just and reasonable" under EPACT
(i.e., are "grandfathered") and may only be challenged upon a showing of a
substantial change in the economic circumstances which were the basis for the
rate ("changed circumstances"). In December 1994, ARCO, Texaco and Chevron filed
testimony in which they sought to demonstrate the required "changed
circumstances" in order to challenge the Partnership's West Line rates, citing
such factors as increased West Line volumes. In April 1995, the United States
Court of Appeals for the District of Columbia Circuit dismissed petitions for
review of the FERC's grandfathering rulings that had been filed by ARCO and
Texaco, on the ground that the FERC rulings are not yet final orders and,
therefore, are not yet subject to judicial review.

In December 1995, Texaco filed an additional FERC complaint, which involves the
question whether a tariff filing is required for movements on certain of the
Partnership's lines upstream of its Watson, California station origin point and,
if so, whether those rates may be set in this proceeding and what those rates
should be. Texaco's initial complaint was followed by several other West Line
shippers filing similar complaints and/or motions to intervene, all of which
have been consolidated into Docket Nos. 96-2-000 et al. Hearings before an
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Administrative Law Judge were held in December 1996 and the parties completed
the filing of final post-hearing briefs on January 31, 1997. An initial decision
is expected during 1997.

In June 1996, the Partnership entered into an agreement with the El Paso
bankruptcy trustee to settle El Paso's claims in the FERC Proceeding with a
payment by the Partnership of $1,250,000. The agreement subsequently was
approved by the bankruptcy court, and the presiding FERC Administrative Law
Judge permitted El Paso to withdraw its complaint. This settlement does not
affect El Paso's civil litigation against the Partnership.

In September 1996, the Partnership and Navajo reached an agreement whereby
Navajo agreed to withdraw its complaint against the Partnership's West Line
rates in exchange for a cash payment of $1,000,000. Navajo's request to withdraw
its West Line complaint was submitted to the FERC for approval in November 1996
and is currently pending. This settlement would not affect Navajo's remaining
complaint against the Partnership's East Line rates.

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During 1996, the Partnership also presented settlement offers to all of the
remaining complainants in the FERC proceedings, including Navajo with respect to
East Line rates. The terms of the existing settlement agreements with El Paso
and Navajo do not provide for rate reductions, but other offers that have been
extended do include proposed prospective reductions in the rates at issue in the
proceedings.

During the quarter ended September 30, 1996, the Partnership recorded an $8
million provision to increase its existing reserves to reflect the total amount
that would be payable under the settlement offers that had been extended as of
that date, including those offers that have been accepted by El Paso and Navajo
and, during the quarter ended December 31, 1996, recorded an additional $15
million provision to increase its reserves to reflect management's current
estimate of the ultimate costs of resolution of the FERC proceedings. The
Partnership is not able to predict with certainty whether settlement agreements
will be completed with some or all of the remaining complainants, the final
terms of any such additional settlement agreements that may be consummated, or
the final outcome of the FERC proceedings should they be carried through to
their conclusions. However, the ultimate resolution of the FERC proceedings
could have a material adverse effect on the Partnership's results of operations,
financial condition, liquidity and ability to maintain its quarterly cash
distribution at the current level.

PARTNERSHIP'S ENVIRONMENTAL MATTERS
The Partnership is subject to environmental cleanup and enforcement actions from
time to time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA" or "Superfund" law) generally imposes
joint and several liability for cleanup and enforcement costs, without regard to
fault or the legality of the original conduct, on current or predecessor owners
and operators of a site.

Since August 1991, the Partnership, along with several other respondents, has
been involved in one cleanup ordered by the United States Environmental
Protection Agency ("EPA") related to ground water contamination in the vicinity
of the Partnership's storage facilities and truck loading terminal at Sparks,
Nevada. The EPA approved the respondents' remediation plan in September 1992 and
the remediation system began operations in September 1995. In addition, the
Partnership is presently involved in 18 ground water hydrocarbon remediation
efforts under administrative orders issued by the California Regional Water
Quality Control Board and two other state agencies.

The investigation and remediation at and adjacent to the Partnership's storage
facilities and truck loading terminal in Sparks, Nevada was also the subject of
a lawsuit brought against the Partnership and other terminal operators in
January 1991 entitled Nevada Division of Environmental Protection v. Santa Fe
Pacific Pipelines, Inc. et al., Case No. CV91-546, in the Second Judicial
-- --
District Court of the State of Nevada. This lawsuit was subsequently joined by
the County of Washoe Health District and the City of Sparks. These parties
sought remediation of the contamination at and adjacent to the Sparks terminal
as well as unspecified, but potentially significant, damages and statutory
penalties. In addition, the Partnership was named as one of the defendants in a
number of other lawsuits brought by property owners seeking unspecified, but
potentially substantial, damages for, among other things, alleged property value
diminishment attributable to soil or groundwater contamination arising from the
defendants' operations.

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group agreed to use its best efforts to install an enhanced remediation system
to accelerate the cleanup of the environmental site. In that regard, the
Partnership is currently in discussions with both the EPA and Nevada Division of
Environmental Protection on possible enhancements to the existing remediation
system. In addition, during late 1995 and early 1996, the defendant group
reached final agreements to settle the claims of the seven property owners who
had filed lawsuits seeking damages alleged to be attributable to the
environmental contamination. These settlement agreements involve various terms,
including cash payments, environmental and property value diminishment
indemnifications, loan guarantees and the purchase of certain properties. All of
the lawsuits have now been dismissed. The Partnership's share of the costs of
all of the settlement agreements associated with the Sparks litigation was
included in its 1995 provisions for environmental costs aggregating $24 million.

During the quarter ended December 31, 1996, the Partnership entered into a
settlement agreement with the California Air Resources Board and Imperial County
Air Pollution Control District to settle all of the agencies' claims arising
from violations noted during compliance inspections of the Partnership's storage
tanks at its Niland and Imperial, California facilities. In accordance with this
agreement, in November 1996, the Partnership paid approximately $80,000 in fines
and approximately $100,000 in support of projects designed to improve air
quality in Imperial County, and reimbursed approximately $30,000 in oversight
costs to the two governmental agencies.

The Partnership is negotiating with certain governmental agencies to settle
claims arising from product releases from Partnership facilities. Management
does not believe that the total cost of any fines or other amounts payable
associated with these product releases, either individually or in the aggregate,
will be material to the Partnership's results of operations or financial
condition, but such amounts may be in excess of $100,000 per occurrence.

The Partnership and the General Partner have initiated two legal actions against
a total of 34 past and present insurance carriers (SFPP, L.P., Santa Fe Pacific
Pipeline Partners, L.P. and Santa Fe Pacific Pipelines, Inc. vs. Agricultural
Insurance Company, et al. and SFPP, L.P., Santa Fe Pacific Pipeline Partners,
-- --
L.P. and Santa Fe Pacific Pipelines, Inc. vs. Associated International Insurance
Company, et al., Superior Court of the State of California for the County of San
-- --
Mateo, Docket Nos. 395109 and 395121, respectively, filed January 1996). These
actions seek a judicial determination that the insurance policies issued by the
defendant insurers provide coverage to the Partnership and the General Partner
for certain costs, liabilities and settlements relating to approximately 25
environmental sites, including Sparks, Nevada. To date, the costs at issue in
these actions have been borne by the Partnership and its predecessor companies.
The defendant insurers have filed initial responsive pleadings in these actions,
and discovery is in progress.

et al., Superior Court of the State of California for the County of San
- -- --
Francisco, filed August 31, 1994). Under an agreement entered into among the
parties in 1994, the amount of annual rent for such easements for the first year
of the ten-year period that began January 1, 1994 is to be based on the fair
market value of the easements, with the rent for subsequent years to be subject
to annual inflation adjustments. This matter was tried in the latter part of
1996 and the court issued its Statement of Tentative Decision in January

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1997. The Statement of Tentative Decision indicated that the court intended to
establish a new base annual rental for the subject rights-of-way at a level,
subject to inflation adjustments, that is adequately provided for by the amounts
that had been accrued by the Partnership through December 31, 1996. This
tentative decision could be modified by the trial court prior to its entry of
final judgment in the matter and the trial court's judgment will be subject to
appeal by SPTC once it is entered.

The Partnership and the General Partner are parties to a number of other legal
actions arising in the ordinary course of business. While the final outcome of
these other matters cannot be predicted with certainty, it is the opinion of
management that none of these other legal actions, either individually or in the
aggregate, when finally resolved, will have a material adverse effect on the
annual results of operations, financial condition or liquidity of the
Partnership or the Company, or on the Partnership's ability to maintain its
quarterly cash distribution at the current level.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS.

All 1,000 shares of Holdings' authorized and outstanding $0.01 par value common
stock are owned by Santa Fe. The Company declared and paid cash dividends
aggregating $7,000,000 to Santa Fe during 1996. No dividends were paid by the
Company in 1995 or 1994.

ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS.

As the principal assets of the Company are its investment in the Partnership and
its notes receivable from Santa Fe, this narrative analysis should be read in
conjunction with the following: (1) Management's Discussion and Analysis of
Financial Condition and Results of Operations of the Partnership, appearing on
pages 17 through 21 of the Partnership's 1996 Annual Report on Form 10-K,
incorporated herein by reference; and (2) Management's Discussion and Analysis
of Financial Condition and Results of Operations of BNSF, filed as Exhibit 28.2
to this Form 10-K.

The Company's equity in income of the Partnership for the year ended December
31, 1996 of $25.0 million was $5.7 million, or approximately 30%, higher than in
1995 primarily due to special items recorded by the Partnership in both years.
The Partnership's results of operations include provisions for litigation costs
aggregating $23.0 million in 1996 and provisions for environmental and
litigation costs aggregating $34.0 million in 1995. Excluding these provisions,
the Company's adjusted equity in income of the Partnership would have been $35.6
million in 1996, compared to the adjusted equity income balance of $35.0 million
in 1995. Full year Partnership revenues of $240.1 million were $6.5 million, or
approximately 3%, higher than in 1995, with trunk revenues being 3% higher
primarily due to growth in total volumes transported. Other Partnership revenues
increased $0.5 million due to the higher volumes delivered.

Partnership operating expenses in 1996 of $152.0 million were $5.7 million lower
than in 1995. Excluding the provisions described above, 1996 operating expenses
would have been $5.3 million, or about 4.5%, higher than in 1995, with higher
field operating expenses ($4.4 million), general and administrative expenses
($2.8 million) and depreciation and amortization ($0.6 million), being partially
offset by lower facilities costs ($1.8 million) and power costs ($0.7 million).
The Partnership's other

- 9 -
<PAGE>

income, net decreased by $0.6 million compared to 1995, primarily due to lower
interest income, attributable to lower cash balances, partially offset by a gain
on the sale of excess land.

Interest income is earned on the notes receivable from Santa Fe, with the
interest rates being tied to the Federal Funds rate. The decrease in interest
income in 1996 reflects lower market interest rates. Interest expense is accrued
based on the quarterly distribution paid on the 8,148,130 Partnership units for
which the Debentures are, under certain specified conditions, exchangeable.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The Company's consolidated financial statements, together with the report
thereon of Price Waterhouse LLP dated January 31, 1997, appear on pages F-1
through F-15 of this Report.

The consolidated financial statements of the Partnership (Commission File Number
1-10066), together with the report thereon of Price Waterhouse LLP dated January
31, 1997, appearing on pages F-1 through F-15 of the Partnership's Form 10-K for
the year ended December 31, 1996, are incorporated herein by reference.

The consolidated financial statements of BNSF, together with the report thereon
of Price Waterhouse LLP dated February 7, 1997, are filed as Exhibit 28.1 to
this Report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

None.

- 10 -
<PAGE>

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

Directors of Holdings are elected annually by Santa Fe. Officers serve at the
discretion of the directors.

Orval M. Adam, age 66, is a director of Holdings and is a member of the Audit
Committee. He retired in January 1991 from his position as Senior Vice President
and Chief Financial Officer of Santa Fe. Mr. Adam is also a director of the
General Partner.

Michael A. Morphy, age 64, is a director of Holdings and is Chairman of the
Audit Committee. Mr. Morphy retired in 1985 from his position as Chairman and
Chief Executive Officer of California Portland Cement Company (cement
manufacturer). Mr. Morphy is also a director of the General Partner, Santa Fe
Energy Resources, Inc. and Cyprus Amax Minerals Company.

Denis E. Springer, age 51, is a director of Holdings. Mr. Springer has been
Senior Vice President and Chief Financial Officer of BNSF since September 1995
and previously served in those same positions at Santa Fe since October 1993.
Mr. Springer previously served Santa Fe as Senior Vice President, Treasurer and
Chief Financial Officer since January 1992. Mr. Springer is also a director of
the General Partner.

Irvin Toole, Jr., age 55, has been President, Chief Executive Officer and
Chairman of the Boards of Directors of Holdings and the General Partner since
September 1991. From November 1988 through September 1991, Mr. Toole served as
Senior Vice President, Treasurer and Chief Financial Officer of the General
Partner, and in the same positions with Holdings beginning with its
incorporation in 1990.

Robert L. Edwards, age 41, is a director of Holdings and the General Partner,
and has been Senior Vice President-Business Development and Planning of the
General Partner since January 1995. Previously, Mr. Edwards was Senior Vice
President, Treasurer and Chief Financial Officer of Holdings and the General
Partner from December 1991 to January 1995.

Barry R. Pearl, age 47, has been Senior Vice President, Treasurer and Chief
Financial Officer of Holdings and the General Partner since January 1995.
Previously, Mr. Pearl served the General Partner as Senior Vice President-
Business Development and Planning from January 1992 to January 1995.

R. Gregory Cunningham, age 51, has been General Counsel of Holdings since
February 1991. Mr. Cunningham has also served the General Partner as Vice
President - General Counsel since January 1994 and as General Counsel since
January 1991.

Burnell H. DeVos III, age 43, has been Controller and Secretary of Holdings and
the General Partner since January 1993 and previously served as Assistant
Controller of the General Partner from May 1989 to December 1992.

- 11 -
<PAGE>

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

(a) The following documents are filed as a part of this Report:

<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
(1) Financial Statements of SFP Pipeline Holdings, Inc.:
Report of Independent Accountants......................................................... F-1
Consolidated Balance Sheet as of December 31, 1996 and 1995............................... F-2
Consolidated Statement of Operations for the three years ended December 31, 1996.......... F-3
Consolidated Statement of Cash Flows for the three years ended December 31, 1996.......... F-4
Notes to Consolidated Financial Statements................................................ F-5

Financial Statements of Santa Fe Pacific Pipeline Partners, L.P. (a):
Report of Independent Accountants......................................................... F-1
Consolidated Balance Sheet as of December 31, 1996 and 1995............................... F-2
Consolidated Statement of Income for the three years ended December 31, 1996.............. F-3
Consolidated Statement of Cash Flows for the three years ended December 31, 1996.......... F-4
Notes to Consolidated Financial Statements................................................ F-5

Financial Statements of Burlington Northern Santa Fe Corporation (b):
Report of Independent Accountants......................................................... 1
Consolidated Statements of Income for the three years ended December 31, 1996............. 2
Consolidated Balance Sheets as of December 31, 1996 and 1995.............................. 3
Consolidated Statements of Cash Flows for the three years ended December 31, 1996......... 4
Consolidated Statements of Changes in Stockholders' Equity for the three years
ended December 31, 1996.................................................................. 5
Notes to Consolidated Financial Statements................................................ 6
</TABLE>

(a) Incorporated by reference from the indicated pages of the
Partnership's 1996 Form 10-K (Commission File No. 1-10066).
(b) Filed as Exhibit 28.1 to this Report.

(2) Financial Statement Schedules: None

(3) Exhibits: The following exhibits are filed as a part of this Report:

Exhibit
Number Description
- ------- ----------------------------------------------------------------------
<C> <S>
2.1 Agreement and Plan of Merger dated as of June 29, 1994, between
Burlington Northern Inc. and Santa Fe Pacific Corporation as amended
by Amendments 1 and 2 thereto, together with Amendments 3 and 4
thereto. Schedules have been omitted but will be furnished
supplementally to the Securities and Exchange Commission upon request.
Incorporated by reference to Exhibit 2.1 to the Registrant's Report on
Form 8-K dated September 22, 1995 (date of earliest event reported)
and filed on October 6, 1995.

3.1 Certificate of Incorporation of the Registrant, dated as of June 26,
1990. Incorporated by reference to Exhibit 3.1 to the Registrant's
Registration Statement on Form S-1.

3.2 By-Laws of the Registrant. Incorporated by reference to Exhibit 3.2 to
the Registrant's Registration Statement on Form S-1.
</TABLE>

- 12 -
<PAGE>

<TABLE>
<CAPTION>
Exhibit
Number Description
- ------- ----------------------------------------------------------------------
<C> <S>
4.1 Indenture dated September 13, 1990, between the Registrant and
Security Pacific National Bank, National Association, as Trustee,
relating to the Variable Rate Exchangeable Debentures Due 2010.
Incorporated by reference to Exhibit 4.1 to the Registrant's 1990 Form
10-K.

4.2 Amended and Restated Agreement of Limited Partnership of Santa Fe
Pacific Pipeline Partners, L.P., dated as of December 19, 1988, as
amended by Amendment No. 1 thereto, dated as of December 7, 1989.
Incorporated by reference to Exhibit 4.2 to the Registrant's
Registration Statement on Form S-1.

4.3 First Mortgage Note Agreement, dated December 8, 1988 (a conformed
composite of 54 separate note agreements, identical except for
signatures), executed by the Operating Partnership, relating to $355
million aggregate principal amount of First Mortgage Notes.
Incorporated by reference to Exhibit 4.3 to the Registrant's
Registration Statement on Form S-1.

10.1 Santa Fe's Supplemental Retirement Plan. Incorporated by reference to
Exhibit 10(d) to Santa Fe's 1984 Form 10-K. The Plan, as amended as of
October 1, 1989, and a Plan amendment dated February 27, 1990 are
incorporated by reference to Exhibit 10(d) to Santa Fe's 1989 Form 10-
K.**

10.2 Santa Fe's Incentive Stock Compensation Plan. Incorporated by
reference to Exhibit 10(e) to Santa Fe's 1985 Form 10-K. Plan
amendments dated May 28, 1987 and October 29, 1987 are incorporated by
reference to Exhibit 10(e) to Santa Fe's 1987 Form 10-K. Amendments
dated March 8, 1989, June 8, 1989 and February 27, 1990 are
incorporated by reference to Exhibit 10(e) to Santa Fe's 1989 Form 10-
K. A Plan amendment dated July 24, 1990 is incorporated by reference
to Santa Fe's June 30, 1990 Form 10-Q. A Plan amendment dated December
4, 1990 is incorporated by reference to Santa Fe's 1990 Form 10-K.**

10.3 Trust Agreement, dated July 6, 1987, between Santa Fe and Harris Trust
and Savings Bank as Trustee, as amended on October 28, 1987 and
November 2, 1987. Incorporated by reference to Exhibit 10(k) of Santa
Fe's 1987 Form 10-K. Amendment to Trust Agreement, dated September 1,
1988, is incorporated by reference to Exhibit 10(i) to Santa Fe's 1988
Form 10-K.**

10.4 The Santa Fe Pacific Pipelines, Inc. Incentive Compensation Plan is
incorporated by reference to Exhibit 10.8 to the Registrant's
Registration Statement on Form S-1. A Plan amendment dated January 12,
1994 is incorporated by reference to Exhibit 10.5 to the Registrant's
1993 Form 10-K.**

10.5 The MLP Incentive Plan is incorporated by reference to Exhibit 10.9 to
the Registrant's Registration Statement on Form S-1.**

10.6 The MLP Phantom Unit Incentive Plan is incorporated by reference to
Exhibit 10 to the Registrant's June 30, 1993 Form 10-Q.**

10.7 Form of Employment Agreement, effective June 1, 1990, between Santa Fe
Pacific Pipelines, Inc. and I. Toole, Jr., J. M. Abboud, B. R. Pearl,
R. G. Cunningham and L. B. Boarts, and, effective December 1, 1991,
between Santa Fe Pacific Pipelines, Inc. and R. L. Edwards.
Incorporated by reference to Exhibit 10.16 to Amendment No. 1 to the
Registrant's Registration Statement on Form S-1.**

</TABLE>
- 13 -
<PAGE>

<TABLE>
<CAPTION>
Exhibit
Number Description
- ------- ----------------------------------------------------------------------
<C> <S>
10.8 Agreement for the Allocation of the Consolidated Federal Income Tax
Liability Among the Members of the Santa Fe Southern Pacific
Corporation Affiliated Group, effective January 1, 1987. Incorporated
by reference to Exhibit 10.12 to the Registrant's Registration
Statement on Form S-1.

10.9 Form of Promissory Note issued by Santa Fe to the Company in exchange
for one-half of the net proceeds from the sale of the Debentures.
Incorporated by reference to Exhibit 21 to the Registrant's
Registration Statement on Form S-1.

13.1* The Partnership's Form 10-K for the year ended December 31, 1996.

21* Subsidiaries of the Registrant.

24* Powers of attorney.

27 Financial Data Schedule

28.1* BNSF's consolidated financial statements as of December 31, 1996 and
1995 and for the three years in the period ended December 31, 1996,
together with the report thereon of Price Waterhouse LLP dated
February 7, 1997.

28.2* BNSF's 1996 Management's Discussion and Analysis of Financial
Condition and Results of Operations.
</TABLE>

* Filed herewith.
** Management contract or compensatory plan or arrangement.

Notes: The Registrant's Registration Statement on Form S-1 was designated No.
33-35638. Santa Fe was identified as Commission File No. 1-8627.

(b) Reports on Form 8-K filed during the quarter ended December 31, 1996: None.

- 14 -
<PAGE>

SIGNATURES

SFP Pipeline Holdings, Inc., pursuant to the requirements of Section 13 or 15(d)
of the Securities Exchange Act of 1934, has duly caused this Report to be signed
on its behalf by the undersigned, thereunto duly authorized.

SFP PIPELINE HOLDINGS, INC.

Dated: March 24, 1997 By: /s/ IRVIN TOOLE, JR.
---------------------------------------------
Irvin Toole, Jr.
Chairman, 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 the Registrant and
in the capacities and on the date indicated.
<TABLE>
<CAPTION>
Signature Title
----------------------------------- -----------------------------------
<S> <C>
Chairman, President and
/s/ IRVIN TOOLE, JR. Chief Executive Officer
----------------------------------- (Principal Executive Officer)
Irvin Toole, Jr. And Director

/s/ BARRY R. PEARL Senior Vice President, Treasurer
----------------------------------- and Chief Financial Officer
Barry R. Pearl (Principal Financial Officer)

/s/ BURNELL H. DEVOS III
----------------------------------- Controller and Secretary
Burnell H. DeVos III (Principal Accounting Officer)

/s/ ROBERT L. EDWARDS
-----------------------------------
Robert L. Edwards Director

ORVAL M. ADAM*
-----------------------------------
Orval M. Adam Director

MICHAEL A. MORPHY*
-----------------------------------
Michael A. Morphy Director

DENIS E. SPRINGER*
-----------------------------------
Denis E. Springer Director

*By: /s/ BARRY R. PEARL
-----------------------------------
Barry R. Pearl, attorney in fact

Dated: March 24, 1997
</TABLE>

-15-
<PAGE>

REPORT OF INDEPENDENT ACCOUNTANTS

TO THE BOARD OF DIRECTORS OF SFP PIPELINE HOLDINGS, INC.

In our opinion, the consolidated financial statements of SFP Pipeline Holdings,
Inc. listed in the index appearing under Item 14 (a) (1) on page 12 present
fairly, in all material respects, the financial position of SFP Pipeline
Holdings, Inc. and subsidiaries at December 31, 1996 and 1995, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted accounting
principles. 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 of these statements in
accordance with generally accepted auditing standards 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 provide a reasonable basis for the opinion expressed
above.

/s/ PRICE WATERHOUSE LLP

PRICE WATERHOUSE LLP

Los Angeles, California
January 31, 1997

F-1
<PAGE>

SFP PIPELINE HOLDINGS, INC.
CONSOLIDATED BALANCE SHEET

(In thousands)
<TABLE>
<CAPTION>
December 31,
------------------
1996 1995
-------- --------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents........................... $ 3,061 $ 7,890
Interest receivable................................. 1,047 1,148
Other current assets................................ 295 450
-------- --------
Total current assets.............................. 4,403 9,488
Investment in Santa Fe Pacific Pipeline Partners, L.P. 59,984 63,402
Notes receivable from Santa Fe Pacific Corporation.... 130,000 130,000
Debt issuance costs, net.............................. 6,597 7,080
Other assets.......................................... 2,701 2,676
-------- --------
Total assets...................................... $203,685 $212,646
======== ========

LIABILITIES AND STOCKHOLDER'S DEFICIT

Current liabilities
Interest payable.................................... $ 6,111 $ 6,111
Income taxes currently payable...................... 848 479
Other current liabilities........................... 4,981 6,264
-------- --------
Total current liabilities......................... 11,940 12,854
Long-term debt, net of unamortized discount........... 204,173 203,638
Deferred income taxes................................. 58,042 63,915
Other liabilities..................................... 1,960 2,112
-------- --------
Total liabilities................................. 276,115 282,519
-------- --------
Commitments and contingencies (Note 5)................ -- --
-------- --------
Stockholder's deficit
Common stock........................................ 1 1
Additional paid-in capital.......................... (33,388) (33,388)
Accumulated deficit................................. (39,043) (36,486)
-------- --------
Total stockholder's deficit....................... (72,430) (69,873)
-------- --------
Total liabilities and stockholder's deficit....... $203,685 $212,646
======== ========
</TABLE>

See Notes to Consolidated Financial Statements.

F-2
<PAGE>

SFP PIPELINE HOLDINGS, INC.
CONSOLIDATED STATEMENT OF OPERATIONS

(IN THOUSANDS)
<TABLE>
<CAPTION>

Year ended December 31,
---------------------------------
1996 1995 1994
--------- --------- ---------
<S> <C> <C> <C>
Equity in income of
Santa Fe Pacific Pipeline Partners, L.P..... $ 24,989 $ 19,296 $ 35,282

General and administrative expenses
and other, net of reimbursements............ 477 784 657
--------- --------- ---------
Operating income............................. 24,512 18,512 34,625

Interest income.............................. 8,835 9,512 6,642
Interest expense............................. 25,465 25,434 23,757
--------- --------- ---------

Income before income taxes................... 7,882 2,590 17,510
Income taxes................................. 3,439 1,069 7,262
--------- --------- ---------
Net income................................... 4,443 1,521 10,248

Accumulated deficit
Beginning of period....................... (36,486) (38,007) (48,255)
Cash dividends............................ (7,000) -- --
--------- --------- ---------
End of period............................. $ (39,043) $ (36,486) $ (38,007)
========= ========= =========

Administrative expenses reimbursed by
Santa Fe Pacific Pipeline Partners, L.P.
and not reflected above (Note 6)............ $ 50,425 $ 45,845 $ 40,565
========= ========= =========
</TABLE>

See Notes to Consolidated Financial Statements.

F-3

<PAGE>

SFP PIPELINE HOLDINGS, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS

(IN THOUSANDS)
<TABLE>
<CAPTION>
Year ended December 31,
---------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income....................................... $ 4,443 $ 1,521 $ 10,248
-------- -------- --------
Adjustments to reconcile net income to net
cash provided (used) by operating activities--
Equity in undistributed earnings of
Santa Fe Pacific Pipeline Partners, L.P....... 3,418 8,293 (10,146)
Deferred income taxes.......................... (5,873) (4,568) (1,252)
Amortization of debt issuance costs
and original issue discount................... 1,018 973 930
Changes in:
Current assets............................... 256 (389) (103)
Current liabilities.......................... (914) 2,390 (1,437)
Other assets and other liabilities........... (177) (473) (79)
-------- -------- --------
Total adjustments......................... (2,272) 6,226 (12,087)
-------- -------- --------
Net cash provided (used) by operating
activities............................... 2,171 7,747 (1,839)

Cash flows from investing activities............... -- -- --

Cash flows from financing activities:
Cash dividends................................... (7,000) -- --
-------- -------- --------
Increase (decrease) in cash and cash equivalents... (4,829) 7,747 (1,839)

Cash and cash equivalents--
Beginning of period.............................. 7,890 143 1,982
-------- -------- --------
End of period.................................... $ 3,061 $ 7,890 $ 143
======== ======== ========
Income taxes paid.................................. $ 8,942 $ 5,173 $ 9,915
======== ======== ========
Interest paid...................................... $ 24,444 $ 24,051 $ 22,821
======== ======== ========
</TABLE>

See Notes to Consolidated Financial Statements.

F-4
<PAGE>

SFP PIPELINE HOLDINGS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements include the accounts of SFP
Pipeline Holdings, Inc. ("Holdings") and its wholly owned subsidiary, Santa Fe
Pacific Pipelines, Inc. ("SFPPI") (collectively, the "Company"). Holdings is a
wholly owned subsidiary of Santa Fe Pacific Corporation ("Santa Fe"). Subsequent
to a business combination in September 1995, Santa Fe is a wholly owned
subsidiary of Burlington Northern Santa Fe Corporation ("BNSF").

Holdings was incorporated in June 1990 by a $1,000 capital contribution from
Santa Fe and commenced operations in September 1990, at which time Santa Fe
contributed 100% of the outstanding capital stock of SFPPI to Holdings and, as
discussed in Note 4, Holdings issued debentures (the "Debentures") in a
principal amount of $219 million. Santa Fe Pacific Pipelines, Inc. ("SFPPI" or
the "General Partner") serves as the general partner of Santa Fe Pacific
Pipeline Partners, L.P. (the "Partnership"), a Delaware limited partnership
formed in December 1988 to acquire and operate the refined petroleum products
pipeline business of Santa Fe. Such business was previously owned by Southern
Pacific Pipe Lines, Inc. and San Diego Pipeline Company, two indirect wholly
owned subsidiaries of Santa Fe (the "Predecessor Companies").

The preparation of financial statements in accordance with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the periods presented.
Actual results could differ from those estimates.

REVENUE RECOGNITION
The Company has recorded its 2% general partner interest and approximate 41.7%
limited partner interest, represented by its ownership of 8,148,148 Partnership
common units, in the Partnership under the equity method of accounting. Interest
income is recognized as earned.

CASH EQUIVALENTS
The Company considers all highly liquid investments with a maturity of three
months or less when purchased to be cash equivalents.

RECLASSIFICATIONS
Certain comparative prior year amounts have been reclassified to conform with
the current year presentation.

F-5
<PAGE>

NOTE 2: INVESTMENT IN SANTA FE PACIFIC PIPELINE PARTNERS, L.P.

The following table sets forth selected financial data for the Partnership, in
which SFPPI holds an approximate 44% interest (in thousands, except per unit
data):
<TABLE>
<CAPTION>

Year ended December 31,
------------------------------------
1996 1995 1994
------------ --------- ---------
<S> <C> <C> <C>
INCOME STATEMENT DATA
Total operating revenues.............. $240,142 $233,677 $228,066
Operating expenses, excluding 129,021 123,696 117,019
provisions...........................
Provisions for environmental and 23,000 34,000 ---
litigation costs.....................
Operating income...................... 88,121 75,981 111,047
Interest expense...................... 36,518 37,247 37,570
Net income............................ $ 52,275 $ 40,367 $ 76,885

PER UNIT DATA
Net income per unit................... $ 2.64 $ 2.04 $ 3.93
Cash distributions declared per unit.. 3.00 3.00 2.80

<CAPTION>
December 31,
------------------------
1996 1995
------------ --------
BALANCE SHEET DATA
Total current assets.................. $ 77,909 $ 82,255
Net properties, plant and equipment... 628,694 623,318
Total assets.......................... 725,818 720,854
Total current liabilities............. 35,545 34,075
Long-term debt........................ 355,000 355,000
Total partners' capital............... 262,915 270,065
</TABLE>

The Partnership's consolidated financial statements as of December 31, 1996 and
1995 and for the three years in the period ended December 31, 1996 are
incorporated by reference in this Form 10-K (see Index to Financial Statements
at page 12 of this Report).

CASH DISTRIBUTIONS
The Partnership makes quarterly cash distributions of substantially all of its
available cash, generally defined as consolidated cash receipts less
consolidated cash expenditures and such retentions for working capital,
anticipated capital expenditures and contingencies as the General Partner deems
appropriate or as are required by the terms of the Partnership's long-term debt.
Distributions are made 98% to the limited partners (the "unitholders") and 2% to
the General Partner, subject to the payment of incentive distributions to the
General Partner which increase as quarterly distributions to unitholders exceed
certain specified target levels. The incremental incentive distributions payable
to the General Partner are 8%, 18% and 28% of all quarterly distributions of
available cash that exceed, respectively, $0.60, $0.65 and $0.70 per unit.

F-6
<PAGE>

As the general partner and a limited partner in the Partnership, SFPPI received
distributions aggregating $28,407,000, $27,589,000 and $25,136,000, including
incentive distributions of $2,734,000, $2,351,000 and $1,202,000, in 1996, 1995
and 1994, respectively. In January 1997, the Partnership declared fourth quarter
1996 distributions on SFPPI's general and limited partner interests aggregating
$7,102,000, payable in February 1997. SFPPI's cumulative equity in undistributed
earnings of the Partnership was $14,081,000 as of December 31, 1996.

OTHER
SFPPI's recorded investment in the Partnership exceeds the sum of the capital
attributed to the general partner, common unitholder and minority interest in
the Partnership's financial statements by approximately $6.7 million at December
31, 1996 primarily due to the gain recognized by SFPPI on the sale of the
underwriters' over-allotment of preference units in 1989.

Prior to the formation of the Partnership in December 1988, the balance of
additional paid-in capital of SFPPI was approximately $286.6 million. As a
result of the assumption by SFPPI, prior to the formation of the Partnership, of
$350.0 million of indebtedness of Santa Fe associated with the Predecessor
Companies' pipeline business and the contribution by Santa Fe to SFPPI's capital
of a $25.0 million promissory note (see Note 3), SFPPI's additional paid-in
capital was reduced to a deficit balance of $38.4 million as of December 31,
1988 and 1989. Due to the change in the Company's consolidated capital structure
upon Holdings' 1990 acquisition of SFPPI's capital stock, which had been carried
at $5.0 million, the deficit balance of additional paid-in capital was
subsequently reduced to $33.4 million as of December 31, 1990.

NOTE 3: NOTES RECEIVABLE FROM SANTA FE PACIFIC CORPORATION

The notes receivable from Santa Fe consist of a $105 million note issued by
Santa Fe in September 1990 in exchange for a portion of the proceeds of the
Company's debenture offering (see Note 4) and a $25 million note originally
issued by Santa Fe in December 1988. The $105 million note is an unsecured
promissory note that will mature and be due and payable in full in August 2010,
upon the maturity of the Debentures, and is payable at any time prior to August
2010 to the extent, and only to the extent, that Holdings' board of directors
determines in good faith that payment is needed, after taking into account all
other available funds, for the Company to meet its obligations under the
Debentures. In June 1990, the $25 million note was exchanged for a substitute
promissory note from Santa Fe, also in the principal amount of $25 million, with
a maturity and other terms similar to those of the $105 million note. Such
promissory notes bear interest at a floating rate, payable quarterly in arrears,
equal to one percent above the monthly average effective Federal Funds rate
(6.27% in December 1996).

On September 22, 1995, as a result of Santa Fe's merger with Burlington Northern
Inc. (the "Merger"), Santa Fe became a wholly owned subsidiary of a new publicly
held company, Burlington Northern Santa Fe Corporation ("BNSF") and, in January
1997, BNSF assumed the obligations associated with the Company's $130 million of
notes receivable from Santa Fe.

The Merger was accounted for as a purchase and Santa Fe's assets and liabilities
were adjusted to their fair value based on the purchase price; purchase
accounting adjustments associated with the Company's assets and liabilities were
recorded in Santa Fe's books and records and were not reflected in (or "pushed
down to") the accompanying consolidated financial statements of the Company.
Financial information for BNSF includes Santa Fe's results of operations
subsequent to the Merger;

F-7
<PAGE>

data for periods prior to the Merger reflects only the operations of Burlington
Northern Inc. The following table sets forth selected financial data for BNSF
(in millions, except per share data):

<TABLE>
<CAPTION>
Year ended December 31,
----------------------------
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
INCOME STATEMENT DATA
Total operating revenues.............. $ 8,187 $ 6,163 $ 4,976
Total operating expenses.............. 6,439 5,637 4,123
Operating income...................... 1,748 526 853
Interest expense...................... 301 220 155
Income before income taxes............ 1,440 334 695
Income before extraordinary charge and
cumulative effect of change in 889 198 426
accounting..........................

Net income............................ $ 889 $ 92 $ 416

FULLY DILUTED EARNINGS PER COMMON SHARE
Income before extraordinary charge and
cumulative effect of change in $ 5.70 $ 1.66 $ 4.38
accounting..........................
Net income............................ 5.70 0.67 4.27

<CAPTION>
December 31,
-----------------
1996 1995
------- --------
BALANCE SHEET DATA
Total current assets.................. $ 1,331 $ 1,264
Net properties, plant and equipment... 17,633 16,001
Total assets.......................... 19,846 18,269
Total current liabilities............. 2,311 2,369
Long-term debt and commercial paper... 4,546 4,153
Deferred income taxes................. 4,729 4,233
Other long-term liabilities........... 2,279 2,477
Total liabilities..................... 13,865 13,232
Total stockholders' equity............ 5,981 5,037
</TABLE>

BNSF's consolidated financial statements as of December 31, 1996 and 1995 and
for the three years in the period ended December 31, 1996, as well as
management's discussion and analysis of financial condition and results of
operations, are filed as exhibits to this Form 10-K (see Index to Exhibits
beginning at page 12 of this Report).

F-8
<PAGE>

NOTE 4: LONG-TERM DEBT

In September 1990, Holdings issued $218,981,000 aggregate principal amount of
Variable Rate Exchangeable Debentures Due 2010 (the "Debentures"). The
Debentures bear interest at a variable rate, payable quarterly in arrears. The
Debentures are exchangeable under certain circumstances at the option of the
holders upon the first to occur of certain specified events or final maturity
for an aggregate of 8,148,130 Partnership common units presently owned by the
Company. Each $1,000 original principal amount of the Debentures is subject to
exchange for 37.2093 common units, subject to adjustment and the Company's right
to pay cash on the date of exchange in an amount equal to the market price of
the Debentures. The Company advanced $105 million of the proceeds of the
September 1990 offering to Santa Fe in exchange for an unsecured promissory
note, with a maturity and terms as described in Note 3, and used essentially all
of the remaining net proceeds of the debenture offering to pay an $86.5 million
dividend to Santa Fe.

The interest payable with respect to a debenture for a particular quarter is
equal to the greater of (i) the cash distributions declared by the Partnership
for that quarter on that number of common units for which such debenture would
then be exchangeable and (ii) 2% of the weighted average principal balance of
such debenture outstanding during that quarter (i.e., a minimum of 8% per year),
provided that in no event shall the amount of interest payable by the Company on
a debenture for any quarter exceed the amount that would, when added to the sum
of all prior interest payments made since the Debentures were issued, result in
the payment of interest at an average annual rate of 16% since the Debentures
were issued. Because the Debentures were issued with an original issue discount
equivalent to 8% of the principal amount, the minimum effective interest rate of
the Debentures will approximate 8.85% through maturity, based on the 8% per
annum minimum interest rate.

The original issue discount is being amortized on an effective interest basis
over the 20-year estimated period the Debentures will be outstanding. During
1996, 1995 and 1994, interest expense included $535,000, $490,000 and $450,000,
respectively, of amortization of the original issue discount; the balance of the
discount at December 31, 1996 was approximately $14,810,000. Debt issuance costs
are being amortized on a straight-line basis over 20 years; during each of the
years 1996, 1995 and 1994, interest expense included approximately $485,000 of
amortization of debt issuance costs.

In January 1997, the Partnership declared a cash distribution of $0.75 per
common unit for the fourth quarter of 1996; accordingly, the Company accrued
interest expense of $6,111,000 (equivalent to the distributions on the 8,148,130
units for which the Debentures would be exchangeable) as of December 31, 1996.

The Debentures are general unsecured obligations of the Company. The indenture
restricts the Company from incurring any other additional indebtedness other
than up to $5.0 million relating to temporary borrowings from Santa Fe or its
affiliates. In addition, the Company has agreed that it will not engage in any
other business activities other than as a partner of the Partnership.

The fair value of the Debentures is estimated, based on recent bid and asked
quotations, to be approximately $280 million at December 31, 1996.

F-9
<PAGE>

NOTE 5: CONTINGENT LIABILITIES

As general partner of the Partnership, SFPPI is contingently liable for the
Partnership's $355 million in long-term debt and any other Partnership
obligations in the event of default by the Partnership.

PARTNERSHIP'S EAST LINE CIVIL LITIGATION AND FERC PROCEEDINGS
Certain of the Partnership's shippers have filed civil suits and initiated
Federal Energy Regulatory Commission ("FERC") complaint proceedings alleging,
among other things, that the shippers were damaged by the Partnership's failure
to fulfill alleged promises to expand the East Line's capacity between El Paso,
Texas and Phoenix, Arizona to meet shipper demand. The FERC proceedings also
involve claims, among other things, that certain of the Partnership's rates and
charges on its East and West Lines are excessive. To date, the complainants have
filed testimony in the FERC proceeding seeking reparations for shipments between
1990 and 1994 aggregating approximately $35 million, as well as rate reductions
of between 30% and 40% for shipments in 1995 and thereafter. The remaining civil
action, brought by El Paso Refinery, L.P. ("El Paso") and its general partner,
El Paso Refining, Inc., claims unspecified actual damages, which appear to
include the $190 million cost of a refinery expansion completed in 1992, plus
punitive and consequential damages.

During 1996, the Partnership pursued settlement efforts to resolve the claims
raised in the FERC proceedings and reached agreements with El Paso regarding
its challenge of the Partnership's East Line rates and with Navajo Refining
Company ("Navajo") regarding its challenge of the Partnership's West Line rates.
The Partnership has also presented settlement offers to all of the remaining
complainants in the FERC proceedings, including Navajo with respect to the
Partnership's East Line rates. The terms of the settlement agreements with El
Paso and Navajo do not provide for rate reductions, but other offers that have
been extended do include proposed prospective reductions in the rates at issue
in the proceedings.

During the quarter ended September 30, 1996, the Partnership recorded an $8
million provision for litigation costs to increase its existing reserves to
reflect the total amount that would be payable under the settlement offers that
had been extended as of that date, including the offers that have been accepted
by El Paso and Navajo and, during the quarter ended December 31, 1996, recorded
an additional $15 million provision to increase its reserves to reflect
management's current estimate of the ultimate costs of resolution of the FERC
proceedings. Previously, during the quarter ended December 31, 1995, the
Partnership recorded a $10 million provision to increase its existing reserves
relating to the FERC proceedings, the El Paso action and certain other matters.
The Partnership's accompanying balance sheet also includes reserves for costs
related to the resolution of the El Paso civil action.

While the Partnership believes it has meritorious defenses in these matters, the
complainants and plaintiffs are seeking amounts that, in the aggregate,
substantially exceed the Partnership's reserves and, because of the
uncertainties associated with litigation and the FERC rate-making methodology,
management cannot predict with certainty the ultimate outcome of these matters.
The Partnership is also not able to predict with certainty whether settlement
agreements will be completed with some or all of the parties to the FERC
proceedings or the El Paso civil action or the final terms of any such
additional settlement agreements that may be consummated. As additional
information becomes available, it may be necessary for the Partnership to record
additional charges to earnings to maintain its reserves at a level deemed
adequate at that time, and the costs associated with the ultimate resolution of
these matters could have a material adverse effect on the Partnership's results

F-10
<PAGE>

of operations, financial condition, liquidity and ability to maintain its
quarterly cash distribution at the current level.

PARTNERSHIP ENVIRONMENTAL MATTERS
The Partnership's transportation and terminal operations are subject to
extensive regulation under federal, state and local environmental laws
concerning, among other things, the generation, handling, transportation and
disposal of hazardous materials and the Partnership is, from time to time,
subject to environmental cleanup and enforcement actions. In particular, the
federal Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA" or "Superfund" law) generally imposes joint and several liability for
cleanup and enforcement costs, without regard to fault or the legality of the
original conduct, on current or predecessor owners and operators of a site.

Along with several other respondents, the Partnership is presently involved in a
cleanup ordered by the United States Environmental Protection Agency related to
soil and groundwater contamination in the vicinity of the Partnership's storage
facilities and truck loading terminal at Sparks, Nevada. In addition, the
Partnership is presently involved in 18 groundwater hydrocarbon remediation
efforts under administrative orders issued by the California Regional Water
Quality Control Board and two other state agencies and, from time to time, may
be involved in groundwater investigations or remediations at the direction of
other governmental agencies. The Partnership is also involved in soil and
groundwater remediation projects, at and adjacent to various other terminal and
pipeline locations, that have not been mandated by government agencies but are
conducted in the ordinary course of business. In a number of remediation
projects, the Partnership is participating with other entities ranging from
large integrated petroleum companies to certain less financially sound parties.

The Partnership accrues for environmental costs that relate to existing
conditions caused by past operations. Environmental costs include initial site
surveys and environmental studies of potentially contaminated sites, costs for
remediation and restoration of sites determined to be contaminated and ongoing
monitoring costs, as well as fines, damages and other costs, when estimable. The
Partnership's environmental reserves are monitored on a regular basis by
management. Liabilities for environmental costs at a specific site are initially
recorded when the Partnership's liability for such costs is probable and a
reasonable estimate of the associated costs can be made. Adjustments to initial
estimates are recorded, from time to time, to reflect changing circumstances and
estimates based upon additional information developed in subsequent periods.
Estimates of the Partnership's ultimate liabilities associated with
environmental costs are particularly difficult to make with certainty due to the
number of variables involved, including the early stage of investigation at
certain sites, the lengthy time frames required to complete remediation at most
locations, the number of parties involved, the number of remediation
alternatives available, the uncertainty of potential recoveries from third
parties and the evolving nature of environmental laws and regulations.

During 1995 and 1996, the Partnership, as a member of a defendant group, settled
all of the claims for penalties and damages that had been asserted by several
governmental agencies and property owners in lawsuits associated with the soil
and groundwater contamination present in the vicinity of the Sparks, Nevada
environmental site. The Partnership recorded provisions for environmental costs
aggregating $24 million during 1995 largely to reflect its share of all of these
settlement costs.

F-11
<PAGE>

in the ordinary course of business, and the cost of performing preliminary
environmental investigations at several locations, as well as environmental
damage claims, primarily associated with the Sparks environmental site. With
respect to the costs accrued at December 31, 1996, the Partnership estimates
that approximately $8.5 million will be paid in 1997, approximately $2 million
to $4 million will be paid per year over the following four years, and
approximately $1 million or less will be paid per year over the subsequent five
years.

Based on the information presently available, it is the opinion of management
that the Partnership's environmental costs, to the extent they exceed recorded
liabilities, will not have a material adverse effect on the Partnership's
financial condition, liquidity or ability to maintain its quarterly cash
distribution at the current level; nevertheless, it is possible that the
Partnership's results of operations in particular quarterly or annual periods
could be materially affected as additional information becomes available.

OTHER CLAIMS AND LITIGATION
The Company and the Partnership are also parties to a number of other legal
actions arising in the ordinary course of business. While the final outcome of
these other matters cannot be predicted with certainty, it is the opinion of
management that none of these other legal actions, either individually or in the
aggregate, when finally resolved, will have a material adverse effect on the
annual results of operations, financial condition or liquidity of the Company or
the Partnership, or on the Partnership's ability to maintain its quarterly cash
distribution at the current level.

LEASE COMMITMENTS
The Partnership and the General Partner lease space in office buildings and
certain computer equipment. Total lease commitments not subject to cancellation
at December 31, 1996 are as follows: $1,215,000 in 1997, $1,105,000 in 1998,
$1,215,000 in 1999, $1,225,000 in 2000, $1,365,000 in 2001 and $16,700,000
thereafter.

The Partnership also leases certain rights-of-way and land under agreements that
can be canceled at any time should they not be required for operations. The
annual payments associated with these leases aggregated approximately $5 million
in 1993, however a substantial portion of this amount became subject to
renegotiation effective January 1, 1994 and the Partnership and the lessor were
unable to reach an agreement on a new base annual rental payment for the next
ten-year period. In the years 1994 through 1996, the Partnership accrued for an
increase in the annual rental for these rights-of-way. In January 1997, a
tentative decision was rendered in the judicial reference proceeding held to
resolve this matter. This tentative decision would establish the new base annual
rental for these rights-of-way at a level, subject to inflation adjustments,
that is adequately provided for by the amounts that had been accrued through
December 31, 1996. Rental expense recorded for all operating leases was
$8,975,000 in 1996, $8,850,000 in 1995 and $8,335,000 in 1994.

NOTE 6: RELATED PARTY TRANSACTIONS AND POSTRETIREMENT PLANS

The Partnership is managed by the General Partner. Under certain partnership and
management agreements, the General Partner, Santa Fe and BNSF are entitled to
reimbursement of direct and indirect costs related to the business activities of
the Partnership. These costs, which totaled $50.4 million, $45.8 million and
$40.6 million in 1996, 1995 and 1994, respectively, include compensation and
benefits payable to officers and employees of the General Partner, payroll
taxes, corporate office building rentals, general and administrative costs, tax
information and reporting costs

F-12
<PAGE>

and legal and other professional service fees. Such reimbursed expenses are not
reflected as expenses of the General Partner or the Company in the accompanying
financial statements.

The Company is included with certain other affiliates in the Burlington Northern
Santa Fe Retirement Plan, a noncontributory defined benefit pension plan
established October 1, 1996 (the "Plan") to effect the consolidation of the
Santa Fe Pacific Retirement Plan and the Burlington Northern Inc. Pension Plan.
The Plan covers substantially all officers and employees of BNSF and its
subsidiaries not covered by collective bargaining agreements. Benefits payable
under the Plan are based on years of credited service and the highest five-year
average compensation levels. BNSF's funding policy is to contribute annually at
a rate not less than the regulatory minimum, and not more than the maximum
amount deductible for income tax purposes. Since the Company is included with
certain other affiliates, detailed Plan information is not available in all
cases; however, as of September 30, 1996, the fair value of Plan assets
allocated to employees associated with the Partnership's operations was $57.4
million, and the actuarial present value of projected Plan obligations,
discounted at 7.75%, was $49.5 million. The expected return on the market value
of Plan assets was 9.5% and compensation levels were assumed to increase at 4.0%
per year. The Plan assets and obligations associated with former employees of
prior affiliates of SFPPI have been assumed by BNSF.

Salaried employees who have rendered ten years of service after attaining age 45
are eligible for both medical benefits and life insurance coverage during
retirement. The retiree medical plan is contributory and provides benefits to
retirees, their covered dependents and beneficiaries. Retiree contributions are
adjusted annually. The plan also contains fixed deductibles, coinsurance and
out-of-pocket limitations. The life insurance plan is non-contributory and
covers retirees only.

The Company's net periodic postretirement benefit cost for approximately 30
former employees of prior affiliates of SFPPI, which was entirely interest cost,
was approximately $95,000 in 1996, $105,000 in 1995 and $130,000 in 1994. The
Company's accumulated postretirement benefit obligation for these former
employees was approximately $1,860,000 at December 31, 1996 and 1995.

The Company's policy is to fund benefits payable under the medical and life
insurance plans as they come due. For employees associated with the
Partnership's operations, the following table shows the reconciliation of the
plans' obligations to amounts accrued at December 31, 1996 and 1995:
<TABLE>
<CAPTION>

Medical Plan Life Insurance Plan
-------------------- -------------------
(In thousands) 1996 1995 1996 1995
--------- -------- ------- --------
<S> <C> <C> <C> <C>
Accumulated postretirement
benefit obligation:
Retirees.............................. $ 3,435 $ 4,325 $2,205 $2,330
Fully eligible active plan 1,365 1,040 30 30
participants.........................
Other active plan participants........ 5,030 5,460 665 600
--------- -------- ------- --------
9,830 10,825 2,900 2,960

Unrecognized prior service credit....... 3,255 3,750 -- --
Unrecognized net gain (loss)............ 2,260 675 (525) (680)
--------- -------- ------- --------
Accrued postretirement liability........ $15,345 $15,250 $2,375 $2,280
========= ======== ======= ========
</TABLE>

The unrecognized prior service credit will be amortized straight-line over the
average future service to full eligibility of the active population. For 1996,
the assumed health care cost trend rate for managed

F-13
<PAGE>

care medical costs is 10.5% and is assumed to decrease gradually to 5% by 2006
and remain constant thereafter. For medical costs not in managed care, the
assumed health care cost trend is 12% in 1996 and is assumed to decrease
gradually to 5% by 2006 and remain constant thereafter. The health care cost
trend rate assumption has a significant effect on the amounts reported. For
example, for the Partnership, increasing the assumed health care cost trend
rates by one percentage point in each year would increase the accumulated
postretirement benefit obligation for the medical plan by $1.4 million and the
combined service and interest components of net periodic postretirement benefit
cost recognized in 1996 by $225,000. For the Company, a similar increase in the
assumed health care cost trend rates would increase the accumulated obligation
and the 1996 periodic cost by approximately $20,000 and $10,000, respectively.
For 1996, the weighted-average discount rate assumed in determining the
accumulated postretirement benefit obligation was 7.75% and the assumed
weighted-average salary increase was 4.0%.

Note 7: INCOME TAXES

The provision for income taxes consisted of the following:
<TABLE>
<CAPTION>
Year ended December 31,
---------------------------
1996 1995 1994
------- -------- -------
<S> <C> <C> <C>
(In thousands)
Current:
Federal.................. $ 7,549 $ 4,700 $ 6,928
State.................... 1,763 937 1,586
------- ------- -------
Total current provision.. 9,312 5,637 8,514
Deferred:
Federal.................. (4,859) (3,767) (1,234)
State.................... (1,014) (801) (18)
------- ------- -------
Total deferred benefit... (5,873) (4,568) (1,252)
------- ------- -------
Total provision.......... $ 3,439 $ 1,069 $ 7,262
======= ======= =======
</TABLE>

Total income taxes as reflected in the Company's statement of operations differs
from the amounts computed by applying the statutory federal corporate tax rate
to income before income taxes as follows:
<TABLE>
<CAPTION>
Year ended December 31,
---------------------------------------------------------------
1996 1995 1994
------------------- -------------------- ---------------------
<S> <C> <C> <C>
(Dollars in thousands)
Federal income tax
at statutory rates............ $ 2,758 35.0% $ 907 35.0% $6,129 35.0%
Increase in taxes
resulting from:
State income taxes,
net of federal benefit..... 487 6.2 88 3.4 1,019 5.8%
Other....................... 194 2.4 74 2.9 114 0.7
-------- ---- ------ ---- ------ ----
Total provision for
income taxes................. $ 3,439 43.6% $1,069 41.3% $7,262 41.5%
======== ==== ====== ==== ====== ====
</TABLE>

F-14
<PAGE>

Deferred income taxes are determined based on temporary differences between the
financial reporting and tax basis of the Company's assets and liabilities, using
enacted tax rates in effect during the years in which the differences are
expected to reverse. Principal temporary differences that gave rise to the net
deferred tax liability are largely attributable to differences between the
financial reporting and tax basis of Partnership properties acquired from the
Predecessor Companies and may be summarized as follows:
<TABLE>
<CAPTION>

December 31,
------------------
1996 1995
-------- --------
<S> <C> <C>
(In thousands)
Deferred tax debits:
Postretirement and postemployment
benefit accruals.................... $ 4,104 $ 4,012
Partnership environmental
remediation provision............... 4,250 5,463
Partnership litigation provision..... 7,367 3,436
Other................................ 4,244 3,998
------- -------
19,965 16,909
------- -------
Deferred tax credits:
Remaining cost basis differences of
depreciable assets.................. (67,914) (70,049)
Other differences in cost basis...... (6,160) (7,178)
Other................................ (3,933) (3,597)
------- -------
(78,007) (80,824)
------- -------
Net deferred tax liability............ $(58,042) $(63,915)
======= ========
</TABLE>

Prior to September 22, 1995, the Company was included in the consolidated
federal income tax return filed by its parent, Santa Fe. Subsequent to the
September 22, 1995 merger discussed in Note 3, the Company is included in the
consolidated federal income tax return of BNSF. The provision for federal income
taxes reflected in these financial statements is based on the amount the Company
would have been required to pay if it filed a separate return. Pursuant to a tax
agreement between Santa Fe and its subsidiaries, the Company has agreed to pay
to Santa Fe an amount based on the federal income tax liability it would have
paid if it filed a separate return, regardless of whether Santa Fe or BNSF, as a
whole, have any current federal tax liability. In determining amounts payable to
Santa Fe, the Company may only take into account its own carryforwards of losses
and credits to reduce amounts it would otherwise owe. Accordingly, there are
circumstances in which the Company may receive no compensation for the current
use of carryforwards of losses or credits by other members of the Santa Fe or
BNSF consolidated groups. Similarly, pursuant to agreements for the allocation
of the combined tax liability among the members of the Santa Fe affiliated group
for the state income, franchise or excise tax (as applicable) of Arizona,
California, New Mexico and Oregon, the Company has agreed to pay to Santa Fe an
amount approximating the state tax liability it would have paid if it filed
separate returns in these states.

F-15
<PAGE>

NOTE 8: QUARTERLY RESULTS (UNAUDITED)

Quarterly results of operations are summarized below:
<TABLE>
<CAPTION>

First Second Third Fourth
(In thousands) Quarter Quarter Quarter Quarter
------- ------- ------- --------
<S> <C> <C> <C> <C>
1996
Operating revenues........ $7,385 $9,479 $5,536 $ 2,589
Operating income.......... 7,217 9,348 5,559 2,388
Net income (loss)......... 1,808 3,064 831 (1,260)

1995
Operating revenues........ $6,999 $5,892 $8,450 ($2,045)
Operating income (loss)... 6,699 5,682 8,305 (2,174)
Net income (loss)......... 1,697 903 2,530 (3,609)
</TABLE>

Note: The Partnership recorded provisions for environmental and litigation
costs aggregating $8 million and $15 million in the third and fourth quarters
of 1996, respectively, and $9 million and $25 million in the second and fourth
quarters of 1995, respectively.

F-16

<PAGE>

================================================================================

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, 1996

OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NUMBER 1-10066
--------------------------------------------

SANTA FE PACIFIC PIPELINE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

DELAWARE 95-4191066
(State of incorporation) (I.R.S. Employer Identification No.)

1100 TOWN & COUNTRY ROAD
ORANGE, CALIFORNIA 92868
(Address of principal executive offices, including zip code)
(714) 560-4400
(Registrant's telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Name of each
Title of each class exchange on which registered
------------------- ----------------------------
COMMON DEPOSITARY UNITS NEW YORK STOCK EXCHANGE

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

--------------------------------------------

The aggregate market value of the Common Depositary Units held by non-affiliates
of the registrant as of March 21, 1997 was approximately $425 million.

===============================================================================
<PAGE>

TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PART I
Items 1 and 2. Business and Properties.................................... 1
General............................................................. 1
Markets............................................................. 2
Principal Customers................................................. 3
Capital Expenditures................................................ 3
Description of the Pipeline System.................................. 4
Description of the Truck Loading Terminals.......................... 5
Maintenance......................................................... 5
Competition and Business Considerations............................. 6
Regulation.......................................................... 7
Employees........................................................... 8
Item 3. Legal Proceedings.................................................. 8
Item 4. Submission of Matters to a Vote of Security Holders................ 13

PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters.......................................................... 14
Item 6. Selected Financial Data............................................ 14
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations................... 15
Item 8. Financial Statements and Supplementary Data........................ 21
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure............................. 21

PART III
Item 10. Directors and Executive Officers of the Registrant................ 21
Item 11. Executive Compensation............................................ 23
Item 12. Security Ownership of Certain Beneficial Owners and Management.... 23
Item 13. Certain Relationships and Related Transactions.................... 23

PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.. 24
Signatures................................................................. 26
</TABLE>
<PAGE>

SANTA FE PACIFIC PIPELINE PARTNERS, L.P.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES.

GENERAL
Santa Fe Pacific Pipeline Partners, L.P. (the "Registrant") is a Delaware
limited partnership formed in 1988 to acquire and operate, through SFPP, L.P.,
formerly Southern Pacific Pipe Lines Partnership, L.P. (the "Operating
Partnership"), the refined petroleum products pipeline business of Santa Fe
Pacific Corporation ("Santa Fe"). The Registrant and the Operating Partnership
are collectively referred to as the "Partnership".

Santa Fe Pacific Pipelines, Inc. (the "General Partner") is the sole general
partner of the Partnership. It owns a 1% general partnership interest in the
Registrant and also owns a 1% general partnership interest in the Operating
Partnership and manages the operations of both partnerships. The General Partner
also owns 8,148,148 common depositary units ("common units"), representing a
41.7% interest, in the Registrant. The General Partner is a wholly owned
subsidiary of SFP Pipeline Holdings, Inc., which is in turn a wholly owned
subsidiary of Santa Fe. In September 1995, Santa Fe and Burlington Northern Inc.
consummated a business combination pursuant to which Santa Fe became a
subsidiary of a new publicly-held company, Burlington Northern Santa Fe
Corporation ("BNSF"). 11,000,000 common units, representing 56.3% of the total
interests in the Partnership, are publicly held and are traded on the New York
Stock Exchange under the symbol "SFL".

The Partnership transports products via pipeline, including gasoline, diesel
fuel and commercial and military jet fuel, primarily for major petroleum
companies, independent refiners, the United States military, and marketers and
distributors of such products. The Partnership also operates 14 truck loading
terminals and provides pipeline service to 40 customer-owned terminals, three
commercial airports, and 11 military bases. The Partnership's pipelines
(collectively, the "Pipeline System") are: (1) the South Line, which is composed
of two segments, the West Line, which transports products from Los Angeles to
Phoenix and Tucson, Arizona and various intermediate points, and the East Line,
which transports products from El Paso, Texas to Tucson, Phoenix and various
intermediate points; (2) the North Line, which transports products primarily
from the San Francisco Bay area to various cities in northern California and
western Nevada; (3) the Oregon Line, which transports products between Portland
and Eugene, Oregon, and one intermediate point; and (4) the San Diego Line,
which transports products from Los Angeles to San Diego, California and various
intermediate points. Substantially all of the Pipeline System's transportation
services constitute common carrier operations that are subject to federal or
state tariff regulation.

-1-
<PAGE>

The following table reflects the total volumes and barrel miles of products
delivered by the Pipeline System for each of the years indicated:

Total Volumes and Barrel Miles Transported (a)
---------------------------------------------------------------------------------------
1996 1995 1994
------------------------- -------------------------- --------------------------
Barrel Barrel Barrel
Volume Miles Volume Miles Volume Miles
----------- ---------- ----------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
South Line
West Line (b)......... 124.4 23,829 121.7 23,439 118.9 22,151
East Line............. 27.0 9,287 24.5 8,320 25.3 8,819
North Line................ 161.6 13,068 155.4 12,709 152.3 12,545
Oregon Line............... 13.7 1,541 13.6 1,529 13.6 1,525
San Diego Line (b)........ 38.7 4,102 39.1 4,013 39.7 4,030
=========== ========== =========== ========== =========== ===========
Total................. 365.4 51,827 354.3 50,010 349.8 49,070
=========== ========== =========== ========== =========== ===========
</TABLE>

(a) Volumes are expressed in millions of barrels of products and barrel
miles are shown in millions. A barrel mile is the movement of a barrel
of product for a distance of one mile.

(b) Product volumes delivered through the West Line to the San Diego Line
are in turn delivered through the San Diego Line to the shipper's
ultimate destination for such volumes. This table reflects such
volumes only in the San Diego Line, from which ultimate delivery is
made.

Although the mix of the products transported varies among the pipeline
segments constituting the Pipeline System, such variation is not
substantial. Tariffs charged for transportation do not vary for
different product types. The following table sets forth the volumes of
gasoline, jet fuels and diesel fuel transported by the Pipeline System
during the years indicated (in millions of barrels):

<TABLE>
<CAPTION>
Volumes Delivered by Product Type
---------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Gasoline.................... 229.3 222.7 225.5
Diesel fuel................. 72.7 70.7 67.3
Jet fuels................... 63.4 60.9 57.0
-------- -------- --------
Total................. 365.4 354.3 349.8
======== ======== ========
</TABLE>

MARKETS
The Partnership currently serves approximately 65 shippers in the refined
products market, with the largest customers consisting of major petroleum
companies, independent refiners, the United States military, and independent
marketers and distributors of products. The volume of products transported in
the Pipeline System is directly affected by the level of end-user demand for
such products in the geographic regions served by the Partnership. Such market
demand varies based upon the different end uses to which the products delivered
through the Pipeline System may be applied. A substantial portion of product
volumes transported in the Pipeline System is gasoline, the demand for which is
dependent on such factors as prevailing economic conditions and demographic
changes in the markets served by the Pipeline System and, to a lesser degree,
gasoline prices. Portions of the Partnership's business can experience seasonal
variations; however, overall volumes are only moderately seasonal, with lower
than average volumes typically being transported during the first and fourth
quarters of each year.

-2-
<PAGE>

PRINCIPAL CUSTOMERS
Of the approximately 65 shippers served by the Partnership on a system-wide
basis in 1996, the largest shippers on each of the pipeline segments were
generally the same entities. The chart below reflects the percentage of
transportation revenues attributable to the top 10 shippers on the South Line,
North Line, Oregon Line and San Diego Line during each of the periods indicated,
based upon total product volumes shipped during the years indicated.

<TABLE>
<CAPTION>
Revenue Percentage
Attributable to Top 10 Shippers
-------------------------------
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
South Line
West Line............ 84% 85% 84%
East Line............ 99 98 95
North Line............... 85 82 80
Oregon Line.............. 99 100 99
San Diego Line........... 93 92 92
</TABLE>

Between 73% and 74% of the refined petroleum products transported in the
Pipeline System during each of the calendar years 1994 through 1996 were shipped
by major petroleum companies. Operating revenues received from ARCO Products
Company and Chevron U.S.A. Products Company accounted for 14.8% and 12.1%,
respectively, of total 1996 revenues. These two customers accounted for 16.3%
and 13.3%, respectively, of total 1995 revenues, and for 16.1% and 12.4%,
respectively, of total 1994 revenues.

Products delivered to military facilities accounted for 4.0%, 4.5% and 4.8% of
total volumes shipped by the Partnership during 1996, 1995 and 1994,
respectively. Military volumes are dependent on the level of activity at
military bases served by the Pipeline System. Since 1991, the United States
Congress has approved plans to reduce the overall level of military activity. As
of year end 1996, several military bases historically served by the Partnership
had been closed and realignment of certain other bases continues to occur, with
the level of activity having decreased at certain bases and increased at others.
No other bases served by the Partnership have been identified for closure or
realignment. In January 1996, the Partnership acquired a pipeline serving
Lemoore Naval Air Station, near Fresno, California.

CAPITAL EXPENDITURES
For the year ended December 31, 1996, Partnership capital expenditures
aggregated $27.7 million, of which approximately $12 million was used for income
enhancing projects, and the balance for sustaining projects. The planned 1997
capital program aggregates approximately $28 million, of which approximately $12
million is planned for income enhancing projects. The Partnership presently
anticipates that ongoing capital expenditures will average approximately $30
million per year over the next five years. This amount could increase or
decrease as the result of changing regulatory requirements or business
opportunities. (See also Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources.)

-3-
<PAGE>

DESCRIPTION OF THE PIPELINE SYSTEM

The SOUTH LINE consists of two pipeline segments, the West Line and the East
Line:

The WEST LINE consists of approximately 555 miles of primary pipeline and
currently transports products for approximately 50 shippers from seven
refineries and three pipeline terminals in the Los Angeles Basin to Phoenix and
Tucson, Arizona and various intermediate commercial and military delivery
points. In 1996, 1995 and 1994, the West Line transported averages of 339,900,
333,400 and 325,600 barrels per day, respectively, of which averages of 114,100,
111,700 and 104,000 barrels per day, respectively, were delivered to Phoenix and
Tucson. Also, a significant portion of West Line volumes are transported to
Colton, California for local distribution and for delivery to Calnev Pipeline,
an unaffiliated common carrier of refined petroleum products to Las Vegas,
Nevada and intermediate points. The West Line serves Partnership terminals
located in Colton and Imperial, California as well as in Phoenix and Tucson.

The EAST LINE is comprised of two parallel lines originating in El Paso, Texas
and continuing approximately 300 miles west to the Tucson terminal and one line
continuing northwest approximately 130 miles from Tucson to Phoenix. All
products received by the East Line at El Paso come from [one] refinery in El
Paso or are delivered through connections with non-affiliated pipelines from
refineries in Odessa and Dumas, Texas and Artesia, New Mexico. The East Line
transports refined petroleum products for approximately 17 shippers. In 1996,
1995 and 1994, the East Line transported averages of 73,700, 67,200 and 69,300
barrels per day, respectively, of refined petroleum products, of which averages
of 35,800, 31,500 and 34,100 barrels per day, respectively, were delivered to
Phoenix. Since August 1992, when the second phase of the East Line expansion
became operational, the daily pumping capacity between El Paso and Tucson has
been approximately 95,000 barrels, and the daily pumping capacity from Tucson to
Phoenix has been approximately 55,000 barrels. The East Line serves the
Partnership's terminals located in Tucson and Phoenix.

In late 1995, Diamond Shamrock, Inc. completed construction of a new 10-inch
diameter products pipeline from its refinery near Dumas, Texas to El Paso. In
late 1996, Diamond Shamrock connected this pipeline to the Partnership's East
Line and began shipping products to Tucson and Phoenix.

Longhorn Partners Pipeline is a proposed joint venture project which would
acquire and convert an existing crude oil pipeline to refined products service
and construct a new pipeline extension to transport refined products from
refineries on the Gulf Coast to El Paso and other destinations in Texas.

Increased product supply in the El Paso area could result in some shift of
volumes transported into Arizona from the Partnership's West Line to its East
Line. While increased movements into the Arizona market from El Paso displace
higher tariff volumes supplied from Los Angeles on the West Line, such shift of
supply sourcing has not had, and is not expected to have, a material effect on
the Partnership's results of operations.

The NORTH LINE of the Pipeline System consists of approximately 1,075 miles of
pipeline in six pipeline segments originating in Richmond, Concord and
Bakersfield, California. This line serves Partnership terminals located in
Brisbane, Bradshaw, Chico, Fresno and San Jose, California, and Sparks, Nevada.
The North Line delivers refined petroleum products for approximately 40
shippers. A substantial portion of the products delivered through the North Line
comes from refineries in the San Francisco Bay area. A small percentage of
supply is received from various pipeline and marine terminals that deliver
products from foreign and domestic ports. Substantially all of the products
shipped through the Bakersfield-Fresno segment of the North Line are supplied by
a refinery located in Bakersfield.

-4-
<PAGE>

The OREGON LINE is a 114-mile pipeline serving approximately 10 shippers. The
Oregon Line receives products from marine terminals in Portland and from Olympic
Pipeline, a non-affiliated carrier, which transports products from the Puget
Sound area to Portland. From its origination point in Portland, the Oregon Line
extends south and serves Partnership terminals located in Albany and Eugene,
Oregon.

The SAN DIEGO LINE is a 135-mile pipeline serving major population areas in
Orange County (immediately south of Los Angeles) and San Diego. Approximately 20
shippers transport products on this line, supplied by the same refineries and
terminals that supply the West Line. The San Diego Line originates from the
pumping station at Norwalk, California on the West Line and extends south to
serve Partnership terminals in the cities of Orange and San Diego.

DESCRIPTION OF THE TRUCK LOADING TERMINALS
The Partnership's operations include 14 truck loading terminals with an
aggregate usable tankage capacity of approximately 8.2 million barrels.
Terminals are located at destination points on each of the lines as well as at
certain intermediate points along each line where deliveries are made. These
terminals furnish short-term product storage, truck loading and ancillary
services, such as vapor recovery, additive injection, oxygenate blending, and
quality control. The truck loading capacity of the terminals ranges from two to
12 trucks at a time. Between 128 million and 129 million barrels of products
were delivered to commercial customers at such terminals during each of the past
three years, resulting in Partnership storage and terminaling revenues of $35.0
million, $34.3 million and $33.8 million during the years 1996, 1995 and 1994,
respectively.

Capacity of the Partnership's terminaling facilities varies throughout the
Pipeline System. The Partnership does not own terminal facilities at all
pipeline delivery locations. At certain locations, product deliveries are made
to facilities owned by shippers or independent terminal operators.

Truck loading and other terminal services are provided by the Partnership as an
additional service, and a separate fee (in addition to transportation tariffs)
is charged. Rates charged for terminaling services are not economically
regulated by the Federal Energy Regulatory Commission ("FERC") or any state
agency.

MAINTENANCE
Routine preventive maintenance is performed to prolong the useful life of the
Pipeline System and terminals. Such maintenance includes cathodic protection to
prevent corrosion, periodic internal pipeline inspections and, when required,
pipeline reconditioning. In addition, the Pipeline System's rights-of-way are
patrolled at regular intervals to identify excavation or other activities by
third parties which, if left unchecked, could result in damage to the pipeline.

A computer-based pipeline monitoring system ("SCADA") continuously monitors
pipeline operating conditions, including pressures, temperatures, pumping rates
and equipment configuration, on a real-time basis. In addition to providing
remote monitoring and control of certain operating equipment, SCADA
automatically alerts operating personnel, who are on duty on a 24-hour basis, if
changes in flow conditions require attention. Use of this information by
operating personnel allows them to respond quickly to system problems.

-5-
<PAGE>

COMPETITION AND BUSINESS CONSIDERATIONS
The Partnership conducts its operations without the benefit of exclusive
franchises from government entities. In addition, the Partnership provides
common carrier transportation services through the Pipeline System at posted
tariffs, and, in virtually all cases, without long-term contracts for
transportation service with its customers. Demand for the Partnership's
transportation services is principally a function of product consumption and
competition in markets served by the Pipeline System. Product consumption is
primarily a function of prevailing economic and demographic conditions, and, to
a lesser extent, product prices paid by end users, while the Partnership's
market share within competitive markets is primarily a function of the
availability and attractiveness (in terms of cost and service) of alternate
modes of transportation, alternate product sources, service capabilities and
pricing.

Utilization of and demand for the Partnership's terminaling services varies
widely throughout the Pipeline System. Certain of the major petroleum companies
as well as independent terminal operators are presently in direct competition
with the Partnership at several terminal locations. At those locations, market
share is primarily a function of pricing, service capabilities and available
tankage.

Because pipelines are generally the lowest cost method for intermediate and
long-haul overland product movement, the Pipeline System's most significant
competitors are proprietary pipelines owned and operated by major oil companies
in the areas where the Pipeline System delivers products, refineries within the
Partnership's market areas and related trucking arrangements. The Partnership
believes that high capital costs, tariff regulation and environmental permitting
considerations make it unlikely that a competing pipeline system comparable in
size and scope to the Pipeline System will be built in the foreseeable future,
provided that the Pipeline System has available capacity to satisfy demand and
its tariffs remain at reasonable levels. However, the possibility of pipelines
being constructed to serve specific markets is a continuing competitive factor.
Trucks may competitively deliver products in certain markets and, in 1996, the
Partnership continued to experience minor but notable reductions in product
volumes delivered to certain shorter-haul destinations, primarily Orange and
Colton, California, due to increased utilization of trucking by major oil
companies. Management cannot predict with certainty whether this trend towards
increased short-haul trucking will continue in the future.

For more than ten years, an entrepreneur, either individually or associated with
Maricopa Refining Co. ("Maricopa"), has attempted to gain investor support for a
petroleum products refinery in the Phoenix area. Because of the perceived risk
of this venture, and the large investment required, this project has not been
undertaken to date. In late 1996, Maricopa Refining announced that it is in the
process of arranging financing to build a 55,000 barrel per day refinery
approximately 30 miles outside Phoenix. It is unknown as to whether Maricopa has
secured, or can secure, crude oil supply and product sales agreements necessary
to support such financing. Maricopa has announced that it has obtained all
necessary permits and, assuming financing is completed in the first quarter of
1997, that the refinery could be operational by late 1999. Should such a
refinery be constructed, the Partnership's throughput on the South Line would be
negatively affected. It is possible that a portion of any revenue reduction
could be recovered through rate increases.

-6-
<PAGE>

REGULATION

TARIFF REGULATION
Substantially all of the Partnership's pipeline operations are common carrier
operations that are subject to federal or state rate regulation.

The Partnership's interstate common carrier pipeline operations are subject to
rate regulation by the Federal Energy Regulatory Commission ("FERC") under the
Interstate Commerce Act which requires, among other things, that petroleum
product pipeline rates be "just and reasonable" and nondiscriminatory. In
general, the FERC has evaluated the justness and reasonableness of petroleum
product pipeline rates under a "cost of service" approach that permits a
pipeline to establish its tariffs, based on projected volumes, at levels
sufficient to recover its cost of service. Under this approach, a pipeline's
cost of service includes the following components: (a) operating expenses, (b)
depreciation and amortization, (c) federal and state income taxes and (d) an
overall allowed rate of return on the pipeline's "rate base." Generally, rate
base is a measure of the investment in, and value of, the common carrier assets
of a petroleum products pipeline.

The TOC methodology is subject to clarification and reconsideration in
individual cases and leaves many issues, including the appropriate rate of
return, for determination on a case-by-case basis. Alternatively, pipelines that
can demonstrate that they operate in competitive markets may be allowed to
establish tariffs under a less stringent form of "light-handed" rate regulation.
Pipelines may also be allowed to increase, or required to decrease, their
interstate rates in accordance with an inflation index (the Producer Price Index
for Finished Goods minus one percent) published annually by the FERC.

Intrastate common carrier operations of the Pipeline System in California are
subject to regulation by the California Public Utilities Commission ("CPUC")
under a "depreciated book plant" methodology, which is based on an original cost
measure of investment. Intrastate tariffs filed by the Partnership with the CPUC
have been established on the basis of revenues, expenses and investments
allocated as applicable to the intrastate portion of the Partnership's business.
In this regard, the operations of the San Diego Line are wholly intrastate and
the operations of certain portions of the North and South Lines are intrastate.

Tariff rates with respect to intrastate pipeline service in California are
subject to challenge by complaint by interested parties or by independent action
of the CPUC. A variety of factors can affect the rates of return permitted by
the CPUC and certain other issues similar to those which have arisen with
respect to the Partnership's FERC regulated rates could also arise with respect
to the Partnership's intrastate rates.

-7-
<PAGE>

(See also Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Other Matters - Rate Regulation.)

ENVIRONMENTAL AND SAFETY REGULATION
The Partnership's operations are subject to federal, state and local laws and
regulations relating to protection of the environment, including laws and
regulations relating to water, air, solid waste and hazardous substances. The
discharge of, or contamination of property by, hazardous materials may arise
from transportation and storage of such materials in the Pipeline System. The
normal operations of the Pipeline System expose the Partnership to claims and
potential liability for injuries to employees, other persons, property and the
environment. (See also Item 3. Legal Proceedings and Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations - Other
Matters - Environmental Matters.) The Partnership's operations are also subject
to operating and safety regulation by the Department of Transportation and
various other federal, state and local agencies.

EMPLOYEES
The Partnership does not have any employees, officers or directors. The General
Partner is responsible for management and operation of the Partnership. As of
December 31, 1996, regular, full-time employees of the General Partner numbered
435.

ITEM 3. LEGAL PROCEEDINGS.

EAST LINE CIVIL LITIGATION AND FERC PROCEEDINGS
In August 1992, two East Line refiners, Navajo Refining Company ("Navajo") and
El Paso Refinery, L.P. ("El Paso"), filed separate, though similar, civil
lawsuits (the "East Line Civil Litigation") against the Partnership arising from
the Partnership's alleged failure to provide additional pipeline capacity from
El Paso, Texas to Tucson and Phoenix, Arizona. In addition, El Paso filed a
protest/complaint with the FERC in September 1992 seeking to block the reversal
of the direction of flow of the six-inch pipeline between Phoenix and Tucson and
challenging the Partnership's proration policy, as well as the Partnership's
existing East Line rates (the "FERC Proceeding").

EAST LINE CIVIL LITIGATION
- --------------------------
The civil actions brought by Navajo and El Paso (El Paso Refining, Inc., and El
Paso Refinery, L.P. v. Santa Fe Pacific Pipelines, Inc. and Santa Fe Pacific
Pipeline Partners, L.P., No. 92-9144, County Court No. 5, El Paso County, filed
August 1992) were filed in New Mexico and Texas, respectively, seeking actual,
punitive and consequential damages alleged to have been caused by the
Partnership's failure to provide additional pipeline capacity from El Paso to
Tucson and Phoenix. Generally, the lawsuits allege that the refiners proceeded
with significant refinery expansions under the belief that the Partnership would
provide additional pipeline capacity to transport their product into Arizona,
and that they were damaged by their inability to ship additional volumes into
that highly competitive market when the Partnership did not provide such
additional capacity. The belief of Navajo and El Paso was purportedly based on
alleged oral representations made by General Partner personnel and from language
contained in a January 1989 settlement agreement with Navajo, relating to a 1985
FERC rate case.

-8-
<PAGE>

El Paso and Phoenix if certain events related to volume levels and proration of
pipeline capacity should occur within five years of the date of the agreement.

On February 25, 1997, the Partnership entered into an agreement with the El Paso
bankruptcy trustee which, subject to the approval of the bankruptcy court, would
settle El Paso's and EPRI's claims in these civil matters in exchange for the
payment of $16 million by the Partnership in two equal installments. This
proposed settlement was submitted to the bankruptcy court overseeing the estates
of El Paso and EPRI for approval on March 18, 1997.

-9-
<PAGE>

several respects to those presented by the complainants. In subsequent filings,
the complainants revised their requested relief to seek reparations for
shipments between 1990 and 1994 aggregating approximately $35 million, as well
as rate reductions of between 30% and 40% for shipments in 1995 and thereafter.

The Energy Policy Act of 1992 ("EPACT") provided that existing oil pipeline
rates that were in effect without challenge for 365 days prior to the bill's
enactment in October 1992 are deemed to be "just and reasonable," with an
exception being allowed for parties, such as Navajo, that were prohibited from
filing challenges during that period due to the terms of settlement agreements.
In October 1993, with respect to Chevron's complaint, the FERC ruled that the
Partnership's West Line rates are deemed "just and reasonable" under EPACT
(i.e., are "grandfathered") and may only be challenged upon a showing of a
substantial change in the economic circumstances which were the basis for the
rate ("changed circumstances"). In December 1994, ARCO, Texaco and Chevron filed
testimony in which they sought to demonstrate the required "changed
circumstances" in order to challenge the Partnership's West Line rates, citing
such factors as increased West Line volumes. In April 1995, the United States
Court of Appeals for the District of Columbia Circuit dismissed petitions for
review of the FERC's grandfathering rulings that had been filed by ARCO and
Texaco, on the grounds that the FERC rulings are not yet final orders and,
therefore, are not yet subject to judicial review.

-10-
<PAGE>

In December 1995, Texaco filed an additional FERC complaint, which involves the
question of whether a tariff filing is required for movements on certain of the
Partnership's lines upstream of its Watson, California station origin point and,
if so, whether those rates may be set in this proceeding and what those rates
should be. Texaco's initial complaint was followed by several other West Line
shippers filing similar complaints and/or motions to intervene, all of which
have been consolidated into Docket Nos. 96-2-000 et al. Hearings before an
-----
Administrative Law Judge were held in December 1996 and the parties completed
the filing of final post-hearing briefs on January 31, 1997. An initial decision
is expected during 1997.

ENVIRONMENTAL MATTERS
The Partnership is subject to environmental cleanup and enforcement actions from
time to time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA" or "Superfund" law) generally imposes
joint and several liability for cleanup and enforcement costs, without regard to
fault or the legality of the original conduct, on current or predecessor owners
and operators of a site.

-11-
<PAGE>

Sparks, Nevada. The EPA approved the respondents' remediation plan in September
1992 and the remediation system began operations in September 1995. In addition,
the Partnership is presently involved in 18 ground water hydrocarbon remediation
efforts under administrative orders issued by the California Regional Water
Quality Control Board and two other state agencies.

The investigation and remediation at and adjacent to the Partnership's storage
facilities and truck loading terminal in Sparks, Nevada was also the subject of
a lawsuit brought against the Partnership and other terminal operators in
January 1991 entitled Nevada Division of Environmental Protection v. Santa Fe
Pacific Pipelines, Inc. et al., Case No. CV91-546, in the Second Judicial
-----
District Court of the State of Nevada. This lawsuit was subsequently joined by
the County of Washoe Health District and the City of Sparks. These parties
sought remediation of the contamination at and adjacent to the Sparks terminal
as well as unspecified, but potentially significant, damages and statutory
penalties. In addition, the Partnership was named as one of the defendants in a
number of other lawsuits brought by property owners seeking unspecified, but
potentially substantial, damages for, among other things, alleged property value
diminishment attributable to soil or groundwater contamination arising from the
defendants' operations.

During 1995, the Partnership and seven other defendants (the "defendant group")
entered into settlement agreements with the State of Nevada, the City of Sparks
and the County of Washoe which settled the claims of these parties in exchange
for specified cash payments and other consideration, the details of which were
reported in the Partnership's 1995 Form 10-K. Among other things, the defendant
group agreed to use its best efforts to install an enhanced remediation system
to accelerate the cleanup of the environmental site. In that regard, the
Partnership is currently in discussions with both the EPA and Nevada Division
of Environmental Protection on possible enhancements to the existing remediation
system. In addition, during late 1995 and early 1996, the defendant group
reached final agreements to settle the claims of the seven property owners who
had filed lawsuits seeking damages alleged to be attributable to the
environmental contamination. These settlement agreements involve various terms,
including cash payments, environmental and property value diminishment
indemnifications, loan guarantees and the purchase of certain properties. All of
the lawsuits have now been dismissed. The Partnership's share of the costs of
all of the settlement agreements associated with the Sparks litigation was
included in its 1995 provisions for environmental costs aggregating $24 million.

-12-
<PAGE>

The Partnership and the General Partner have initiated two legal actions against
a total of 34 past and present insurance carriers (SFPP, L.P., Santa Fe Pacific
Pipeline Partners, L.P. and Santa Fe Pacific Pipelines, Inc. vs. Agricultural
Insurance Company, et al. and SFPP, L.P., Santa Fe Pacific Pipeline Partners,
------
L.P. and Santa Fe Pacific Pipelines, Inc. vs. Associated International Insurance
Company, et al., Superior Court of the State of California for the County of San
------
Mateo, Docket Nos. 395109 and 395121, respectively, filed January 1996). These
actions seek a judicial determination that the insurance policies issued by the
defendant insurers provide coverage to the Partnership and the General Partner
for certain costs, liabilities and settlements relating to approximately 25
environmental sites, including Sparks, Nevada. To date, the costs at issue in
these actions have been borne by the Partnership and its predecessor companies.
The defendant insurers have filed initial responsive pleadings in these actions,
and discovery is in progress.

OTHER
The Partnership and Southern Pacific Transportation Company ("SPTC") are engaged
in a judicial reference proceeding to determine the extent, if any, to which the
rent payable by the Partnership for the use of pipeline easements on
rights-of-way held by SPTC should be adjusted pursuant to existing contractual
arrangements (Southern Pacific Transportation Company vs. Santa Fe Pacific
Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P.,
et al., Superior Court of the State of California for the County of San
- ------
Francisco, filed August 31, 1994). Under an agreement entered into among the
parties in 1994, the amount of annual rent for such easements for the first year
of the ten-year period that began January 1, 1994 is to be based on the fair
market value of the easements, with the rent for subsequent years to be subject
to annual inflation adjustments. This matter was tried in the latter part of
1996 and the court issued its Statement of Tentative Decision in January 1997.
The Statement of Tentative Decision indicated that the court intended to
establish a new base annual rental for the subject rights-of-way at a level,
subject to inflation adjustments, that is adequately provided for by the amounts
that had been accrued by the Partnership through December 31, 1996. This
tentative decision could be modified by the trial court prior to its entry of
final judgment in the matter and the trial court's judgment will be subject to
appeal by SPTC once it is entered.

The Partnership is party to a number of other legal actions arising in the
ordinary course of business. While the final outcome of these other matters
cannot be predicted with certainty, it is the opinion of management that none of
these other legal actions, either individually or in the aggregate, when finally
resolved, will have a material adverse effect on the Partnership's annual
results of operations, financial condition, liquidity or ability to maintain its
quarterly cash distribution at the current level.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of security holders during the fourth
quarter of 1996.

-13-
<PAGE>

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Information as to the principal markets on which the Registrant's common units
are traded, the high and low sales prices of such units and distributions
declared on such units for the two years ended December 31, 1996, and the
approximate number of record holders of such units is set forth in Note 8 to the
Partnership's consolidated financial statements on page F-15 of this Report.

ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth selected consolidated financial data for the
Partnership:
<TABLE>
<CAPTION>

Year ended December 31,
----------------------------------------------------
(in thousands, except per unit data) 1996 1995 1994 1993 1992
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Total revenues.............................. $240,142 $233,677 $228,066 $219,471 $205,025
Operating expenses (excluding provisions
and depreciation & amortization).......... 107,941 103,196 97,199 95,178 85,340
Provisions for environmental
and litigation costs...................... 23,000 34,000 -- 27,000 10,000
Depreciation & amortization................. 21,080 20,500 19,820 18,971 18,327
Operating income............................ 88,121 75,981 111,047 78,322 91,358
Interest expense............................ 36,518 37,247 37,570 37,086 36,937
Income before cumulative
effect of accounting change (a)........... 52,275 40,367 76,885 41,616 54,118
Cumulative effect of accounting change...... -- -- -- -- (16,407)
Net income.................................. $ 52,275 $ 40,367 $ 76,885 $ 41,616 $ 37,711

PER UNIT DATA:
Income before cumulative
effect of accounting change............. $ 2.64 $ 2.04 $ 3.93 $ 2.13 $ 2.77
Cumulative effect of accounting change...... -- -- -- -- (0.84)
Net income.................................. 2.64 2.04 3.93 2.13 1.93
Cash distributions paid..................... 3.00 2.95 2.80 2.80 2.80
Cash distributions declared................. 3.00 3.00 2.80 2.80 2.80

CAPITAL EXPENDITURES........................ $ 27,686 $ 31,431 $ 17,913 $ 21,084 $ 30,931

BALANCE SHEET DATA (AT YEAR END):
Properties, plant and equipment, net........ $628,694 $623,318 $613,039 $616,610 $618,098
Total assets................................ 725,818 720,854 714,772 696,980 684,852
Long-term debt.............................. 355,000 355,000 355,000 355,000 355,000
Total partners' capital..................... 262,915 270,065 287,961 265,851 279,010
</TABLE>

(a) Effective January 1, 1992, the Partnership adopted new accounting standards
for postretirement and postemployment benefits (Statements of Financial
Accounting Standards Nos. 106 and 112).

-14-
<PAGE>

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

RESULTS OF OPERATIONS

1996 COMPARED WITH 1995
- -----------------------
The Partnership reported 1996 net income of $52.3 million, or $2.64 per unit,
compared to net income of $40.4 million, or $2.04 per unit, in 1995, with the
variance being primarily attributable to special items recorded in both years.
Results of operations included provisions for litigation costs aggregating $23.0
million in 1996 and provisions for environmental and litigation costs
aggregating $34.0 million in 1995. Excluding these provisions, adjusted net
income was $74.5 million, or $3.76 per unit, in 1996, compared to $73.3 million,
or $3.70 per unit, in 1995.

Total 1996 revenues of $240.1 million were approximately 3% above 1995 levels.
Trunk revenues of $189.2 million were $6.0 million higher than in 1995 primarily
due to growth in total volumes transported. Commercial volumes were about 3.5%
higher, and military volumes 7.5% lower, than in 1995, and the average length of
haul was slightly greater. Commercial deliveries to all of the major markets
served by the Partnership, including Southern California, increased during 1996.
The reduction in military volumes was largely attributable to the downsizing and
realignment of military bases served by the Partnership. Storage and terminaling
revenues were about 2% higher than in 1995. Other revenues were 1% lower than in
1995.

Total operating expenses of $152.0 million were $5.7 million lower than in 1995.
Excluding the provisions described above, operating expenses would have been
$5.3 million, or about 4.5%, higher than in 1995, with higher field operating
expenses ($4.4 million), general and administrative expenses ($2.8 million) and
depreciation and amortization ($0.6 million), being partially offset by lower
facilities costs ($1.8 million) and power costs ($0.7 million). The increase in
field operating expenses was largely attributable to higher pipeline repairs and
maintenance, including pipeline reconditioning projects, and higher
environmental costs, partially offset by reductions in certain other field
costs. General and administrative expenses were higher due to outside legal
costs, primarily associated with the East Line civil litigation, the FERC
proceedings, and environmental insurance litigation, higher employee health care
and other benefit costs, and business process redesign costs. The increase in
depreciation and amortization resulted from the Partnership's expanding capital
asset base. The decrease in facilities costs is largely attributable to
approximately $3 million in property tax refunds, partially offset by higher
insurance premiums and right-of-way rental costs. The decrease in power costs
resulted from periodic fuel cost adjustments received at several locations and
savings from power transmission capital investments. Excluding provisions,
environmental remediation and East Line litigation costs recorded as operating
expense aggregated $9.6 million in 1996 and $7.0 million in 1995.

Other income, net decreased $0.6 million compared to 1995, primarily due to
lower interest income, attributable to lower cash balances, partially offset by
a gain on the sale of excess land.

1995 COMPARED WITH 1994
- -----------------------
The Partnership reported 1995 net income of $40.4 million, or $2.04 per unit,
compared to net income of $76.9 million, or $3.93 per unit, in 1994, with the
variance being primarily attributable to special items recorded in both years.
Results of operations included provisions for environmental and litigation costs
aggregating $34.0 million in 1995 and a $3.1 million credit resulting from
changes in eligibility requirements for postretirement medical benefits in 1994.
Excluding the 1995 provisions and the 1994 credit, adjusted net income was $73.3
million, or $3.70 per unit, in 1995, compared to $73.9 million, or $3.78 per
unit, in 1994.

-15-
<PAGE>

Total 1995 revenues of $233.7 million were 2.5% above 1994 levels. Trunk
revenues of $183.3 million were $3.9 million higher than in 1994 primarily due
to growth in total volumes transported. Commercial volumes were about 1.5%
higher, and military volumes 5% lower, than in 1994, and the average length of
haul was slightly greater. Deliveries to most of the markets served by the
Partnership increased during 1995, although Southern California deliveries were
lower as a result of competition from short-haul trucking to Los Angeles area
terminals. The reduction in military volumes was largely attributable to the
closure of Castle Air Force Base, in Central California. Storage and terminaling
revenues were 1% higher than in 1994. Other revenues increased $1.3 million
primarily due to new detergent additive services.

Total operating expenses of $157.7 million were $40.7 million higher in 1995
than in 1994, due largely to 1995 provisions for environmental and litigation
costs aggregating $34.0 million. Excluding the 1995 provisions, operating
expenses would have been $6.7 million, or 6%, higher than in 1994, with higher
general and administrative expenses ($4.7 million), power costs ($1.0 million),
depreciation and amortization ($0.7 million) and field operating expenses ($0.5
million), partially offset by lower facilities costs ($0.3 million), accounting
for that increase. General and administrative expenses were higher due to
outside legal and consulting costs, primarily related to the FERC proceeding and
litigation associated with the Sparks, Nevada environmental site, partially
offset by lower employee health care and postretirement benefit costs. Power
costs increased as the result of increased volumes and greater use of drag
reducing agent to increase pipeline capacity on selected routes. The increase in
depreciation and amortization resulted from the Partnership's expanding capital
asset base, particularly short-lived software costs. The increase in field
operating expenses is largely attributable to higher repairs and maintenance,
including pipeline reconditioning. The decrease in facilities costs is largely
attributable to lower property tax assessments and insurance premiums, partially
offset by higher right-of-way rental costs. Excluding provisions, environmental
remediation and East Line litigation costs recorded as operating expense
aggregated $7.0 million in 1995 and $3.8 million in 1994.

Other income, net decreased $2.1 million compared to 1994, primarily due to the
$3.1 million postretirement benefit credit recorded in 1994, partially offset by
higher interest income, which resulted from higher interest rates and cash
balances.

FINANCIAL CONDITION - LIQUIDITY AND CAPITAL RESOURCES
For the year ended December 31, 1996, cash flow from operations totaled $87.2
million, compared to $83.7 million in 1995. Working capital cash requirements
decreased $7.7 million in 1996 due to timing differences in collections of trade
and nontrade accounts receivable and payment of accrued obligations. Proceeds
from property sales totaled $2.7 million. Significant uses of cash in 1996
included cash distributions of $61.4 million and capital expenditures of $27.7
million, resulting in a net increase in cash and cash equivalents of $0.9
million for the year. Total cash and cash equivalents of $42.1 million at
December 31, 1996 included $15.4 million for the fourth quarter 1996 cash
distribution, which was paid in February 1997.

Since the useful lives of the pipeline system and terminal properties are
generally long and technological change is limited, replacement of facilities is
relatively infrequent. The principal need for capital, therefore, has been in
connection with capacity expansions, service enhancements, compliance with
increasingly stringent environmental and safety regulations and installation of
Supervisory Control and Data Acquisition ("SCADA") equipment and related
operations systems software.

-16-
<PAGE>

For the year ended December 31, 1996, Partnership capital expenditures
aggregated $27.7 million. Capital expenditures for income enhancement projects,
including capacity expansions, service enhancements and system upgrades,
aggregated approximately $12 million in 1996, with approximately $6 million of
that total reflecting the purchase of a 35-mile, 6-inch diameter pipeline that
extends from the Partnership's Fresno, California terminal to Lemoore Naval Air
Station. Capital expenditures for environmental and safety projects included
additions and modifications to storage tanks and vapor recovery systems to
comply with more stringent regulations, oily water handling facilities and fire
protection improvements. Such expenditures aggregated approximately $6 million
in 1996 and are expected to increase over time in response to increasingly
rigorous environmental and safety standards.

The planned 1997 capital program aggregates approximately $28 million, of which
$16 million will be invested in facility upgrades and environmental, safety and
regulatory-driven projects. The Partnership presently anticipates that ongoing
capital expenditures will average approximately $30 million per year over the
next five years. This amount could increase or decrease as the result of
changing regulatory requirements or business opportunities associated with
pipeline and facility expansions and acquisitions.

The Partnership expects that it will generally finance its ongoing capital
program with internally generated funds; however, the Partnership may use
borrowed funds or proceeds from additional equity offerings to finance a portion
of significant capital expenditures. Future capital expenditures will continue
to depend on numerous factors, some of which are beyond the Partnership's
control, including demand for refined petroleum products in the pipeline
system's market areas, changes in product supply patterns, governmental
regulations and the availability of sufficient funds from operations to fund
such expenditures.

During 1996, the Partnership continued to review the feasibility of providing
pipeline service from the San Francisco Bay area to Colton, in Southern
California, by expanding the existing capacity on its North Line and building a
new pipeline between Fresno and Colton. Due to supply and market uncertainties,
the level of shipper throughput commitments has not been sufficient to proceed
and places the viability of this project in doubt.

Long-term debt aggregated $355 million at December 31, 1996 and consisted of
$305 million of First Mortgage Notes (the "Notes") and a $50 million borrowing
under the Partnership's bank term credit facility. The Partnership intends to
refinance some or all of the Notes as the various series become payable. To
facilitate such refinancing and provide for additional financial flexibility,
the Partnership presently has available the multi-year term credit facility,
with a $60 million aggregate limit, and a $20 million working capital facility
with three banks. The term facility may also be used to finance capital
projects, while the working capital facility is available for general short-term
borrowing purposes. Management has held discussions with the three lenders, and
the lenders have presented proposals, to significantly expand the Partnership's
borrowing capacity under, and extend the term of, the existing term credit
facility. Management expects that an expansion and extension of the facility's
provisions will be completed during the first half of 1997.

-17-
<PAGE>

OTHER MATTERS

RATE REGULATION
The Partnership's interstate common carrier pipeline operations are subject to
rate regulation by the Federal Energy Regulatory Commission ("FERC"). Intrastate
common carrier operations in California are subject to regulation by the
California Public Utilities Commission ("CPUC"). In 1996, rates subject to FERC
and CPUC regulation accounted for approximately 57% and 43% of total
transportation revenues, respectively.

In 1985, the FERC adopted a cost-based methodology for establishing allowable
rates for liquid petroleum pipelines; however, this methodology continues to be
subject to clarification in individual cases and leaves many issues for
determination on a case-by-case basis. Effective January 1995, the FERC
established a new rate-making methodology that allows oil pipelines to adjust
their transportation rates as long as those rates do not exceed prescribed
ceiling levels determined by applying an index equal to annual changes in the
Producer Price Index for Finished Goods, minus one percent. Under this
methodology, pipelines may apply for cost of service-based rates in those cases
where the carrier can demonstrate that a "substantial divergence" exists between
the rates that would be allowed under cost-based rate-making and the rates
produced by indexation. In addition, carriers may establish market-based rates
for those markets in which it can be demonstrated that they do not have
significant market power. The access to cost-based and market-based rates is
significant because the Partnership believes the index selected by the FERC does
not adequately reflect historical cost of service increases and, accordingly,
the Partnership may need to pursue cost-based or selective market-based rate
adjustments in future rate filings. Interstate rate indexing had a minimal
impact on Partnership revenues in 1996 and management does not expect that
indexing will have a significant impact on trunk revenues in 1997.

EAST LINE CIVIL LITIGATION AND FERC PROCEEDINGS
Certain of the Partnership's shippers have filed civil suits and initiated FERC
complaint proceedings alleging, among other things, that the shippers were
damaged by the Partnership's failure to fulfill alleged promises to expand the
East Line's capacity between El Paso, Texas and Phoenix, Arizona to meet shipper
demand. The FERC proceedings also involve claims, among other things, that
certain of the Partnership's rates and charges on its East and West Lines are
excessive. To date, the complainants have filed testimony in the FERC proceeding
seeking reparations for shipments between 1990 and 1994 aggregating
approximately $35 million, as well as rate reductions of between 30% and 40% for
shipments in 1995 and thereafter. The remaining civil action, brought by El Paso
Refinery, L.P. ("El Paso") and its general partner, El Paso Refining, Inc.,
claims unspecified actual damages, which appear to include the $190 million cost
of a refinery expansion completed in 1992, plus punitive and consequential
damages.

During 1996, the Partnership pursued settlement efforts to resolve the claims
raised in the FERC proceedings and reached agreements with El Paso regarding its
challenge of the Partnership's East Line rates and with Navajo Refining Company
("Navajo") regarding its challenge of the Partnership's West Line rates. The
Partnership has also presented settlement offers to all of the remaining
complainants in the FERC proceedings, including Navajo with respect to the
Partnership's East Line rates. The terms of the settlement agreements with El
Paso and Navajo do not provide for rate reductions, but other offers that have
been extended do include proposed prospective reductions in the rates at issue
in the proceedings.

-18-
<PAGE>

On February 25, 1997, the Partnership entered into an agreement with the El Paso
bankruptcy trustee which, subject to the approval of the bankruptcy court, would
settle all of the claims raised by El Paso and its general partner in the civil
litigation in exchange for the payment of $16 million by the Partnership in two
equal installments. As the amount of the proposed settlement exceeds the amount
that had previously been reserved for this matter, management anticipates that
the Partnership will record a provision of approximately $6 million to reflect
this settlement during the first quarter of 1997.

While the Partnership believes it has meritorious defenses in these matters, the
complainants and plaintiffs are seeking amounts that, in the aggregate,
substantially exceed the Partnership's reserves and, because of the
uncertainties associated with litigation and the FERC rate-making methodology,
management cannot predict with certainty the ultimate outcome of these matters.
The Partnership is also not able to predict with certainty whether settlement
agreements will be completed with some or all of the parties to the FERC
Proceeding or the El Paso civil action or the final terms of any such additional
settlement agreements that may be consummated. As additional information becomes
available, it may be necessary for the Partnership to record additional charges
to earnings to maintain its reserves at a level deemed adequate at that time,
and the costs associated with the ultimate resolution of these matters could
have a material adverse effect on the Partnership's results of operations,
financial condition, liquidity and ability to maintain its quarterly cash
distribution at the current level.

ENVIRONMENTAL
The Partnership's transportation and terminal operations are subject to
extensive regulation under federal, state and local environmental laws
concerning, among other things, the generation, handling, transportation and
disposal of hazardous materials and the Partnership is, from time to time,
subject to environmental cleanup and enforcement actions. In particular, the
federal Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA" or "Superfund" law) generally imposes joint and several liability for
cleanup and enforcement costs, without regard to fault or the legality of the
original conduct, on current or predecessor owners and operators of a site.

-19-
<PAGE>

In a number of remediation projects, the Partnership is participating with other
entities ranging from large integrated petroleum companies to certain less
financially sound parties.

The Partnership's balance sheet at December 31, 1996 and 1995 includes reserves
for environmental costs aggregating $25.1 million and $37.1 million,
respectively, which reflect the estimated cost of completing all remediation
projects presently known to be required, either by government mandate or in the
ordinary course of business, and the cost of performing preliminary
environmental investigations at several locations, as well as environmental
damage claims, primarily associated with the Sparks environmental site. With
respect to the costs accrued at December 31, 1996, the Partnership estimates
that approximately $8.5 million will be paid in 1997, approximately $2 million
to $4 million will be paid per year over the following four years, and
approximately $1 million or less will be paid per year over the subsequent five
years.

DEMAND FOR REFINED PETROLEUM PRODUCTS
Demand for transportation and terminaling services is principally a function of
product consumption and competition in markets served by the pipeline system.
Commercial volumes are generally dependent upon such factors as prevailing
economic conditions, demographic changes, transportation and terminaling
alternatives and, to a lesser degree, product prices paid by end-users. Military
volumes are dependent upon the level of activity at military bases served by the
Partnership.

-20-
<PAGE>

During 1996, the pipeline systems, on average, operated at approximately 75% of
capacity. While capacity utilization on individual system segments generally
ranged from 70% to 90% of capacity, the lines from the Los Angeles area to San
Diego and Colton, California and from the San Francisco Bay area to Sacramento,
California and Reno, Nevada operated at or near full capacity for a portion of
the year. Overall, volumes have been moderately seasonal, with somewhat lower
than average volumes being transported during the first and fourth quarters of
each year, although deliveries to specific locations also experience seasonal
variations.

OTHER
The Partnership leases certain rights-of-way under an agreement that became
subject to renegotiation effective January 1, 1994 and the Partnership and the
lessor were unable to reach an agreement on a new base annual rental payment for
the next ten-year period. In the years 1994 through 1996, the Partnership
accrued for an increase in the annual rental for these rights-of-way. In January
1997, a tentative decision was rendered in the judicial reference proceeding
held to resolve this matter. This tentative decision would establish the new
base annual rental for these rights-of-way at a level, subject to inflation
adjustments, that is adequately provided for by the amounts that had been
accrued through December 31, 1996.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Partnership's consolidated financial statements, together with the report
thereon of Price Waterhouse LLP dated January 31, 1997, are set forth on pages
F-1 through F-15 of this Report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The Registrant has no officers, directors or employees. Set forth below is
certain information concerning the directors and executive officers of the
General Partner.

Orval M. Adam, age 66, is a director of the General Partner, Chairman of the
Compensation and Benefits Committee and a member of the Audit Committee and
Committee on Directors. He retired in January 1991 from his position as Senior
Vice President and Chief Financial Officer of Santa Fe. Mr. Adam is also a
director of SFP Pipeline Holdings, Inc., the sole shareholder of the General
Partner.

Wilford D. Godbold, Jr., age 58, is a director of the General Partner, Chairman
of the Audit Committee and a member of the Compensation and Benefits Committee
and Committee on Directors. Mr. Godbold has served as President and Chief
Executive Officer of ZERO Corporation (container manufacturer) since 1984. Mr.
Godbold is also a director of ZERO Corporation, Pacific Enterprises and Southern
California Gas Company.

Michael A. Morphy, age 64, is a director of the General Partner and a member of
the Audit Committee and Compensation and Benefits Committee. Mr. Morphy retired
in 1985 from his position as Chairman and Chief Executive Officer of California
Portland Cement Company (cement manufacturer). Mr.

-21-
<PAGE>

Morphy is also a director of SFP Pipeline Holdings, Inc., the sole shareholder
of the General Partner, Santa Fe Energy Resources, Inc. and Cyprus Amax Minerals
Company.

Robert D. Krebs, age 54, is a director of the General Partner, Chairman of the
Committee on Directors and a member of the Compensation and Benefits Committee.
Mr. Krebs has served as President and Chief Executive Officer of Burlington
Northern Santa Fe Corporation ("BNSF") since September 1995. He previously
served as Chairman, President and Chief Executive Officer of Santa Fe since
1988. Mr. Krebs is also a director of BNSF, Santa Fe Pacific Gold Corporation,
Phelps Dodge Corporation and Northern Trust Corporation.

Denis E. Springer, age 51, is a director of the General Partner and a member of
the Compensation and Benefits Committee and Committee on Directors. Mr. Springer
has been Senior Vice President and Chief Financial Officer of BNSF since
September 1995 and, previously, served in those same positions at Santa Fe since
October 1993. Mr. Springer previously served Santa Fe as Senior Vice President,
Treasurer and Chief Financial Officer since January 1992. Mr. Springer is also a
director of SFP Pipeline Holdings, Inc., the sole shareholder of the General
Partner.

Irvin Toole, Jr., age 55, is President, Chief Executive Officer and Chairman of
the Board of Directors of the General Partner. From November 1988 until election
to his present position in September 1991, Mr. Toole served as Senior Vice
President, Treasurer and Chief Financial Officer. Mr. Toole is also Chairman of
the Board of Directors of SFP Pipeline Holdings, Inc., the sole shareholder of
the General Partner.

Robert L. Edwards, age 41, is a director of the General Partner and has been
Senior Vice President-Business Development and Planning of the General Partner
since January 1995. Previously, Mr. Edwards was Senior Vice President, Treasurer
and Chief Financial Officer from December 1991 through January 1995. Mr. Edwards
is also a director of SFP Pipeline Holdings, Inc., the sole shareholder of the
General Partner.

Barry R. Pearl, age 47, has been Senior Vice President, Treasurer and Chief
Financial Officer of the General Partner since January 1995. Mr. Pearl
previously served as Senior Vice President-Business Development and Planning
between January 1992 and January 1995.

John M. Abboud, age 54, has been Senior Vice President-Operations and
Engineering of the General Partner since 1985.

Lyle B. Boarts, age 53, has been Vice President-Human Resources of the General
Partner since November 1988.

R. Gregory Cunningham, age 51, has been Vice President-General Counsel since
January 1994. Previously, he served as General Counsel of the General Partner
since January 1991.

Burnell H. DeVos III, age 43, has served as Controller and Secretary of the
General Partner since January 1993. Mr. DeVos was Assistant Controller of the
General Partner from May 1989 through December 1992.

William M. White, age 51, has served as Vice President-Engineering of the
General Partner since January 1993. Mr. White previously was Manager-Northern
District from May 1986 through December 1992.

-22-
<PAGE>

ITEM 11. EXECUTIVE COMPENSATION.
The directors, officers and employees of the General Partner receive no direct
compensation from the Partnership for their services to the Partnership. The
Partnership reimburses the General Partner for all direct costs incurred in
managing the Partnership and all indirect costs (principally salaries and other
general and administrative costs) allocable to the Partnership.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

(a) Security Ownership of Certain Beneficial Owners

To the best of the General Partner's knowledge, the following persons are the
only persons who are beneficial owners of more than five percent of the
Registrant's equity securities:

<TABLE>
<CAPTION>
Number Percent
Title of Class Name and Address of Units of Class
- --------------- ------------------------------------ ----------- --------
<C> <S> <C> <C>
Common units Santa Fe Pacific Pipelines, Inc. (1) 8,148,148 42.6%
1100 Town & Country Road
Orange, CA 92868

Common units J. P. Morgan & Co., Incorporated (2) 3,010,471 15.7%
60 Wall Street
New York, NY 10260

Common units Pioneering Management Corporation (3) 1,234,200 6.4%
60 State Street
Boston, MA 02109
</TABLE>
(1) As discussed in Items 1 and 2 of this Report, Santa Fe Pacific Pipelines,
Inc. is also the general partner of the Partnership, referred to herein as
the "General Partner," and is a wholly owned indirect subsidiary of Santa
Fe Pacific Corporation ("Santa Fe") which, as the result of a business
combination in September 1995, is a wholly owned subsidiary of Burlington
Northern Santa Fe Corporation.

(2) This information is based on a Securities and Exchange Commission Schedule
13-G report by J. P. Morgan & Co., Incorporated, dated and filed on January
31, 1997.

(3) This information is based on a Securities and Exchange Commission Schedule
13-G report by Pioneering Management Corporation, dated and filed on
January 27, 1997.

(b) Security Ownership of Management

As of February 28, 1997, common units beneficially held by all directors and
officers as a group represented less than 1% of the Partnership's outstanding
units.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The Registrant and the Operating Partnership are managed by the General Partner
pursuant to the Amended and Restated Agreement of Limited Partnership of the
Partnership (the "Partnership Agreement"), and the Amended and Restated
Agreement of Limited Partnership of the Operating Partnership (the "Operating
Partnership Agreement"). Under the Partnership Agreement and Operating
Partnership Agreement, the General Partner and certain related parties are
entitled to reimbursement of all direct and indirect costs and expenses related
to the business activities of the Partnership and the Operating Partnership.
These costs and expenses include compensation and benefits payable to officers
and employees of the General Partner, payroll taxes, corporate office building
rentals, general and

-23-
<PAGE>

administrative costs, and legal and other professional services fees. These
costs to the Partnership totaled $50.4 million, $45.8 million and $40.6 million
in 1996, 1995 and 1994, respectively.

The Partnership Agreement provides for incentive distribution payments to the
General Partner out of the Partnership's "Available Cash" (as defined in the
Partnership Agreement) which increase as quarterly distributions to unitholders
exceed certain specified targets. The incremental incentive distributions
payable to the General Partner are 8%, 18% and 28% of all distributions of
Available Cash that exceed, respectively, $0.60, $0.65 and $0.70 per unit. Such
incentive distributions aggregated $2,735,000 in 1996, $2,350,000 in 1995 and
$1,200,000 in 1994.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

(a) The following documents are filed as a part of this Report:
<TABLE>
<CAPTION>
Page
----
<S> <C>
(1) Financial Statements:
Report of Independent Accountants................................. F-1
Consolidated Balance Sheet as of December 31, 1996 and 1995....... F-2
Consolidated Statement of Income for the three years ended
December 31, 1996.......................................... F-3
Consolidated Statement of Cash Flows for the three years
ended December 31, 1996.................................... F-4
Notes to Consolidated Financial Statements........................ F-5
</TABLE>
(2) Financial Statement Schedules: None.

(3) Exhibits: The following exhibits are filed as a part of this Report. With
the exception of Exhibits 21, 24 and 27, all exhibits listed herein are
incorporated by reference, with the location of the exhibit in the
Registrant's previous filing being indicated parenthetically.

<TABLE>
<CAPTION>
Exhibit
Number Description
- -------- ----------------------------------------------------------------------
<C> <S>
3.1 Amended and Restated Agreement of Limited Partnership of the
Registrant, dated as of December 19, 1988.
(1988 Form 10-K - (Exhibit 3.1)
3.2 Amended and Restated Agreement of Limited Partnership of the
Operating Partnership, dated as of December 19, 1988.
(1988 Form 10-K - Exhibit 3.2)
3.3 Certificate of Limited Partnership of the Registrant, dated as of
August 23, 1988. (1988 Form 10-K -Exhibit 3.3)
3.4 Certificate of Limited Partnership of the Operating Partnership,
dated as of August 23, 1988. (1988 Form 10-K - Exhibit 3.5)
3.5 Assumption Agreement between the Registrant and Santa Fe Pacific
Pipelines, Inc., dated as of December 7, 1989.
(1989 Form 10-K - Exhibit 3.4)
3.6 Amendment No. 1 to Amended and Restated Agreement of Limited
Partnership of the Registrant, dated as of December 7, 1989.
(1989 Form 10-K - Exhibit 3.2)
3.7 Certificate of Amendment to Certificate of Limited Partnership
of the Registrant, dated as of December 7, 1989.
(1989 Form 10-K - Exhibit 3.3)
3.8 Amendment No. 1 to Amended and Restated Agreement of Limited
Partnership of the Operating Partnership, dated as of December 7,
1989. (1989 Form 10-K - Exhibit 3.5)
</TABLE>

-24-
<PAGE>

<TABLE>
<CAPTION>
Exhibit
Number Description
- -------- ----------------------------------------------------------------------
<C> <S>
3.9 Certificate of Amendment to Certificate of Limited Partnership of the
Operating Partnership, dated as of December 7, 1989.
(1989 Form 10-K - Exhibit 3.6)
3.10 Amendment No. 2 to Amended and Restated Agreement of Limited
Partnership of the Operating Partnership, dated as of January 24,
1990. (1989 Form 10-K - Exhibit 3.8)
3.11 Certificate of Amendment No. 2 to Certificate of Limited Partnership
of the Operating Partnership, dated as of January 30, 1990.
(1989 Form 10-K - Exhibit 3.9)
4.1 Form of Deposit Agreement between the Registrant, American Stock
Transfer & Trust Company and the General Partner, as attorney-in-fact
Statement No. 33-24395 - Exhibit 4.1)
4.2 First Mortgage Note Agreement, dated December 8, 1988 (a conformed
composite of 54 separate agreements, identical except for signatures)
(1988 Form 10-K - Exhibit 4.2)
4.3 Deed of Trust, Security Agreement and Fixture Filing, dated December
8, 1988, between the Operating Partnership, the General Partner,
Chicago Title Insurance Company and Security Pacific National Bank.
(1988 Form 10-K - Exhibit 4.3)
4.4 Trust Agreement, dated December 19, 1988, between the Operating
Partnership, the General Partner and Security Pacific National Bank.
(1988 Form 10-K - Exhibit 4.4)
4.5 The Operating Partnership has established a $60 million term
credit facility with three banks, dated as of October 14, 1993. As
the maximum allowable borrowings under this facility do not exceed
10% of the Registrant's total assets, this instrument is not filed as
an exhibit to this Report, however, the Registrant hereby agrees to
furnish a copy of such instrument to the Securities and Exchange
Commission upon request.
21 Subsidiaries of the Registrant*
24 Powers of attorney*
27 Financial Data Schedule as of and for the year ended December 31,
1996*
</TABLE>

* Filed herewith.

(b) Reports on Form 8-K filed during the quarter ended December 31, 1996: None

-25-
<PAGE>

SIGNATURES

Santa Fe Pacific Pipeline Partners, L.P., pursuant to the requirements of
Section 13 or 15(d) of the Securities Exchange Act of 1934, has duly caused this
Report to be signed on its behalf by the undersigned, thereunto duly authorized.

SANTA FE PACIFIC PIPELINE PARTNERS, L.P.
(Registrant)
By: Santa Fe Pacific Pipelines, Inc., as General Partner

Dated: March 24, 1997 By: /s/ IRVIN TOOLE, JR.
------------------------------------------------------
Irvin Toole, Jr.
Chairman, 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 the Registrant and
in the capacities with Santa Fe Pacific Pipelines, Inc., as General Partner, and
on the date indicated.
<TABLE>
<CAPTION>
Signature Title
- --------------------------- -----------------------------------------------
<S> <C>
/s/ IRVIN TOOLE, JR. Chairman, President and Chief Executive Officer
- --------------------------- (Principal Executive Officer)
Irvin Toole, Jr. and Director

/s/ BARRY R. PEARL Senior Vice President, Treasurer
- --------------------------- and Chief Financial Officer
Barry R. Pearl (Principal Financial Officer)

/s/ BURNELL H. DeVOS III Controller and Secretary
- --------------------------- (Principal Accounting Officer)
Burnell H. DeVos III

/s/ ROBERT L. EDWARDS Senior Vice President-
- --------------------------- Business Development and Planning
Robert L. Edwards and Director

ORVAL M. ADAM*
- --------------------------- Director
Orval M. Adam

WILFORD D. GODBOLD, JR.*
- --------------------------- Director
Wilford D. Godbold, Jr.

MICHAEL A. MORPHY*
- --------------------------- Director
Michael A. Morphy

ROBERT D. KREBS*
- --------------------------- Director
Robert D. Krebs

DENIS E. SPRINGER*
- --------------------------- Director
Denis E. Springer
</TABLE>

*By: /s/ BARRY R. PEARL
---------------------------------
Barry R. Pearl, attorney in fact

Dated: March 24, 1997

-26-

<PAGE>

EXHIBIT 21
----------

The following is a subsidiary of the Registrant:

Santa Fe Pacific Pipelines, Inc., a Delaware corporation.

<PAGE>

EXHIBIT 24
----------

POWER OF ATTORNEY
-----------------

WHEREAS, SFP PIPELINE HOLDINGS, INC., a Delaware corporation (the
"Registrant"), will file with the Securities and Exchange Commission, under the
provisions of the Securities Exchange Act of 1934, as amended, its Annual Report
on Form 10-K for the fiscal year ended December 31, 1996; and

WHEREAS, the undersigned holds the office in the Corporation as set forth
below his name;

NOW THEREFORE, the undersigned hereby constitutes and appoints Barry R.
Pearl, his attorney, with full power to act for him in his name, place and
stead, to sign his name to the Annual Report on Form 10-K of the Registrant for
the fiscal year ended December 31, 1996; and to any and all amendments to such
Annual Report on Form 10-K, and hereby ratifies and confirms all that said
attorney may or shall lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 13th day of February 1997.

/s/ ORVAL M. ADAM
-----------------------------
Orval M. Adam
Director
<PAGE>

POWER OF ATTORNEY
-----------------

WHEREAS, the undersigned holds the office in the Corporation as set forth
below his name;

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 13th day of February 1997.

/s/ DENIS E. SPRINGER
-----------------------------
Denis E. Springer
Director

<PAGE>

POWER OF ATTORNEY
-----------------

WHEREAS, the undersigned holds the office in the Corporation as set forth
below his name;

IN WITNESS WHEREOF, the undersigned has executed this Power of Attorney
this 13th day of February 1997.

/s/ MICHAEL A. MORPHY
-----------------------------
Michael A. Morphy
Director

<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS OF SFP PIPELINE HOLDINGS, INC. AS OF AND FOR
THE YEAR ENDED DECEMBER 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 3,061
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 4,403
<PP&E> 0
<DEPRECIATION> 0
<TOTAL-ASSETS> 203,685
<CURRENT-LIABILITIES> 11,940
<BONDS> 204,173
0
0
<COMMON> 1
<OTHER-SE> (72,430)
<TOTAL-LIABILITY-AND-EQUITY> 203,685
<SALES> 0
<TOTAL-REVENUES> 24,989
<CGS> 0
<TOTAL-COSTS> 477
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 25,465
<INCOME-PRETAX> 7,882
<INCOME-TAX> 3,439
<INCOME-CONTINUING> 4,443
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,443
<EPS-PRIMARY> 0
<EPS-DILUTED> 0

</TABLE>

<PAGE>

EXHIBIT 28.1

Report of Independent Accountants

To the Stockholders and Board of Directors of Burlington Northern Santa Fe
Corporation and Subsidiaries

In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, of cash flows and of changes in stockholders'
equity present fairly, in all material respects, the financial position of
Burlington Northern Santa Fe Corporation and subsidiary companies at December
31, 1996 and the results of their operations and their cash flows for the year
in conformity with generally accepted accounting principles. 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 audit. We conducted our audit of these financial statements in accordance
with generally accepted auditing standards 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 audit provides a reasonable basis for the opinion expressed
above. The consolidated financial statements of Burlington Northern Santa Fe
Corporation and subsidiary companies for the years ended December 31, 1995 and
1994 were audited by other independent accountants whose report dated February
15, 1996 expressed an unqualified opinion on those statements and included an
explanatory paragraph that described the changes in the Company's method of
accounting for periodic major locomotive overhauls in 1995 and for
postemployment benefits in 1994 discussed in Note 4 to the financial statements.

Price Waterhouse LLP
Chicago, Illinois
February 7, 1997

<PAGE>

CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>
Burlington Northern Santa Fe Corporation and Subsidiaries
(Dollars in millions, except per share data)
- -------------------------------------------------------------------------------------------------
Year ended December 31, 1996 1995 1994
- ----------------------------------------------------------------- ------ ------ ------
<S> <C> <C> <C>
Revenues $8,187 $6,163 $4,976
Operating expenses:
Compensation and benefits 2,561 2,067 1,766
Purchased services 866 593 529
Depreciation and amortization 760 520 362
Equipment rents 736 540 429
Fuel 727 480 369
Materials and other 789 702 668
Merger, severance and asset charges -- 735 --
------ ------ ------
Total operating expenses 6,439 5,637 4,123
- ----------------------------------------------------------------- ------ ------ ------
Operating income 1,748 526 853
Interest expense 301 220 155
Other income (expense), net (7) 28 (3)
------ ------ ------
Income before income taxes 1,440 334 695
Income tax expense 551 136 269
------ ------ ------
Income before extraordinary item and cumulative effect
of change in accounting method 889 198 426
Extraordinary item, loss on early retirement of debt, net of tax -- (6) --
------ ------ ------
Income before cumulative effect of change in accounting method 889 192 426
Cumulative effect of change in accounting method, net of tax -- (100) (10)
------ ------ ------
Net income $ 889 $ 92 $ 416
- ----------------------------------------------------------------- ====== ====== ======
Primary earnings per common share:
Income before extraordinary item and change in accounting method $ 5.70 $ 1.66 $ 4.48
Extraordinary item -- (.05) --
Change in accounting method -- (.94) (.11)
------ ------ ------
Primary earnings per common share $ 5.70 $ 0.67 $ 4.37
- ----------------------------------------------------------------- ====== ====== ======
Average shares (in millions) 156.0 106.7 90.2
Fully diluted earnings per common share:
Income before extraordinary item and change in accounting method $ 5.70 $ 1.66 $ 4.38
Extraordinary item -- (.05) --
Change in accounting method -- (.94) (.11)
------ ------ ------
Fully diluted earnings per common share $ 5.70 $ 0.67 $ 4.27
- ----------------------------------------------------------------- ====== ====== ======
Average shares (in millions) 156.0 106.7 97.5
</TABLE>
See accompanying notes to consolidated financial statements.

2
<PAGE>

CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
Burlington Northern Santa Fe Corporation and Subsidiaries
(Dollars in millions)
- ------------------------------------------------------------------------------------------------
December 31, 1996 1995
- ----------------------------------------------------------------------- ------- -------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 47 $ 50
Accounts receivable, net 711 620
Materials and supplies 222 220
Current portion of deferred income taxes 307 320
Other current assets 44 54
------- -------
Total current assets 1,331 1,264

Property and equipment, net 17,633 16,001
Other assets 882 1,004
------- -------
Total assets $19,846 $18,269
- ----------------------------------------------------------------------- ======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and other current liabilities $ 2,146 $ 2,289
Long-term debt due within one year 165 80
------- -------
Total current liabilities 2,311 2,369

Long-term debt and commercial paper 4,546 4,153
Deferred income taxes 4,729 4,233
Casualty and environmental liabilities 543 626
Employee merger and separation costs 466 530
Other liabilities 1,270 1,321
------- -------
Total liabilities 13,865 13,232
- ----------------------------------------------------------------------- ------- -------
Commitments and contingencies (see Notes 3, 12 and 13)
Stockholders' equity:
Common stock, $.01 par value, 300,000,000 shares authorized;
154,198,088 shares and 149,649,930 shares issued, respectively 2 1
Additional paid-in capital 4,838 4,606
Retained earnings 1,165 459
Treasury stock, at cost, 196,122 shares and 44,713 shares, respectively (16) (3)
Other (8) (26)
------- -------
Total stockholders' equity 5,981 5,037
------- -------
Total liabilities and stockholders' equity $19,846 $18,269
- ----------------------------------------------------------------------- ======= =======
</TABLE>

See accompanying notes to consolidated financial statements.

3
<PAGE>

Consolidated Statement of Cash Flows

Burlington Northern Santa Fe Corporation and Subsidiaries
(Dollars in millions)
- ------------------------------------------------------------------------------------------
Year ended December 31, 1996 1995 1994
- ------------------------------------------------------------ ------- ------- -----
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income $ 889 $ 92 $ 416
Adjustments to reconcile net income to net
cash provided by operating activities:
Cumulative effect of change in accounting method -- 100 10
Depreciation and amortization 760 520 362
Deferred income taxes 453 (112) 126
Merger, severance and asset charges -- 735 --
Employee merger and separation costs paid (183) (118) --
Other, net (62) 51 9
Changes in current assets and liabilities, excluding SFP
assets/liabilities acquired:
Accounts receivable, net (100) 63 (108)
Materials and supplies (2) (42) (13)
Other current assets (6) (5) (5)
Accounts payable and other current liabilities 122 132 11
------- ------- -----
Net cash provided by operating activities 1,871 1,416 808
- ---------------------------------------------------------- ------- ------- -----
INVESTING ACTIVITIES
Cash used for capital expenditures (2,234) (890) (698)
Purchase of SFP, net of cash acquired -- (488) (18)
Other, net (10) 12 16
------- ------- -----
Net cash used for investing activities (2,244) (1,366) (700)
- ---------------------------------------------------------- ------- ------- -----
FINANCING ACTIVITIES
Net (decrease) increase in commercial paper (78) 895 64
Proceeds from issuance of long-term debt 626 1,294 310
Payments on long-term debt (103) (2,071) (346)
Dividends paid (184) (129) (129)
Proceeds from stock options exercised 118 25 6
Other, net (9) (41) (3)
------- ------- -----
Net cash provided by (used for) financing activities 370 (27) (98)
------- ------- -----
Increase (decrease) in cash and cash equivalents (3) 23 10
Cash and cash equivalents:
Beginning of year 50 27 17
------- ------- -----
End of year $ 47 $ 50 $ 27
- ---------------------------------------------------------- ======= ======= =====
SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid, net of amounts capitalized $ 306 $ 228 $ 149
Income taxes paid, net of refunds 69 250 128
Assets financed through capital lease obligations 43 140 50
Noncash consideration for purchase of SFP:
Net assets acquired $ 3,319
Cash paid (532)
Cash acquired 26
-------
Noncash consideration $ 2,813
- ---------------------------------------------------------- ======= ======= =====
</TABLE>

See accompanying notes to consolidated financial statements.

4
<PAGE>

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Burlington Northern Santa Fe Corporation and Subsidiaries
(Shares in thousands. Dollars in millions, except per share data.)
- -----------------------------------------------------------------------------------------------------------------------------------
Convertible
Preferred Common
Stock and Stock and
Outstanding Additional Additional
Common Paid-in Paid-in Retained Treasury
Shares Capital Capital Earnings Stock Other Total
- -------------------------------------------------------------- ---------- ---------- -------- -------- ------ -------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1993 88,796 $ 337 $1,421 $ 198 $ (4) $(33) $1,919
Net income 416 416
Dividends:
Common stock, $1.20 per share (107) (107)

Convertible preferred stock, $3.125 per share (22) (22)

Adjustments associated with unearned
compensation, restricted stock 178 12 (1) 11
Exercise of stock options and related tax benefit 184 8 8
Equity adjustment from minimum pension
liability 9 9
Other 66 3 3
- -------------------------------------------------------------- ---------- ---------- -------- -------- ------ -------

Balance at December 31, 1994 89,224 337 1,444 485 (5) (24) 2,237
Net income 92 92
Purchase of SFP:
Common stock issued 52,004 2,652 2,652
Value of outstanding SFP stock options 119 119
Conversion and redemption of convertible
preferred stock for common stock 7,313 (337) 335 (2)

Dividends:
Common stock, $1.20 per share (123) (123)

Convertible preferred stock, $3.125 per share (21) (21)

Adjustments associated with unearned
compensation, restricted stock 243 13 2 16 31
Exercise of stock options and related tax benefit 778 39 (3) 36
Equity adjustment from minimum pension
liability (18) (18)

Cost to equity investment adjustment 26 26
Other 43 5 3 8
- -------------------------------------------------------------- ---------- ---------- -------- -------- ------ -------

Balance at December 31, 1995 149,605 -- 4,607 459 (3) (26) 5,037
Net income 889 889
Common stock dividends, $1.20 per share (183) (183)

Adjustments associated with unearned
compensation, restricted stock 539 8 (2) 3 9
Exercise of stock options and related tax benefit 3,454 191 (11) 180
Equity adjustment from minimum pension
liability 15 15
Acquisition of a subsidiary 363 31 31
Other 41 3 3
- -------------------------------------------------------------- ---------- ---------- -------- -------- ------ -------

Balance at December 31, 1996 154,002 $ -- $4,840 $1,165 $(16) $ (8) $5,981
- -------------------------------------------------------------- ========== ========== ======== ======== ====== =======
</TABLE>
See accompanying notes to consolidated financial statements.

5
<PAGE>

Notes to Consolidated Financial Statements
Burlington Northern Santa Fe Corporation and Subsidiaries

1. ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Burlington
Northern Santa Fe Corporation and its majority-owned subsidiaries (collectively
BNSF or Company). BNSF was incorporated in Delaware on December 16, 1994, for
the purpose of effecting a business combination between Burlington Northern Inc.
(BNI) and Santa Fe Pacific Corporation (SFP) which was consummated on September
22, 1995. The principal subsidiaries of BNI and SFP were Burlington Northern
Railroad Company (BNRR) and The Atchinson, Topeka and Santa Fe Railway Company
(ATSF), respectively. Effective December 1996, BNI was merged with and into SFP,
and ATSF merged with and into BNRR and the name was changed to The Burlington
Northern and Santa Fe Railway Company (BNSF Railway). The accompanying BNSF
consolidated statements of income and cash flows for the years ended December
31, 1996, 1995 and 1994 include BNSF's results and cash flows for the year ended
December 31, 1996, BNI's results and cash flows for the years ended December 31,
1995 and 1994, and SFP's results and cash flows from September 22, 1995 through
December 31, 1995. All significant intercompany accounts and transactions have
been eliminated. The preparation of financial statements in accordance with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the periods
presented.

RECLASSIFICATIONS

Certain comparative prior year amounts in the consolidated financial statements
and notes have been reclassified to conform with the current year presentation.

CASH AND CASH EQUIVALENTS

All short-term investments with original maturities of less than 90 days are
considered cash equivalents. Cash equivalents are stated at cost, which
approximates market value.

MATERIALS AND SUPPLIES

Materials and supplies consist mainly of diesel fuel and repair parts for
equipment and other railroad property and are valued at the lower of average
cost or market.

PROPERTY AND EQUIPMENT

Property and equipment are depreciated and amortized on a straight-line basis
over their estimated useful lives. Upon normal sale or retirement of depreciable
railroad property, cost less net salvage is charged to accumulated depreciation
and no gain or loss is recognized. Significant premature retirements are
recorded as gains or losses at the time of their occurrence. Expenditures which
significantly increase asset values or extend useful lives are capitalized.
Repair and maintenance expenditures are charged to operating expense when the
work is performed. Property and equipment are stated at cost including property
values of SFP, which were adjusted in applying purchase accounting.
Additionally, the Company incurs certain direct labor, contract service,
purchased software and other costs associated with the development and
installation of computer software. Costs for newly developed software or
significant enhancements to existing software are typically capitalized.
Research, operations and maintenance costs are charged to operating expense when
the work is performed.

REVENUE RECOGNITION

Transportation revenues are recognized based upon the proportion of service
provided.
6

<PAGE>

EARNINGS PER COMMON SHARE

Primary earnings per common share are computed by dividing net income, after
deduction of preferred stock dividends, by the weighted average number of common
shares and common share equivalents outstanding. Common share equivalents are
computed using the treasury stock method. Fully diluted earnings per common
share are computed by dividing net income by the weighted average number of
common shares and common share equivalents outstanding. During 1995 and 1994,
the if-converted method was used for convertible preferred stock when computing
fully diluted earnings per common share. For the year ended December 31, 1995,
the computation of fully diluted earnings per share was antidilutive; therefore,
the amounts reported for primary and fully diluted earnings per share were the
same.

2. ACQUISITION OF SFP

On June 29, 1994, BNI and SFP entered into an Agreement and Plan of Merger (as
amended, the Merger Agreement) pursuant to which SFP would merge with BNI in the
manner set forth below (the Merger). Stockholders of BNI and SFP approved the
Merger Agreement at special stockholders' meetings held on February 7, 1995. On
August 23, 1995, the Interstate Commerce Commission issued a written decision
approving the Merger and on September 22, 1995 the Merger was consummated.

Pursuant to the Merger Agreement, BNI and SFP commenced tender offers
(together, the Tender Offer) to acquire 25 million and 38 million shares of SFP
common stock, respectively, at $20 per share in cash. During 1995, SFP borrowed
$1.0 billion under a credit facility of which $760 million of the proceeds were
used to purchase the 38 million shares pursuant to the Tender Offer. In
addition, BNI borrowed $500 million under a credit facility to finance BNI's
purchase of SFP common stock in the Tender Offer. The Tender Offer was completed
on February 21, 1995.

To ensure that the transaction contemplated by the Merger Agreement qualified
as a tax-free transaction for federal income tax purposes, the parties utilized
the holding company structure. Under the holding company structure, BNSF created
two subsidiaries. One subsidiary merged with and into BNI, and the other
subsidiary merged with and into SFP. The holding company structure had the same
economic effect with respect to the stockholders of BNI and SFP as would have a
direct merger of BNI and SFP.

The 1995 business combination with SFP was accounted for by the purchase
method. As such, the accompanying consolidated financial statements include
assets, liabilities and financial results of SFP after Merger consummation. The
following summarizes the purchase price (dollars in millions, except per share
data, and shares in thousands):

<TABLE>

<S> <C> <C>
BNI investment in SFP at September 22, 1995 $ 516
Shares of SFP common stock outstanding
at September 22, 1995 151,396
Less SFP shares held by BNI (25,000)
--------
Remaining SFP shares outstanding 126,396
Exchange ratio .4114
--------
Shares of BNSF common stock issued 52,000
Per share value of BNSF common stock $ 51
--------
Total value of BNSF common stock issued 2,652
Value of outstanding SFP stock options 119
BNI direct acquisition costs 32
--------
Purchase price $ 3,319
========
</TABLE>

<PAGE>

The purchase price was calculated based on an estimated fair value of BNSF
common stock of $51 per share. The fair value was determined from the average of
the daily closing prices of BNI common stock for the five trading days
immediately preceding and the five trading days immediately following approval
of the Merger by BNI and SFP shareholders which occurred on February 7, 1995.

The effects of the acquisition on the consolidated balance sheet, including the
fair value adjustments, were as follows (in millions):
<TABLE>
<S> <C>
Property and equipment, net $ 9,409
Other assets 886
Deferred income taxes (2,936)
Long-term debt (2,034)
Other liabilities (2,006)
-------
Net assets acquired $ 3,319
=======
</TABLE>
The purchase price allocation included $138 million for anticipated
nonrecurring costs and expenses for severance and relocation of prior SFP
employees and the planned disposition of excess SFP office space and other SFP
assets.

The consolidated pro forma results presented below were prepared as if the
Merger had occurred on January 1, 1994 and include the historical results of BNI
and SFP, excluding the after-tax effect of $309 million for merger-related
charges recorded by BNI in 1995. Additionally, the consolidated pro forma
results include the effects of purchase accounting adjustments and the Tender
Offer. Pro forma adjustments reflecting merger benefits are not included. This
unaudited consolidated pro forma information is not necessarily indicative of
the results of operations that might have occurred had the Merger actually taken
place on the date indicated, or of future results of operations of the combined
entities (dollars in millions, except per share data):

<TABLE>
<CAPTION>
Year ended December 31, 1995 1994
- ----------------------- ------ ------
<S> <C> <C>
Revenues $8,150 $7,657
Operating expenses 6,824 6,465
Income before extraordinary items 605 536
Net income(1) 499 549
Primary earnings per share:
Income before extraordinary items $ 4.00 $ 3.63
Net income 3.27 3.72
Fully diluted earnings per share:
Income before extraordinary items $ 3.94 $ 3.59
Net income 3.25 3.67
</TABLE>

(1) Pro forma 1995 results include approximately $230 million (pre-tax) related
to the merger severance and asset charge which are not considered directly
attributable to the Merger. Additionally, pro forma net income includes the $100
million cumulative effect for the change in accounting for locomotive overhauls
for years prior to 1995 and a $25 million reduction for the effect of the change
on 1995. Also, 1995 pro forma net income includes the $6 million extraordinary
charge for retirement of debt. Pro forma 1994 net income includes a $10 million
reduction for a change in accounting.

3. MERGER, SEVERANCE AND ASSET CHARGES

Included in the Consolidated Statement of Income for 1995 were operating
expenses of $735 million related to merger, severance and asset costs.
Significant components included in these costs are described below.

<PAGE>

Employee-related costs of $287 million were recorded related to BNSF's plan to
centralize the majority of its union clerical functions which was approved in
1995. This plan includes the reduction of approximately 1,600 employees which,
among other things, requires installation of common information systems. The
Company and the union entered into an implementation agreement which allows the
Company to abolish the positions and provide separation benefits to affected
employees. Benefits paid to affected employees may be in the form of lump-sum
payments or payments made over several years depending on the seniority level
and election of the employee. Implementation of the plan began in 1996;
however, the plan is not expected to be fully implemented until 1998
due to the geographical complexity of the combined rail system, and the time
required to finish development and installation of common systems. Approximately
500 positions were abolished in 1996 and the remaining position reductions are
expected to occur during 1997 and 1998. No comparable costs were accrued in
applying purchase accounting, as ATSF's operations had previously been
centralized. Also, no provision for voluntary separation or severance costs
above those provided was included in the 1995 charge. Presently, the magnitude
of any future expense is unknown. Additionally, relocation costs for clerical
employees are charged to expense in the period incurred.

Costs of $254 million were recorded for salaried employees and reflect
severance, pension and other employee benefits, and costs for employee
relocations incurred during the period. Severance, pension and other employee
benefit costs of $231 million reflect the elimination of approximately 1,000
former BNI employees. Most of these positions were eliminated in 1995 and 1996.
Additional components of salaried employee costs include special termination
benefits to be received under the Company's retirement plan and expenses related
to restricted stock which vested upon approval of the Merger. Relocation
expenses of $23 million reflect costs incurred in 1995 for relocating
approximately 300 former BNI employees.

Costs of $105 million were included for branch line dispositions reflecting
the write-off of the net book value of the lines at the anticipated disposal
date, less estimated net proceeds. Approximately 75 line segments, covering
3,300 miles of former BNI lines were included, of which approximately 2,000
miles were disposed of during 1996. Remaining costs of $89 million included in
the $735 million charge related to obligations at leased facilities, a majority
of which have been vacated, and the write-off of duplicate and excess assets
including computer hardware and software and certain facilities.

Additional accruals of $138 million were recorded through purchase accounting
related to former SFP employees and assets. Approximately $105 million of these
costs related to termination of approximately 500 salaried employees for
severance payments and special termination benefits to be received under the
Company's retirement and health and welfare plans. Salaried employee costs also
include amounts to relocate approximately 500 former SFP employees. The
remaining $33 million of costs relate to the sale or abandonment of 500 miles of
branch lines, rents on vacated leased facilities and the write-off of excess
assets.

Current and long-term employee merger and separation liabilities totaling $580
million are included in the consolidated balance sheet at December 31, 1996 and
principally represent employee-related costs for the centralization of clerical
functions, as well as remaining liabilities for actions taken by ATSF in prior
periods. The majority of these prior ATSF costs are associated with deferred
benefits payable upon separation or retirement to certain active conductors and
trainmen incurred in connection with an agreement which, among other things,
reduced crew sizes. Additionally, certain locomotive engineers are eligible for
a deferred benefit payable upon separation or retirement, associated with an
agreement with ATSF which allowed for more flexible work rules.

During 1996, BNSF paid $183 million for i) employee merger and separation
payments, principally related to the reduction of approximately 1,000 salaried
employees and 500 clerical employees, ii) salaried employee relocations
committed to in 1995, and iii) deferred benefits for ATSF conductors, trainmen
and locomotive engineers. At December 31, 1996, $114 million of the remaining
accrual is included within current liabilities for anticipated costs to be paid

9
<PAGE>

in 1997. The remaining costs are expected to be paid over the next several
years, except for certain costs related to conductors, trainmen and locomotive
engineers of ATSF which will be paid upon the employees' separation or
retirement, as well as certain benefits for clerical employees which may be paid
on an installment basis, generally over five to ten years.

4. ACCOUNTING CHANGES

Effective January 1, 1995, BNSF changed its method of accounting for periodic
major locomotive overhauls. Under the new method, costs of owned locomotives
relating to components requiring major overhaul are depreciated, on a straight-
line basis, to the first major overhaul date. The remaining cost of the owned
locomotive is depreciated, on a straight-line basis, over the estimated economic
life of the locomotive.

The cost of overhauls on owned units are then capitalized when incurred and
depreciated, on a straight-line basis, until the next anticipated overhaul. In
addition, estimated costs for major overhauls on leased units are accrued on a
straight-line basis over the life of the leases. BNSF previously expensed
locomotive overhauls when the costs were incurred. BNSF believes that this
change is preferable because it improves the matching of expenses incurred to
revenues earned. The cumulative effect of this change on years prior to 1995 was
a reduction in net income of $100 million (net of a $63 million income tax
benefit), or $.94 per share (primary and fully diluted). The effect of this
change for the year ended December 31, 1995, was to reduce income before
extraordinary item and cumulative effect of change in accounting method by $25
million or $.23 per share (primary and fully diluted). The pro forma effect of
this change on 1994 would have been to reduce net income by $26 million or $.29
per share primary, and $.27 per share fully diluted.

Effective January 1, 1994, BNSF adopted Statement of Financial Accounting
Standards (SFAS) No. 112, "Employers' Accounting for Postemployment Benefits."
The cumulative effect, net of $7 million income tax benefit, of this change in
accounting attributable to years prior to 1994, was to decrease 1994 net income
by $10 million, or $.11 per common share.

5. OTHER INCOME (EXPENSE), NET

Other income (expense), net includes the following (in millions):

Year ended December 31, 1996 1995 1994
- ------------------------------------------ ----- ----- -----
<S> <C> <C> <C>
Equity in earnings of pipeline partnership $ 24 $ 9 $ --
Gain on property dispositions 23 12 15
Interest income 2 8 3
Accounts receivable sale fees (14) (4) (9)
BNI's equity in earnings of SFP prior
to consummation of the Merger -- 16 --
Miscellaneous, net (42) (13) (12)
- ------------------------------------------ ----- ----- -----
Total $ (7) $ 28 $ (3)
===== ===== =====
</TABLE>

10
<PAGE>

6. INCOME TAXES

Income tax expense, excluding the cumulative effect of change in
accounting method and extraordinary item, was as follows (in millions):
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
- ----------------------- ----- ----- -----
<S> <C> <C> <C>
Current:
Federal $ 81 $ 216 $ 124
State 17 32 19
----- ----- -----
98 248 143
----- ----- -----
Deferred:
Federal 396 (101) 109
State 57 (11) 17
----- ----- -----
453 (112) 126
----- ----- -----
Total $ 551 $ 136 $ 269
===== ===== =====
</TABLE>
Reconciliation of the federal statutory income tax rate to the effective tax
rate, excluding the cumulative effect of change in accounting method and
extraordinary item, was as follows:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
- ------------------------------------------------------- ------ ------- -------
<S> <C> <C> <C>
Federal statutory income tax rate 35.0% 35.0% 35.0%
State income taxes,
net of federal tax benefit 3.4 4.0 3.4
Other, net (0.1) 1.7 0.3
- ------------------------------------------------------- ------ ------- -------
Effective tax rate 38.3% 40.7% 38.7%
- ------------------------------------------------------- ====== ======= =======
The components of deferred tax assets and liabilities
were as follows (in millions):
December 31, 1996 1995
- ------------------------------------------------------- ------- -------
Deferred tax liabilities:
Depreciation and amortization $(5,110) $(5,076)
Other (397) (249)
- ------------------------------------------------------- ------- -------
Total deferred tax liabilities (5,507) (5,325)
- ------------------------------------------------------- ------- -------
Deferred tax assets:
Casualty and environmental liabilities 300 360
Employee merger and separation costs 214 359
Postretirement benefits 96 88
Non-expiring AMT credit carryforwards 44 124
Pensions 16 69
Other 415 412
- ------------------------------------------------------- ------- -------
Total deferred tax assets 1,085 1,412
- ------------------------------------------------------- ------- -------
Net deferred tax liability $(4,422) $(3,913)
- ------------------------------------------------------- ======= =======
Noncurrent deferred income tax liability $(4,729) $(4,233)
Current deferred income tax asset 307 320
- ------------------------------------------------------- ------- -------
Net deferred tax liability $(4,422) $(3,913)
- ------------------------------------------------------- ======= =======
</TABLE>
11

<PAGE>

In 1996 and 1994, tax expense of $9 million and $6 million, respectively,
related to the adjustment to reduce the minimum pension liability was allocated
directly to stockholders' equity. In 1995, tax benefits of $11 million related
to the adjustment to recognize the minimum pension liability was allocated
directly to stockholders' equity.

BNSF filed its first federal consolidated income tax return for 1995. BNI's
and SFP's federal income tax returns have been examined through 1991 and 1992,
respectively. All years prior to 1986 are closed for BNI and SFP. Issues
relating to the years 1986-1992 are being contested through various stages of
administrative appeal. In addition, BNSF and its subsidiaries have various state
income tax returns in the process of examination, administrative appeal or
litigation. Management believes that adequate provision has been made for any
adjustment that might be assessed for open years through 1996.

7. ACCOUNTS RECEIVABLE, NET

A special purpose subsidiary of BNSF Railway has sold, with limited recourse,
variable rate certificates which mature in December 1999 evidencing undivided
interests in an accounts receivable master trust. The master trust's assets
include an ownership interest in a revolving portfolio of BNSF Railway's
accounts receivable which are used to support the certificates. At December 31,
1996, $280 million of certificates sold were outstanding and were supported by
receivables in the master trust of $347 million. A maximum of $300 million of
certificates can be sold if the master trust balance is increased by receivables
which are eligible for sale. BNSF Railway has retained the collection
responsibility with respect to the accounts receivable held in trust. BNSF
Railway is exposed to credit loss related to collection of accounts receivable
to the extent that the amount of receivables in the master trust
exceeds the amount of certificates sold. Upon the merger of ATSF and BNRR,
BNRR's receivables were added to the accounts receivable master trust, effective
January 1, 1997, but the $300 million maximum amount of certificates which can
be sold was not increased. Costs related to such agreements vary on a monthly
basis and are generally related to certain interest rates. These costs are
included in Other income (expense), net.

BNSF maintains an allowance for doubtful accounts based upon the expected
collectibility of all accounts receivable, including accounts receivable sold.
Allowances for doubtful accounts of $57 million and $50 million have been
recorded at December 31, 1996 and 1995, respectively.

8. PROPERTY AND EQUIPMENT, NET

Property and equipment, net (in millions), and the weighted average annual
depreciation rate (%) was as follows:

<TABLE>
<CAPTION>
Depreciation
December 31, 1996 1995 Rate-1996
- -------------------------------- -------- ------- -------------
<S> <C> <C> <C>
Land $ 1,418 $ 1,379 --
Track structure 9,668 8,951 3.5%
Other roadway 7,231 6,598 2.8
Locomotives 1,525 1,231 6.9
Freight cars and other equipment 1,879 1,856 4.5
Computer hardware and software 402 319 18.1
- -------------------------------- -------- ------- -------------
Total cost 22,123 29,334
Less accumulated depreciation
and amortization (4,490) (4,333)
- -------------------------------- -------- -------
Property and equipment, net $17,633 $16,001
======== =======
</TABLE>

The consolidated balance sheet at December 31, 1996 and 1995 included $471
million and $200 million, respectively, for property and equipment under capital
leases.

In the first quarter of 1996, BNSF adopted SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
The adoption of SFAS No. 21 had no impact on the Company's financial position
or 1996 results of operations.

<PAGE>

9. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES

Accounts payable and other current liabilities consisted of the following (in
millions):

December 31, 1996 1995
- ---------------------------------------------------- -------- -------
<S> <C> <C>
Accounts and wages payable $ 581 $ 519
Casualty and environmental liabilities 267 290
Accrued vacations 148 141
Taxes other than income taxes 125 143
Equipment leases 118 83
Employee merger and separation costs 114 215
Other 793 898
- ---------------------------------------------------- ------ ------
Total $2,146 $2,289
====== ======
</TABLE>

10. DEBT

Debt outstanding was as follows (in millions):

December 31, 1996 1995
- ---------------------------------- ------- --------
<S> <C> <C>
Notes and Debentures
7% debentures, due 2025 $ 350 $ 350
6 3/8% notes, due 2005 300 300
Pipeline exchangeable debentures,
11.2% (variable), due 2010 219 219
8 3/4% debentures, due 2022 200 200
7.29% debentures, due 2036 200 --
6 7/8% debentures, due 2016 175 --
7.40% notes, due 1999 150 150
7% notes, due 2002 150 150
7 1/2% debentures, due 2023 150 150
8 3/8% notes, due 2001 100 100
8 5/8% notes, due 2004 100 100
Other 28 29
Mortgage Bonds
Consolidated mortgage bonds,
3 1/5% to 9 1/4%, due 2006 to 2045 321 321
General mortgage bonds, 3 1/8% and
2 5/8%, due 2000 and 2010, respectively 62 62
Prior lien railway and land grant bonds,
4%, due 1997 57 57
General lien railway and land grant bonds,
3%, due 2047 35 35
Mortgage notes, 10.325%, due 1997 to 2014 31 32
First mortgage bonds, series A, 4%, due 1997 20 20
Mortgage notes, 8 5/8%, due 2008 18 20

Commercial Paper and Bank Borrowings
Commercial paper, 5.6% (variable) 907 985
Bank borrowings, 5.6% (variable) 65 85
Equipment Obligations
Equipment obligations, weighted average
rate of 8.02%, due 1997 to 2013 629 661
Capitalized lease obligations, weighted
average rate of 6.87%, expiring 1997
to 2009 400 154
Unamortized purchase accounting adjustment 101 114
Unamortized discount (57) (61)
- ------------------------------------------ ------ ------
Total $4,711 $4,233
Less: Current portion of long-term debt (165) (80)
- ------------------------------------------ ------ ------
Long-term debt $4,546 $4,153
====== ======
</TABLE>

13
<PAGE>

BNSF maintains a program for the issuance, from time to time, of commercial
paper. These borrowings are supported by bank revolving credit agreements.
Outstanding commercial paper balances are considered as reducing available
borrowings under these agreements. The bank revolving credit agreements allow
borrowings of up to $500 million on a short-term basis and $1.5 billion on a
long-term basis. Annual facility fees are currently .075 percent and .11
percent, respectively, and are subject to change based upon changes in BNSF's
senior unsecured debt ratings. Borrowing rates are based upon i) LIBOR plus a
spread based upon BNSF's senior unsecured debt ratings, ii) money market rates
offered at the option of the lenders, or iii) an alternate base rate. The
commitments of the lenders to make loans are currently scheduled to expire on
November 14, 1997 and November 15, 2001, respectively. At December 31, 1996,
there were no borrowings against the long-term revolving credit agreement, and
the maturity value of commercial paper outstanding was $916 million, leaving a
total of $584 million of the long-term revolving credit agreement available and
$500 million of the short-term revolving credit agreement available. A
significant portion of commercial paper has been hedged to fixed interest rates
through interest rate swap transactions (see Note 12: Hedging activities, leases
and other commitments).

The financial covenants of the bank revolving credit agreements require that
BNSF's consolidated tangible net worth, as defined in the agreements, be at
least $4.4 billion, and that its debt cannot exceed 55 percent of its
consolidated total capital, as defined in the agreements. BNSF was in compliance
with these financial covenants at December 31, 1996.

In February 1996, BNSF issued $175 million of 6.875% debentures due February
15, 2016. In June 1996, BNSF issued $200 million of 7.29% debentures due June
1, 2036. The net proceeds from the sale of these debentures were used for
general corporate purposes including the repayment of short-term debt. Both
debentures were issued under a BNSF shelf registration which, after being
increased by $500 million during the year, has $475 million remaining. In
October 1996, BNSF filed a prospectus supplement under this shelf registration
to provide for the issuance from time to time of up to $475 million principal
amount of the Company's Series A medium-term notes.

In December 1995, BNSF issued $300 million of 6 3/8% notes due December 15,
2005 and $350 million of 7% debentures due December 15, 2025 under the shelf
registration statement. The net proceeds from the sale of the notes and
debentures were used for general corporate purposes, including but not limited
to the repayment of commercial paper and short-term bank loans. During the
course of 1995, the Company entered into various interest rate swap agreements
with a principal amount of $500 million, for the purpose of establishing rates
in anticipation of debt issuances under the shelf registration statement. The
swaps were anticipated to hedge $250 million of 10-year debt and $250 million of
30-year debt. In conjunction with the fourth quarter 1995 issuance of 10-year 6
3/8% notes and 30-year 7% debentures, the Company closed out the swap
transactions which resulted in losses of $13 million and $15 million,
respectively. The losses were deferred and are being recognized over the term of
the borrowings.

Additionally, in December 1995, BNSF defeased its 9% debentures by placing
$166 million of U.S. government securities into an irrevocable trust for the
purpose of repaying the debentures in April 1996. The defeasance of debt
resulted in an extraordinary charge of $6 million, net of applicable income tax
benefits of $3 million, principally reflecting the call premium on the debt.

In 1996, BNRR and ATSF completed cross-border leveraged leases of equipment
for a total amount of $311 million which were recorded as capital lease
obligations. These transactions included the issuance of $242 million of
equipment secured debt. In 1995, BNRR completed cross-border leveraged leases of
equipment for a total amount of $136 million which were recorded as capital
lease obligations. These transactions included the issuance of $108 million of
equipment secured debt.

In November 1994, BNRR entered into a $150 million three-year term loan
facility agreement. In November 1995, this debt was repaid through the issuance
of commercial paper by BNRR. In May 1994, BNI issued $150 million of 7.4% notes
due May 15, 1999.

Aggregate long-term debt scheduled maturities are $165 million, $98 million,
$237 million, $116 million and $1,154 million for 1997 through 2001,
respectively. Commercial paper borrowings of $907 million are included in
maturities for 2001.

14
<PAGE>

Substantially all BNSF Railway properties and certain other assets are pledged
as collateral to, or are otherwise restricted under, the various BNSF Railway
long-term debt agreements. Equipment obligations and capital leases are secured
by the underlying equipment.

In addition, an indirect wholly-owned subsidiary of BNSF is contingently
liable as general partner for $355 million of long-term debt issued by Santa Fe
Pacific Pipeline Partners, L.P. (Pipeline Partnership). The subsidiary holds a
42 percent limited partner interest and a 2 percent general partner interest in
the Pipeline Partnership which it accounts for under the equity method. The
pipeline exchangeable debentures are exchangeable for BNSF's limited partnership
interest in the Pipeline Partnership. BNSF's investment in the
Pipeline Partnership was $283 million and $291 million at December 31, 1996 and
1995, respectively.

11. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of BNSF's financial instruments at December 31, 1996
and 1995 and the methods and assumptions used to estimate the fair value of each
class of financial instruments held by BNSF, were as follows:

CASH AND CASH EQUIVALENTS

The carrying amount approximated fair value because of the short maturity of
these instruments.

LONG-TERM DEBT AND COMMERCIAL PAPER

The fair value of BNSF's long-term debt was primarily based on quoted market
prices for the same or similar issues, or on the current rates that would be
offered to BNSF for debt of the same remaining maturities. The carrying amount
of commercial paper approximated fair value because of the short maturity of
these instruments. The carrying amounts of BNSF's long-term debt and commercial
paper at December 31, 1996 and 1995 were $4,711 million and $4,233 million,
respectively, while the estimated fair values at December 31, 1996 and 1995 were
$4,721 million and $4,412 million, respectively.

12. HEDGING ACTIVITIES, LEASES AND OTHER COMMITMENTS
HEDGING ACTIVITIES
FUEL

BNSF has a program to hedge against fluctuations in the price of its diesel
fuel purchases. This program includes various commodity swap transactions which
are accounted for as hedges. Any gains or losses associated with changes in
market value of these hedges are deferred and recognized as a component of fuel
expense in the period in which the hedged fuel is purchased and used. To the
extent BNSF hedges portions of its fuel purchases, it may not fully benefit from
decreases in fuel prices.

As of February 7, 1997, BNSF had entered into fuel swaps for approximately 635
million gallons at an average price of approximately 54 cents per gallon. These
contracts have expiration dates ranging from March 1997 to December 1998.

The above price does not include taxes, fuel handling costs, certain
transportation costs and any differences which may occur from time to time
between the prices of commodities hedged and the purchase price of BNSF's diesel
fuel.

BNSF's fuel hedging program covers approximately 35 percent of estimated 1997
fuel purchases and 25 percent of estimated 1998 fuel purchases. Quarterly hedges
in 1997 range from 20 percent to 40 percent of anticipated fuel purchases while
1998 hedges approximate 25 percent each quarter. Hedge positions are closely
monitored to ensure that they will not exceed actual fuel requirements in any
period. Unrecognized gains from BNSF's fuel hedging transactions were
approximately $17 million at December 31, 1996 and were not material at December
31, 1995. BNSF also monitors its hedging positions and credit ratings of its
counterparties and does not anticipate losses due to counterparty
nonperformance.

15
<PAGE>

INTEREST RATE

From time to time, the Company enters into various interest rate hedging
transactions for the purpose of managing exposure to fluctuations in interest
rates and establishing rates in anticipation of future debt issuances. As of
February 7, 1997, BNSF has interest rate swap transactions with a total
principal amount of $875 million to fix interest rates on commercial paper debt.
The interest rate swap transactions require payment of a weighted average fixed
interest rate of approximately 5.8 percent, and the receipt of a variable
interest rate based on a commercial paper composite rate. Swap transactions of
$625 million, $250 million and $125 million will mature during the years ended
December 31, 1997, 1998 and 1999, respectively. Unrecognized losses from BNSF's
swap transactions were immaterial at December 31, 1996. During 1995, the Company
closed out interest rate swap transactions in conjunction with the issuance of
debt (see Note 10: Debt).

LEASES

BNSF has substantial lease commitments for locomotives, freight cars,
trailers, office buildings and other property. Most of these leases provide the
option to purchase the equipment at fair market value at the end of the lease.
However, some provide fixed price purchase options. Future minimum lease
payments (which reflect leases having non-cancelable lease terms in excess of
one year) as of December 31, 1996 are summarized as follows (in millions):

<TABLE>
<CAPTION>
Capital Operating
Year ended December 31 Leases Leases
- --------------------------------------- ------- ---------
<S> <C> <C>
1997 $ 55 $ 322
1998 59 272
1999 55 216
2000 50 169
2001 50 142
Thereafter 311 1,284
- --------------------------------------- ------- ---------
Total 580 $2,405
Less amount representing interest 180 =========
- --------------------------------------- -------
Present value of minimum lease payments $400
=======

</TABLE>

Lease rental expense for all operating leases was $446 million, $352 million
and $276 million for the years ended December 31, 1996, 1995 and 1994,
respectively. Contingent rentals and sublease rentals were not significant.

OTHER COMMITMENTS

BNSF has entered into commitments to acquire 180 locomotives in
1997. The locomotives will be financed from one or a combination of sources
including, but not limited to, cash from operations, leases and debt issuances.
The decision on the method used will depend upon the current market conditions
and other factors.

In connection with the closing of the sale of rail lines in southern
California in 1992 and 1993, BNSF has entered into various shared use agreements
with the agencies, which require BNSF to pay the agencies approximately $6
million annually to maintain track structure and facilities. Additionally, BNSF
recorded a $50 million liability in 1993 for an obligation retained by BNSF,
which under certain conditions requires a repurchase of a portion of the
properties sold.

16
<PAGE>

13. ENVIRONMENTAL AND OTHER CONTINGENCIES
ENVIRONMENTAL

BNSF's operations, as well as those of its competitors, are subject
to extensive federal, state and local environmental regulation. BNSF's operating
procedures include practices to protect the environment from the environmental
risks inherent in railroad operations, which frequently involve transporting
chemicals and other hazardous materials. Additionally, many of BNSF's land
holdings are and have been used for industrial or transportation related
purposes or leased to commercial or industrial companies whose activities may
have resulted in discharges onto the property. As a result, BNSF is subject to
environmental clean-up and enforcement actions. In particular, the Federal
Comprehensive Environmental Response Compensation and Liability Act of 1980
(CERCLA), also known as the "Superfund" law, as well as similar state laws
generally impose joint and several liability for clean-up and enforcement costs
without regard to fault or the legality of the original conduct on current and
former owners and operators of a site. BNSF has been notified that it is a
potentially responsible party (PRP) for study and clean-up costs at
approximately 32 Superfund sites for which investigation and remediation
payments are or will be made or are yet to be determined (the Superfund sites)
and, in many instances, is one of several PRPs. In addition, BNSF may be
considered a PRP under certain other laws. Accordingly, under CERCLA and other
federal and state statutes, BNSF may be held jointly and severally liable for
all environmental costs associated with a particular site. If there are other
PRPs, BNSF generally participates in the clean-up of these sites through cost-
sharing agreements with terms that vary from site to site. Costs are typically
allocated based on relative volumetric contribution of material, the amount of
time the site was owned or operated, and/or the portion of the total site owned
or operated by each PRP.

Environmental costs include initial site surveys and environmental studies of
potentially contaminated sites as well as costs for remediation and restoration
of sites determined to be contaminated. Liabilities for environmental clean-up
costs are initially recorded when BNSF's liability for environmental clean-up is
both probable and a reasonable estimate of associated costs can be made.
Adjustments to initial estimates are recorded as necessary based upon additional
information developed in subsequent periods. BNSF conducts an ongoing
environmental contingency analysis, which considers a combination of factors
including independent consulting reports, site visits, legal reviews, analysis
of the likelihood of participation in and the ability of other PRPs to pay for
clean-up, and historical trend analyses.

BNSF is involved in a number of administrative and judicial proceedings and
other mandatory clean-up efforts at approximately 345 sites, including the
Superfund sites, at which it is being asked to participate in the study and/or
clean-up of the environmental contamination. BNSF paid approximately $47
million, $31 million and $21 million during 1996, 1995 and 1994, respectively,
relating to mandatory clean-up efforts, including amounts expended under federal
and state voluntary clean-up programs. BNSF has accruals of approximately $225
million for remediation and restoration of all known sites, including $215
million pertaining to mandated sites, of which approximately $55 million relates
to the Superfund sites. BNSF anticipates that the majority of the accrued costs
at December 31, 1996 will be paid over the next five years. No individual site
is considered to be material. Recoveries received from third parties, net of
legal costs incurred, were approximately $31 million during 1995 and were not
significant in the years ended December 31, 1996 and 1994.

Liabilities recorded for environmental costs represent BNSF's best estimates
for remediation and restoration of these sites and include both asserted and
unasserted claims. Unasserted claims are not considered to be a material
component of the liability. Although recorded liabilities include BNSF's best
estimates of all costs, without reduction for anticipated recoveries from third
parties, BNSF's total clean-up costs at these sites cannot be predicted with
certainty due to various factors such as the extent of corrective actions that
may be required, evolving environmental laws and regulations, advances in
environmental technology, the extent of other PRPs' participation in clean-up
efforts, developments in ongoing environmental analyses related to sites
determined to be contaminated, and developments in environmental surveys and
studies of potentially contaminated sites. As a result, future charges to income
for environmental liabilities could have a significant effect on results of
operations in a particular quarter or fiscal year as individual site studies and
remediation and restoration efforts proceed or as new sites arise. However,
expenditures associated with such liabilities are typically paid out over a long
period; therefore, management believes that it is unlikely that any identified
matters, either individually or in the aggregate, will have a material adverse
effect on BNSF's consolidated financial position or liquidity.

17
<PAGE>

The railroad industry, including BNSF Railway, will become subject to future
requirements regulating air emissions from diesel locomotives that may increase
their operating costs. Regulations applicable to new locomotive engines were
issued by the Environmental Protection Agency in early 1997, with final
regulations to be promulgated by the end of the year. It is anticipated that
these regulations will be effective for locomotive engines installed after 1999
and through 2010. Under some interpretations of federal law, older locomotive
engines may be regulated by states based on standards and procedures which the
State of California ultimately adopts. At this time, it is unknown whether
California will adopt locomotive emission standards that may differ from federal
standards.

OTHER CLAIMS AND LITIGATION

BNSF and its subsidiaries are parties to a number of legal actions and claims,
various governmental proceedings and private civil suits arising in the ordinary
course of business, including those related to environmental matters and
personal injury claims. While the final outcome of these items cannot be
predicted with certainty, considering among other things the meritorious legal
defenses available, it is the opinion of management that none of these items,
when finally resolved, will have a material adverse effect on the annual results
of operations, financial position or liquidity of BNSF, although an adverse
resolution of a number of these items could have a material adverse effect on
the results of operations in a particular quarter or fiscal year.

14. RETIREMENT PLANS

Prior to October 1, 1996, BNSF sponsored noncontributory, defined benefit
pension plans through its subsidiaries, BNI and SFP, covering substantially all
non-union employees. Additionally, BNI and SFP sponsored nonqualified defined
benefit plans for certain officers and other employees. On October 1, 1996, the
respective BNI and SFP qualified defined benefit pension plans were merged,
creating the qualified BNSF Retirement Plan. The corresponding nonqualified
defined benefit plans were merged on October 1, 1996, creating the nonqualified
BNSF Supplemental Retirement Plan. The benefits under BNSF's plans are based on
years of credited service and the highest five-year average compensation levels.
BNSF's funding policy is to contribute annually not less than the regulatory
minimum, and not more than the maximum amount deductible for income tax
purposes.

Components of the net pension cost for BNSF's plans, including the prior BNI
and SFP plans, were as follows (in millions):

<TABLE>
<CAPTION>
BNSF BNSF(1) BNI(2)
Year ended December 31, 1996 1995 1994
- -------------------------------------------------------------------------------- -------- ---------- --------
<S> <C> <C> <C>
Service cost, benefits earned during the period $ 17 $ 11 $ 12
Interest cost on projected benefit obligation 97 65 50
Actual return on plan assets (148) (114) (25)
Net amortization and deferred amounts 43 61 (1)
Curtailment costs -- 10 --
Cost of special termination benefits -- 32 --
- -------------------------------------------------------------------------------- -------- ---------- --------
Net pension cost $ 9 $ 65 $ 36
======== ========== ========
</TABLE>

(1) Represents full year BNI combined with SFP for the period from September 22,
1995 through December 31, 1995.

(2) Represents historical BNI only.

18
<PAGE>

The following table shows the reconciliation of BNSF's and SFP's funded status
of the qualified plans and BNI's qualified and nonqualified plans with amounts
recorded in the consolidated balance sheet (in millions):
<TABLE>
<CAPTION>
BNSF BNI SFP
December 31, 1996 1995 1995
- ------------------------------------------------------------------ ------- ------ -------
<S> <C> <C> <C>
Actuarial present value of benefit
Obligations:
Vested benefit obligation $(1,081) $(641) $ (547)
======= ====== =======
Accumulated benefit obligation $(1,161) $(696) $ (575)
- ------------------------------------------------------------------ ======= ====== =======
Projected benefit obligation $(1,247) $(758) $ (614)
Plan assets at fair value, primarily marketable equity and
debt securities 1,320 534 718
- ------------------------------------------------------------------ ------- ------ -------
Plan assets in excess of (less than) projected benefit obligation 73 (224) 104
Unrecognized net (gain) loss (63) 93 --
Unrecognized prior service cost (10) 2 --
Unamortized net transition obligation 15 20 --
Adjustment required to recognize minimum liability -- (53) --
- ------------------------------------------------------------------ ------- ------ -------
Prepaid (accrued) pension asset (liability) $ 15 $(162) $ 104
- ------------------------------------------------------------------ ======= ====== =======
</TABLE>

BNSF uses a September 30 measurement date. The prior BNI and SFP plans used
measurement dates of December 31 and September 30, respectively. The assumptions
used in accounting for the BNSF, BNI and SFP qualified and nonqualified plans
were as follows:

<TABLE>
<CAPTION>
BNSF BNI SFP BNI
1996 1995 1995 1994
- ------------------------------------------------ ------- ----- ------ ------
<S> <C> <C> <C> <C>
Discount rate 7.75% 7.0% 7.5 % 9.0%
Rate of increase in compensation levels 4.0 % 4.0% 4.0 % 5.5%
Expected long-term rate of return on plan assets 9.5 % 9.5% 9.75% 9.5%
</TABLE>
The following table shows the reconciliation of the BNSF and SFP funded status
of the nonqualified supplemental plan with amounts recorded in the consolidated
balance sheet (in millions):
<TABLE>
<CAPTION>
BNSF SFP
December 31, 1996 1995
- --------------------------------------------------- ------- ------
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefit obligation $ (31) $ (7)
- --------------------------------------------------- ======= ======
Accumulated benefit obligation $ (32) $ (8)
- --------------------------------------------------- ======= ======
Projected benefit obligation $ (39) $ (11)
- --------------------------------------------------- ------- ------
Unrecognized net loss 14 3
Unrecognized prior service cost 1 --
Unamortized net transition obligation 1 --
Adjustment required to recognize mininum liability (9) --
- --------------------------------------------------- ------- ------
Accrued pension liability $ (32) $ (8)
- --------------------------------------------------- ======= ======
</TABLE>
19
<PAGE>

Prior to December 31, 1996, BNSF sponsored 401(k) thrift and profit sharing
plans through its subsidiaries, BNI and SFP, which covered substantially all
non-union employees and certain union employees. The plans covering non-union
employees were merged on December 31, 1996. Under the merged plan, BNSF matches
50 percent of the first 6 percent of non-union employees' contributions, which
are subject to certain percentage limits of the employees' earnings, at each pay
period. Depending on BNSF's performance, an additional matching contribution of
up to 30 percent of the first 6 percent can be made at the end of the year. The
prior BNI plan matched 35 percent of the first 6 percent of non-union employees'
contributions, at the end of each quarter and depending on BNI's performance,
matched an additional 20 to 40 percent at the end of the year. The prior SFP
plan matched 100 percent of the first 4 percent of non-union employees'
contributions and 25 percent of the first 4 percent of union employees'
contributions. Under the prior plans, BNI employees were immediately fully
vested in the employer match, while SFP employees became vested on a five year
schedule based on length of service. As part of the transition to the BNSF plan,
former SFP employees became fully vested in the employee match made through
December 31, 1996. Employer contributions made subsequent to December 31, 1996,
for all non-union employees, are subject to the five year length of
service vesting schedule. BNSF's 401(k) matching expense was $13 million in 1996
and 1995, and $8 million in 1994.

15. OTHER POSTEMPLOYMENT BENEFIT PLANS

BNSF provides life insurance benefits to eligible former BNI non-union
employees. The life insurance plan is noncontributory and covers retirees only.
The postretirement benefit cost related to former BNI employees were $1 million
in each of the three years ended December 31, 1996, 1995 and 1994, respectively.

BNSF's policy is to fund benefits payable under the life insurance plan as
they come due. The accumulated postretirement benefit obligation related to the
former BNI plan was approximately $17 million at December 31, 1996 and 1995.

Salaried employees of the former SFP who have rendered 10 years of service
after attaining age 45 are eligible for both medical benefits and life insurance
coverage during retirement. The retiree medical plan is contributory and
provides benefits to retirees, their covered dependents and beneficiaries.
Retiree contributions are adjusted annually. The plan also contains fixed
deductibles, coinsurance and out-of-pocket limitations. The life insurance plan
is noncontributory and covers retirees only. Components of SFP's postretirement
benefit cost related to former SFP employees relating to its medical and life
insurance plans were as follows (in millions):

<TABLE>
<CAPTION>
Life Insurance Medical
Plan Plan
---------------- ---------------
1996 1995(1) 1996 1995(1)
<S> <C> <C> <C> <C>
Service cost $ -- $ -- $ 5 $ 1
Interest cost 4 1 12 3
Net amortization and deferred amounts -- -- -- (2)
- ---------------------------------------- ----- ------- ----- -----
Net postretirement benefit cost $ 4 $ 1 $ 17 $ 2
- ---------------------------------------- ===== ======= ===== =====
</TABLE>

(1) Includes only the components of postretirement benefit cost from
September 22, 1995 to December 31, 1995.

20
<PAGE>

BNSF's policy is to fund benefits payable under the medical and life insurance
plans as they come due. The following table shows the reconciliation of the
plans' obligations to amounts accrued at December 31, 1996 and 1995 (in
millions). The former SFP plan uses a September 30 measurement date.

Life Insurance Medical
Plan Plan
-------------- -------------
1996 1995 1996 1995
------ ------ ------ ----
<S> <C> <C> <C> <C>
Accumulated postretirement benefit obligation:
Retirees $ 43 $ 45 $ 119 $130
Fully eligible active participants -- -- 11 15
Other active participants 4 4 33 40
------ ------ ------ ----
47 49 163 185
Unrecognized net loss (1) (2) (3) (8)
- ---------------------------------------------- ----- ------ ------ ----
Accrued postretirement benefit cost $ 46 $ 47 $ 160 $177
===== ====== ====== ====
</TABLE>

For 1996, the assumed health care cost trend rate for managed care medical
costs is 10.5 percent and is assumed to decrease gradually to 5 percent by 2006
and remain constant thereafter. For medical costs not in managed care, the
assumed health care cost trend rate is 12 percent and is assumed to decrease
gradually to 5 percent by 2006 and remain constant thereafter. Increasing the
assumed health care cost trend rates by one percentage point would increase the
accumulated postretirement benefit obligation for the medical plan by $20
million and the combined service and interest components of net periodic
postretirement benefit cost recognized in 1996 by $2 million.

For 1996, the weighted-average discount rate assumed in determining the
accumulated postretirement benefit obligation was 7.75 percent and the assumed
weighted-average salary increase was 4.0 percent.

OTHER PLANS

Under collective bargaining agreements, BNSF participates in multiemployer
benefit plans which provide certain postretirement health care and life
insurance benefits for eligible union employees. Insurance premiums paid
attributable to retirees, which are generally expensed as incurred, were $14
million in 1996, $11 million in 1995 and $10 million in 1994.

16. STOCK OPTIONS, OTHER INCENTIVE PLANS AND OTHER STOCKHOLDERS' EQUITY
STOCK OPTIONS

Under BNSF's stock option plan, options may be granted to officers and salaried
employees at fair market value of the Company's common stock on the date of
grant. Approximately 7.4 million common shares were available for future grant
at December 31, 1996. All options expire within 10 years after the date of
grant. Shares issued upon exercise of options may be issued from treasury shares
or from authorized but unissued shares.

The Company applies Accounting Principles Board (APB) Opinion 25 and related
interpretations in accounting for its stock option plans. Accordingly, no
compensation expense has been recognized for its fixed stock option plans as the
exercise price equals the stock price on the date of grant. Had compensation
expense been determined for stock options granted in 1996 and 1995 based on the
fair value at grant dates consistent with SFAS No. 123 "Accounting for Stock
Based Compensation," the Company's pro forma 1996 net income and earnings per
share would have been $871 million and $5.58, respectively, and 1995 net income
and earnings per share would have been $84 million and $.59, respectively.

The pro forma amounts were estimated using the Black-Scholes option pricing
model with the following assumptions for 1996 and 1995:

<TABLE>
<CAPTION>
1996 1995
---------- -----------
<S> <C> <C>
Weighted average expected life (years) 3.0 3.0
Expected volatility 20% 20%
Annual dividend per share $ 1.20 $ 1.20
Risk free interest rate 6.11% 6.11%
Weighted average fair value of options granted $13.34 $ 9.41
------- ------
</TABLE>

<PAGE>

A summary of the status of the stock option plans as of December 31, 1996,
1995 and 1994, and changes during the years then ended, is presented below:

<TABLE>
<CAPTION>
1996 1995 1994
------------------------------ --------------------------- -------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Options Prices Options Prices Options Prices
- --------------------------- ----------- ---------- ----------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Balance at beginning of year 9,598,653 $ 37.44 4,119,731 $41.16 3,635,091 $38.24
Granted 2,439,380 75.77 1,026,414 58.20 752,690 54.15
Conversion of SFP 0ptions -- -- 5,342,024 29.86 -- --
Exercised (3,582,964) 34.37 (821,769) 31.27 (184,088) 33.42
Cancelled (199,784) 64.01 (67,747) 55.29 (83,962) 47.82
----------- ---------- ----------- -------- ---------- --------
Balance at end of year 8,255,285 $ 49.46 9,598,653 $37.44 4,119,731 $41.16
- --------------------------- =========== ========== =========== ======== ========== ========
Options exercisable at year
end 5,934,124 7,465,135 2,950,427
</TABLE>

The following table summarizes information regarding stock options outstanding
at December 31, 1996:

Range of Options Options Weighted Average Weighted
Exercise prices Outstanding Exercisable Remaining Life Exercise Prices
- ---------------- ----------- ----------- ---------------- ---------------
<S> <C> <C> <C> <C>
$09.04 to $24.27 2,216,025 2,216,025 5.2 years $19.76
$25.85 to $49.66 1,041,198 1,041,198 4.5 years $36.64
$50.58 to $73.88 2,655,216 2,655,216 7.3 years $56.04
$74.50 to $74.50 1,907,297 -- 9.1 years $74.50
$80.19 to $86.63 435,549 21,685 8.8 years $82.07(1)
--------- ---------
$09.04 to $86.63 8,255,285 5,934,124 6.9 years $39.18
========= =========
</TABLE>

(1) The weighted average exercise price of options outstanding approximates the
weighted average exercise price of options exercisable.

OTHER INCENTIVE PLANS

BNSF has other long-term incentive programs in addition to
stock options which are administered separately on behalf of employees.

BNSF shareholders adopted the BNSF 1996 Stock Incentive Plan and the Non-
Employee Directors' Stock Plan (NEDS), two omnibus stock plans, at the Annual
Meeting of Shareholders on April 18, 1996. Under the BNSF Stock Incentive Plan
and NEDS, up to 10,000,000 and 300,000 shares of BNSF common stock, respectively
have been authorized to be issued in the form of stock options, restricted
stock, performance shares and performance units.

During 1996, BNSF awarded a total of approximately 400,000 shares of
restricted stock to eligible employees and directors. No cash payment is
required by the individual.

Shares awarded under the plans may not be sold, transferred or used as
collateral by the holder until the shares awarded become free of restrictions.
The restrictions will be lifted in thirds over three years beginning on the
third anniversary of the grant date if certain stock-price-based performance
goals are met. If, however, the performance goals are not met, the restricted
shares will be forfeited. All shares still subject to restrictions are generally
forfeited and returned to the plan if the employee's or director's relationship
is terminated. A total of 369,000 restricted shares related to this award were
outstanding as of December 31, 1996.

<PAGE>

Additionally, under the BNSF 1996 Stock Incentive Plan certain eligible
employees may defer the cash payment of their bonus paid under the Incentive
Compensation Plan (ICP) and will receive restricted stock which restrictions
lapse in three years or in two years if certain performance goals are met. The
number of restricted shares awarded are based on the amount of bonus deferred,
plus incremental shares, using the market price of BNSF common stock on the date
of grant. Restricted awards granted under this program totaled 81,000 shares in
1996. A total of 220,000 awards were outstanding under this and prior programs
on December 31, 1996.

In addition, all regularly-assigned salaried employees not eligible to
participate in deferrals under the ICP are eligible to participate in the BNSF
Discounted Stock Purchase Program. This program allows employees to use their
bonus earned under the ICP to purchase BNSF common stock at a discount from the
market price and requires that the stock be restricted for a three-year period.
During the years ended December 31, 1996, 1995 and 1994, 29,000, 39,000 and
32,000 shares were purchased under this plan.

Compensation expense is recorded for these BNSF plans in accordance with APB
Opinion 25 and was not material in 1996, 1995 or 1994.

OTHER STOCKHOLDERS' EQUITY

As a result of the Merger, certain investments in third parties held by both BNI
and SFP, which were previously recorded on the cost method, were converted to
the equity method due to BNSF's combined ownership position and ability to
exercise significant influence. As such, $26 million, which is net of deferred
taxes of $17 million, was recorded in 1995 as an increase to retained earnings
to reflect BNI's undistributed equity in earnings since initial investment.
SFP's investments were adjusted to fair value upon the application of purchase
accounting.

17. COMMON STOCK AND PREFERRED CAPITAL STOCK
COMMON STOCK

BNSF is authorized to issue 300,000,000 shares of common stock, $.01
Par Value. At December 31, 1996, there were 154,001,966 shares of common stock
outstanding. Each holder of common stock is entitled to one vote per share in
the election of directors and on all matters submitted to a vote of
stockholders. Subject to the rights and preferences of any future issuance of
preferred stock, each share of common stock is entitled to receive dividends as
may be declared by the Board of Directors out of funds legally available and to
share ratably in all assets available for distribution to stockholders upon
dissolution or liquidation. No holder of common stock has any preemptive right
to subscribe for any securities of BNSF.

PREFERRED STOCK, SERIES A, $.01 PAR VALUE, AUTHORIZED 25,000,000 SHARES

In 1992, BNI issued 6,900,000 shares of 6 1/4% Cumulative Convertible Preferred
Stock, Series A, No Par Value. The convertible preferred stock was not
redeemable prior to December 1995. In September 1995, the outstanding BNI shares
were converted to 6,878,607 shares of BNSF 6 1/4 Cumulative Convertible
Preferred Stock, $.01 par value. In October 1995, the Board of Directors voted
to redeem BNSF's 6 1/4% Cumulative Convertible Preferred Stock, Series A, $.01
par value, effective December 26, 1995, at the redemption price of $52.1875 per
share. The majority of the holders of this preferred stock elected to convert
their shares into BNSF common stock as BNSF's common stock price was
significantly higher than the redemption price. As such, the cash payment for
shares redeemed was not significant.

CLASS A PREFERRED STOCK, $.01 PAR VALUE, AUTHORIZED 50,000,000 SHARES -- ZERO
SHARES ISSUED

At December 31, 1996, BNSF had available for issuance 50,000,000 shares of Class
A Preferred Stock, $.01 Par Value. The Board of Directors has the authority to
issue such stock in one or more series, to fix the number of shares and to fix
the designations and the powers, rights, and qualifications and restrictions of
each series.
23
<PAGE>

18. QUARTERLY FINANCIAL DATA -- UNAUDITED
(Dollars in millions, except per share data) Fourth Third Second First
- -------------------------------------------------------------- ---------- -------- ---------- ---------
<S> <C> <C> <C> <C>
1996
Revenues(1) $ 2,092 $ 2,044 $ 2,024 $ 2,027
Operating income 469 476 418 385
- -------------------------------------------------------------- ---------- -------- ---------- ---------
Net income $ 244 $ 247 $ 211 $ 187
- -------------------------------------------------------------- ---------- -------- ---------- ---------
Primary and fully diluted earnings per common share $ 1.56 $ 1.58 $ 1.35 $ 1.21
- -------------------------------------------------------------- ---------- -------- ---------- ---------
Dividends declared per common share $ .30 $ .30 $ .30 $ .30
Common stock price:
High $90 1/8 $86 3/4 $88 3/4 $87 1/8
Low 77 7/8 76 1/4 77 7/8 73 1/2

1995
Revenues(1) $ 2,087 $ 1,455 $ 1,279 $ 1,342
Operating income (loss)(2) (175) 254 242 205
Income (loss) before extraordinary item and
cumulative effect of change in accounting method (160) 133 124 101
Extraordinary item, loss on early retirement of debt,
net of tax(3) (6) -- -- --
Cumulative effect of change in accounting method, net of tax(4) -- -- -- (100)
- -------------------------------------------------------------- ---------- -------- ---------- ---------
Net income (loss) $ (166) $ 133 $ 124 $ 1
- -------------------------------------------------------------- ---------- -------- ---------- ---------
Primary earnings (loss) per common share:(4)
Income (loss) before extraordinary item and
change in accounting method $ (1.15) $ 1.32 $ 1.31 $ 1.05
Extraordinary item (0.04) -- -- --
Change in accounting method -- -- -- (1.11)
---------- -------- ---------- ---------
Primary earnings (loss) per common share $ (1.19) $ 1.32 $ 1.31 $ (0.06)
- -------------------------------------------------------------- ---------- -------- ---------- ---------
Fully diluted earnings (loss) per common share:(5)
Income (loss) before extraordinary item and
change in accounting method $ (1.15) $ 1.28 $ 1.26 $ 1.05
Extraordinary item (0.04) -- -- --
Change in accounting method -- -- -- (1.11)
- -------------------------------------------------------------- ---------- -------- ---------- ---------
Fully diluted earnings (loss) per common share $ (1.19) $ 1.28 $ 1.26 $ (0.06)
- -------------------------------------------------------------- ---------- -------- ---------- ---------
Dividends declared per common share $ .30 $ .30 $ .30 $ .30
Common stock price:
High $83 7/8 $76 1/4 $63 5/8 $60 1/8
Low 71 1/4 62 5/8 56 1/8 47 1/2
- -------------------------------------------------------------- ---------- -------- ---------- ---------
</TABLE>

(1) Amounts do not agree to previously reported amounts due to certain
reclassifications between revenues and expenses which were not significant.

(2) Results include pre-tax charges of $587 million, $106 million, $10 million
and $32 million for the fourth, third, second and first quarters of 1995,
respectively related to merger, severance and asset charges as discussed in
Note 3.

(3) Results for the fourth quarter include the loss on defeasance of BNI 9%
debentures of $6 million, net of $3 million income tax benefit, or $.04 per
share, treated as an extraordinary item.

(4) Effective January 1, 1995, BNSF changed its accounting for locomotive
overhauls. The cumulative effect of this change attributable to years prior
to 1995 was to decrease net income by $100 million, or $1.11 per share.

(5) Fully diluted earnings per share are antidilutive for the first and fourth
quarters of 1995; therefore, the amounts reported for primary and fully
diluted earnings per share are the same. Amounts do not total to the annual
earnings per share because each quarter and the year are calculated
separately based on average outstanding shares and common share equivalents
during that period.

<PAGE>

EXHIBIT 28.2

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

Management's discussion and analysis relates to the financial condition and
results of operations of Burlington Northern Santa Fe Corporation and its
majority-owned subsidiaries (collectively BNSF or Company). The principal
subsidiaries were Burlington Northern Inc. (BNI), Burlington Northern Railroad
Company (BNRR), Santa Fe Pacific Corporation (SFP) and The Atchison, Topeka and
Santa Fe Railway Company (ATSF). SFP and ATSF became subsidiaries of BNSF on
September 22, 1995 as a result of a business combination accounted for as a
purchase. Effective December 1996, BNI was merged with and into SFP, and ATSF
merged with and into BNRR and the name was changed to The Burlington Northern
and Santa Fe Railway Company (BNSF Railway).

RESULTS OF OPERATIONS

The results of operations discussed below include BNSF results for the year
ended December 31, 1996, BNI results for each of the two years ended December
31, 1995 and 1994 and SFP results from the merger date, September 22, 1995,
through December 31, 1995.

YEAR ENDED DECEMBER 31, 1996 COMPARED WITH YEAR ENDED DECEMBER 31, 1995

BNSF recorded net income for 1996 of $889 million ($5.70 per common share),
compared with net income of $92 million ($.67 per common share) for 1995.
Results for 1995 include $735 million of merger, severance and asset charges
which reduced net income by approximately $453 million, or $4.24 per common
share. Results for 1995 were further reduced by $100 million (after tax), or
$.94 per common share, for the cumulative effect of an accounting change for
locomotive overhauls and $6 million (after tax), or $.05 per common share, for
an extraordinary loss on early retirement of debt. Excluding the above items,
net income for 1995 would have been $651 million.

REVENUE TABLE

The following table presents BNSF's revenue information by commodity for the
years ended December 31, 1996, 1995 and 1994 and includes certain
reclassifications of prior year information to conform to current year
presentation.

<TABLE>
<CAPTION>
Revenues Revenue Ton Miles (RTM) Revenue Per Thousand RTM
------------------------------- ---------------------------- ----------------------------------
1996 1995 1994 1996 1995 1994 1996 1995 1994
(In Millions) (In Millions)
------ ------ ------ ------- ------- ------- ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Intermodal $2,088 $1,120 $ 758 71,262 38,516 24,671 $29.30 $29.08 $30.72
Coal 1,973 1,821 1,674 169,380 153,169 136,164 11.65 11.89 12.29
Agricultural Commodities 1,170 1,143 776 59,601 55,356 33,922 19.63 20.65 22.88
Chemicals 765 443 356 28,896 17,155 13,859 26.47 25.82 25.69
Forest Products 555 471 452 25,140 19,828 19,495 22.08 23.75 23.19
Consumer and Food Products 469 365 318 18,201 12,332 10,341 25.77 29.60 30.75
Metals 413 320 256 20,199 13,804 11,503 20.45 23.18 22.66
Automotive 397 213 156 6,062 3,158 2,031 65.49 67.45 76.81
Minerals and Ores 319 260 222 12,318 10,119 8,588 25.90 25.69 25.85
Other 38 7 8 -- -- -- -- -- --
------ ------ ------ ------- ------- ------- ------ ------ ------
Total $8,187 $6,163 $4,976 411,059 323,437 260,574 $19.82 $19.03 $19.07
====== ====== ====== ======= ======= ======= ====== ====== ======
</TABLE>

<PAGE>

REVENUES

Total revenues for 1996 were $8,187 million compared with revenues of $6,163
million for 1995. The $2,024 million increase primarily reflects inclusion of a
full year of SFP results in 1996. Prior to the business combination, coal and
agricultural made up approximately 50 percent of BNI's revenues while intermodal
shipments comprised approximately 45 percent of total SFP revenues.

Intermodal revenues increased $968 million compared with 1995, due to
inclusion of a full year of SFP operations. Prospectively, it is expected that
intermodal traffic will continue to represent a significant portion of BNSF's
revenues.

Coal revenues improved $152 million during 1996. Approximately 85 percent of
the increase was due to the inclusion of a full year of SFP operations.
Additionally, tonnage of low-sulfur coal shipped from the Powder River Basin
increased from 1995. Revenue per thousand revenue ton miles declined principally
as a result of continuing competitive pricing pressures and a change in traffic
mix.

Agricultural commodities revenues during 1996 were $27 million greater than
1995 reflecting a full year of SFP operations largely offset by lower export
shipments of wheat and corn.

Chemicals revenues increased $322 million compared with 1995. Approximately 90
percent of the increase was due to inclusion of a full year of SFP operations.
The remaining increase was due to strong petroleum products and agricultural
chemicals demand.

Revenue increases and changes in revenue per thousand revenue ton miles in all
other commodity groups were principally due to the inclusion of SFP results for
the full year.

EXPENSES

Total operating expenses for 1996 were $6,439 million compared with expenses of
$5,637 million for 1995. The operating ratio for 1996 was 78.6 percent, compared
with an operating ratio of 79.5 percent for 1995, excluding $735 million for
merger, severance and asset charges. The favorable decrease in the operating
ratio reflects synergies from combining operations which resulted in reduced
costs principally within administrative functions. These benefits were partially
offset by higher prices paid for labor, services and materials, including a
significant increase in the cost of diesel fuel during 1996.

Compensation and benefits expenses of $2,561 million were $494 million above
1995 principally due to the full year of combined operations. The Company began
to realize the benefit of the merger during 1996 as employment, which
approximated 43,000 at the end of 1996, decreased by 5 percent when compared
with the prior year. Salaried employee levels have decreased over 15 percent in
the same time period.

Purchased services expenses increased $273 million for 1996 compared with
1995, principally reflecting a full year of combined operations.

Depreciation and amortization expense for 1996 was $240 million higher than
1995 primarily due to the full year depreciation and amortization for combined
operations.

Equipment rents expenses were $196 million higher than 1995 due to the full
year combined operations as well as an increase in lease rental expense for
freight cars.

Fuel expenses for 1996 were $247 million or 51 percent higher than 1995
primarily due to an increase in consumption resulting from the full year of
combined operations and an 8 cent increase in the average price per gallon.

2
<PAGE>

Materials and other expenses for 1996 increased $87 million compared with
1995. The increase reflects the full year of combined operations partially
offset by decreases in expenses from cost initiatives including reductions in
employee injuries due to increased focus on employee safety.

As discussed in Note 3: Merger, severance and asset charges, the Company
recorded $735 million for such costs in 1995. The principal components of the
charge were $287 million related to BNSF's plan to centralize the majority of
its clerical functions and $254 million for severance, pension and other
salaried employee benefits and for employee relocation cost incurred during the
period. Additionally, $105 million was recorded for planned branch line
dispositions. The remaining $89 million included obligations for vacating leased
facilities and the write-off of duplicate and excess assets. Additional accruals
of $138 million were recorded through purchase accounting related to former SFP
employees and assets. When its plans are completed, BNSF expects to have
eliminated over 3,000 positions and disposed of approximately 4,000 miles of low
density track. To date, BNSF has eliminated approximately 1,500 salaried
positions and 500 clerical positions and has disposed of approximately 2,000
miles of low-density track. Also as described in Note 3, costs related to union
employee relocation as well as certain costs for separation and severances were
not included in the charge; therefore, these costs, to the extent incurred, will
be recorded as future operating expenses. Presently, the magnitude of any future
expense is unknown.

Interest expense increased $81 million compared with 1995, due to the full
year effect of interest on SFP debt in 1996 as well as an increase in the levels
of outstanding debt.

Other income net was $35 million below 1995. The decrease is due to a full
year of combined operations in 1996 as well as $16 million of equity in earnings
of SFP from February 21, 1995, the date of BNI's initial investment in SFP, to
September 22, 1995, the date of merger consummation.

YEAR ENDED DECEMBER 31, 1995 COMPARED WITH YEAR ENDED DECEMBER 31, 1994

BNSF recorded net income for 1995 of $92 million ($.67 per common share, primary
and fully diluted) compared with net income of $416 million ($4.37 per common
share, primary, and $4.27 per common share, fully diluted) for 1994. As
previously discussed, 1995 included the merger, severance and asset charges, the
accounting change for locomotive overhauls and the extraordinary loss on early
retirement of debt. Excluding these items, net income for 1995 would have been
$651 million. Results for 1994 were reduced by $10 million (after tax), or $.11
per common share, for the cumulative effect of an accounting change for
postemployment benefits. Excluding the accounting change, net income for 1994
would have been $426 million.

REVENUES

Total revenues for 1995 were $6,163 million compared with revenues of $4,976
million for 1994. The $1,187 million increase reflects $802 million of SFP
revenues for the period of September 22, 1995 through December 31, 1995.
Excluding SFP, revenues increased by $385 million or 8 percent primarily due to
higher coal and agricultural commodities revenues.

Intermodal revenues increased $362 million when compared with 1994, almost
exclusively due to the inclusion of SFP revenues in 1995.

Coal revenues improved $147 million during 1995 due to higher traffic levels
caused primarily by new business, favorable weather conditions early in the year
and increased demand for low-sulfur coal from the Powder River Basin as well as
the addition of $58 million of SFP revenues in 1995. Revenue per thousand
revenue ton miles declined as a result of continuing competitive pricing
pressures and a change in traffic mix.

3
<PAGE>

Agricultural commodities revenues during 1995 were $367 million greater than
1994. The increase was principally caused by improvements in corn and soybean
revenues which benefited from increased crop production as well as higher
traffic volumes to the Pacific Northwest due to stronger export demand during
1995. Barley and wheat revenues declined primarily due to weaker export demand
compared with the strong demand in 1994. Additionally, agricultural commodities
revenues included $59 million of SFP revenues during 1995. The shift in
commodities to lower yielding corn and soybeans from higher yielding wheat led
to the aggregate decrease in revenue per thousand revenue ton miles.

Revenues for chemicals increased $87 million and forest products increased $19
million compared with 1994. The addition of $80 million of SFP revenues along
with strong petroleum products demand contributed to the increase in chemicals
revenues. The increase in forest product revenues was due to the addition of $32
million of SFP revenues and was partially offset by lower traffic levels for
lumber.

Metals revenues increased $64 million due to increased taconite, aluminum and
steel products revenues as well as the addition of $28 million of SFP revenues
in 1995.

Revenue increases in all other commodity groups are principally due to the
inclusion of SFP revenues from September 22, 1995 to December 31, 1995.

EXPENSES

Total operating expenses for 1995, including $664 million of SFP
operating expenses and $735 million of merger, severance and asset charges, were
$5,637 million compared with expenses of $4,123 million for 1994. Excluding the
merger, severance and asset charges, the operating ratio for 1995 was 79.5
percent, an improvement over the operating ratio of 82.9 percent for 1994.

Compensation and benefits expenses of $2,067 million were $301 million above
1994 and included $233 million of SFP compensation and benefits expense. The
remaining $68 million of the increase was due to higher traffic levels, a wage
increase for union represented employees effective July 1994, an increase in
health and welfare costs for union employees due primarily to an increase in
insurance premium rates, and increased incentive compensation expense. These
increases were partially offset by operating efficiencies.

Purchased services expenses increased $64 million for 1995 compared with 1994,
principally reflecting the addition of SFP expenses.

Depreciation and amortization expense for 1995 was $158 million higher than
1994 primarily due to the inclusion of $86 million of SFP depreciation and
amortization expense for 1995. Additionally, the increase reflects $30 million
attributable to the 1995 effect of a change in accounting for locomotive
overhauls. The remainder of the increase was due to capital additions which
increased the Company's asset base.

Equipment rents expenses were $111 million higher than 1994 due to the
inclusion of $70 million of SFP equipment rents expense in 1995 as well as a $46
million increase in lease rental expense as a result of a larger fleet of leased
freight cars and an increase in the leasing of locomotives to meet power
requirements in 1995.

Fuel expenses for 1995 were $111 million higher compared with 1994 primarily
due to the addition of $74 million of SFP expenses along with a $29 million
increase in consumption resulting from higher traffic volumes in 1995. An
increase in the average price paid per gallon of 1.2 cents in 1995 contributed
to the remainder of the increase.

4
<PAGE>

Materials and other expenses for 1995 increased $34 million compared with
1994, principally reflecting the addition of SFP expenses and expenses
attributable to the change in accounting for locomotive overhauls in 1995.

Interest expense increased $65 million compared with 1994, principally due to
the addition of $26 million of SFP expense in 1995 as well as interest on the
$500 million of unsecured debt incurred in 1995 to finance BNI's investment in
SFP.

Other income (expense), net was $31 million favorable in 1995 compared with
1994. This increase was due to BNI's equity in earnings of SFP of $16 million.
The remainder of the increase in other income was principally due to interest
income on the settlement of a tax refund and lower fees on the sale of accounts
receivable in 1995.

In December 1995, BNSF defeased BNI's 9% debentures due 2016, by placing $166
million of U.S. government securities into an irrevocable trust for the purpose
of repaying the debentures in 1996. The defeasance resulted in an extraordinary
charge of $6 million (after tax), principally reflecting the call premium on the
debt.

Effective January 1, 1995, BNSF changed its method of accounting for periodic
major locomotive overhauls. Under the new method, overhauls on owned units are
capitalized and depreciated ratably until the next anticipated overhaul. In
addition, estimated costs for overhauls on leased units are accrued on a
straight-line basis over the life of the leases. BNSF previously expensed
locomotive overhauls when the costs were incurred. The cumulative effect of this
change for years prior to 1995 was a reduction in net income of $100 million
(after tax) while the effect of this change for the year ended December 31, 1995
was to reduce net income by $25 million (after tax).

ACQUISITION OF SFP

Pursuant to the Merger Agreement, BNI and SFP commenced tender offers
(together, the Tender Offer) to acquire 25 million and 38 million shares of SFP
common stock, respectively, at $20 per share in cash. During 1995, SFP borrowed
$1.0 billion under a credit facility of which $760 million of the proceeds were
used to purchase the 38 million shares pursuant to the Tender Offer. In
addition, BNI borrowed $500 million under a credit facility of which the
proceeds were used to finance BNI's purchase of SFP common stock in the Tender
Offer. The Tender Offer was completed on February 21, 1995.

CAPITAL RESOURCES AND LIQUIDITY
1996 CASHFLOWS

Cash generated from operations is BNSF's principal source of liquidity. BNSF
generally funds any additional requirements through debt issuance, including
commercial paper, or leasing of assets.

5
<PAGE>

Operating activities provided cash of $1,871 million during 1996 compared with
$1,416 million during 1995. The increase in cash from operations was primarily
attributable to higher earnings before depreciation and amortization, and
deferred income taxes as compared to 1995. The above was partially offset by an
increase in payments for employee, merger and separation costs and a net
increase in working capital.

BNSF's cash outflows from investing activities for 1996 predominantly
consisted of capital expenditures of $2,234 million which are further discussed
below, while cash inflows from financing activities reflect net proceeds from
borrowings of $445 million partially offset by dividend payments of $184
million.

OTHER CAPITAL RESOURCES

BNSF issues commercial paper from time to time. These borrowings are supported
by bank revolving credit agreements. Outstanding commercial paper balances are
considered as reducing available borrowings under these agreements. The bank
revolving credit agreements allow borrowings of up to $500 million on a short-
term basis and an additional $1.5 billion on a long-term basis. Annual facility
fees are currently .075 percent and .11 percent, respectively, and are subject
to change based upon changes in BNSF's senior unsecured debt ratings. Borrowing
rates are based upon, i) LIBOR plus a spread based upon BNSF's senior unsecured
debt ratings, ii) money market rates offered at the option of the lenders, or
iii) an alternate base rate. The commitments of the lenders to make the loans
are currently scheduled to expire on November 14, 1997 and November 15, 2001,
respectively.

At December 31, 1996, there were no borrowings against the revolving credit
agreements and the maturity value of commercial paper outstanding was $916
million, leaving a total of $584 million of the long-term revolving credit
agreement available and $500 million of the short-term revolving credit
agreement available.

CAPITAL EXPENDITURES AND RESOURCES

A breakdown of cash capital expenditures is set forth in the following table (in
millions):
<TABLE>
<CAPTION>

Year ended December 31, 1996 1995 1994
- ------------------------------------------ ------ ----- -----
<S> <C> <C> <C>
Track structure and other roadway property $1,625 $ 706 $ 544
Equipment 609 184 154
- ------------------------------------------ ------ ----- -----
Total capital expenditures $2,234 $ 890 $ 698
========================================== ====== ===== =====
</TABLE>
Track and other roadway capital expenditures for 1996 increased significantly
compared with 1995. This increase reflects a full year of capital projects
required to maintain the capacity of an expanded route system. Additionally,
BNSF significantly expanded capacity throughout its system in 1996, primarily in
the Powder River Basin and in the Pacific Northwest. Also as a result of the
merger of Union Pacific Railroad Company (UP) and Southern Pacific Rail
Corporation (SP) (discussed below) the Company purchased certain prior UP or SP
routes during 1996. Equipment capital expenditures increased in 1996 compared
with 1995 due principally to the purchase of 225 locomotives in 1996. During
1995, the Company acquired nearly all new locomotives through operating leases.
Additionally, equipment capital spending was higher in 1996 due to the ownership
of a substantially larger locomotive and car fleet.

6
<PAGE>

Capital expenditures in 1997 are expected to approximate $1.85 billion.
Approximately $1.1 billion of these expenditures will be for maintaining
productive capacity of the existing route structures. The remainder will be
spent on the acquisition of new equipment, including 180 locomotives, and
capacity expansion projects throughout the system including the Powder River
Basin and the Pacific Northwest.

INFLATION

Due to the capital intensive nature of BNSF's business the full effect
of inflation is not reflected in operating expenses because depreciation is
based on historical cost. An assumption that all operating assets were
depreciated at current price levels would result in substantially greater
expense than historically reported amounts.

DIVIDENDS

Common stock dividends declared were $1.20 per common share annually
for 1996, 1995 and 1994. Dividends paid on common stock during 1996 were $184
million, and $129 million on common and preferred stock during 1995 and 1994.
The increase in 1996 dividends reflects an increase in outstanding shares of
common stock principally due to the Merger. On January 16, 1997, the Board of
Directors declared a dividend of 30 cents per share upon its outstanding shares
of common stock, $.01 par value, payable April 1, 1997, to stockholders of
record on March 10, 1997.

CAPITAL STRUCTURE

BNSF's ratio of total debt to total capital was 44 percent at
the end of 1996 compared with 46 and 45 percent at the end of 1995 and 1994,
respectively.

OTHER MATTERS
CASUALTY AND ENVIRONMENTAL

Personal injury claims, including work-related injuries to employees, are a
significant expense for the railroad industry. Employees of BNSF are compensated
for work-related injuries according to the provisions of the Federal Employers'
Liability Act (FELA). For several years prior to 1992, the trend of significant
increases in BNSF's personal injury expense reflected the combined effects of
increasing frequency of claims, rising medical expenses, legal judgments and
settlements. FELA's system of requiring finding of fault, coupled with
unscheduled awards and reliance on the jury system, contributed to these
significant increases in expense in past years. BNSF implemented a number of
safety programs to reduce the number of personal injury claims and personal
injury expense. The total amount of personal injury expenses were $162 million,
$143 million, and $170 million in 1996, 1995 and 1994, respectively. Expenses in
1996 reflect a full year of combined operations while 1995 includes SFP expenses
from September 22, 1995 through December 31, 1995. Expenses in 1994 reflect only
BNI.

As discussed in more detail in Note 13: Environmental and other contingencies,
the Company's operations, as well as those of its competitors, are subject to
extensive federal, state and local environmental regulation. BNSF's operating
procedures include practices to protect the environment from the environmental
risks inherent in railroad operations, which frequently involve transporting
chemicals and other hazardous materials. Additionally, many of BNSF's land
holdings are and have been used for industrial or transportation-related
purposes or leased to commercial or industrial companies whose activities may
have resulted in discharges onto the property. As a result, BNSF is subject to
environmental clean-up and enforcement actions. In particular, the Federal

7
<PAGE>

Comprehensive Environmental Response Compensation and Liability Act of 1980,
also known as the "Superfund" law, as well as similar state laws generally
impose joint and several liability for clean-up and enforcement costs without
regard to fault or the legality of the original conduct on current and former
owners and operators of a site.

BNSF is involved in a number of administrative and judicial proceedings and
other mandatory clean-up efforts at approximately 345 sites at which it is being
asked to participate in the study and/or clean-up of alleged environmental
contamination. BNSF paid approximately $47 million, $31 million, and $21 million
during 1996, 1995 and 1994, respectively for mandatory clean-up efforts,
including amounts expended under federal and state voluntary clean-up programs.
BNSF has accruals of approximately $225 million for remediation and restoration
of all known sites. BNSF anticipates that the majority of the accrued costs at
December 31, 1996 will be paid over the next five years. No individual site is
considered to be material.

Liabilities recorded for environmental costs represent BNSF's best estimates
for remediation and restoration of these sites and include both asserted and
unasserted claims. Unasserted claims are not considered to be a material
component of the liability. Although recorded liabilities include BNSF's best
estimates of all costs, without reduction for anticipated recoveries from third
parties, BNSF's total clean-up costs at these sites cannot be predicted with
certainty due to various factors such as the extent of corrective actions that
may be required, evolving environmental laws and regulations, advances in
environmental technology, the extent of other parties' participation in clean-up
efforts, developments in ongoing environmental analyses related to sites
determined to be contaminated, and developments in environmental surveys and
studies of potentially contaminated sites. As a result, future charges to income
for environmental liabilities could have a significant effect on results of
operations in a particular quarter or fiscal year as individual site studies and
remediation and restoration efforts proceed or as new sites arise. However,
expenditures associated with such liabilities are typically paid out over a long
period; therefore, management believes that it is unlikely that any identified
matters, either individually or in the aggregate, will have a material adverse
effect on BNSF's consolidated financial position or liquidity.

OTHER CLAIMS AND LITIGATION

8
<PAGE>

LABOR

Labor unions represent approximately 88 percent of BNSF Railway employees
under collective bargaining agreements with 13 different labor organizations.
BNRR, ATSF and other major railroads were actively involved in industry-wide
labor contract negotiations beginning in late 1994. Through this process, wages,
health and welfare benefits, work rules and other issues have now been
negotiated for substantially all BNSF Railway union-represented employees. BNSF
Railway remains in negotiations with approximately 425 employees represented by
the American Train Dispatchers Department of the Brotherhood of Locomotive
Engineers.

The new collective bargaining agreements will remain in effect through at
least December 31, 1999 and until new agreements are reached or the Railway
Labor Act's procedures are exhausted. The new collective bargaining agreements
include provisions for retroactive and prospective wage increases, signing
bonuses and lump-sum payments. Throughout the negotiation process, the Company
had been providing reserves related to potential union agreements; therefore,
payments related to the retroactive portion of these agreements did not have a
material effect on the Company's 1996 results of operations.

HEDGING ACTIVITIES
FUEL

BNSF has a program to hedge against fluctuations in the price of its diesel fuel
purchases. This program includes forward purchases for delivery at fueling
facilities. Additionally, this program includes various commodity swap and
collar transactions which are accounted for as hedges. Any gains or losses
associated with changes in market value of these hedges are deferred and
recognized as a component of fuel expense in the period in which the hedged fuel
is purchased and used. To the extent BNSF hedges portions of its fuel purchases,
it may not fully benefit from decreases in fuel prices. However, throughout 1996
and the beginning of 1997, BNSF Railway has seen a continued increase in the
price of fuel, which has resulted in an increase in fuel expense for unhedged
purchases. Based on 1996 fuel consumption, each one cent increase in the price
of fuel would result in approximately $10 million in additional fuel expense on
an annual basis.

BNSF's fuel hedging program covers approximately 35 percent of estimated 1997
fuel purchases and 25 percent of estimated 1998 fuel purchases. Quarterly hedges
in 1997 range from 20 percent to 40 percent of anticipated fuel purchases while
1998 hedges approximate 25 percent each quarter. Hedge positions are closely
monitored to ensure that they will not exceed actual fuel requirements.
Unrecognized gains from BNSF's fuel hedging transactions were approximately $17
million at December 31, 1996 and were not material at December 31, 1995. BNSF
also monitors its hedging positions and credit ratings of its counterparties and
does not anticipate losses due to counterparty nonperformance.

INTEREST RATE

As of February 7, 1997, BNSF has interest rate swap transactions with a total
principal amount of $875 million to fix interest rates on commercial paper debt.
The interest rate swap transactions require payment of a weighted average fixed
interest rate of approximately 5.8 percent, and the receipt of a variable
interest rate based on a commercial paper composite rate. Swap transactions of
$625 million, $250 million and $125 million will mature during the years ended
December 31, 1997, 1998 and 1999, respectively.

9
<PAGE>

UP-SP MERGER

The Surface Transportation Board (STB) approved the proposed common control and
merger of rail carriers controlled by Union Pacific Corporation and SP in its
written decision dated August 12, 1996. The transaction was consummated on
September 12, 1996. As a condition of the merger, the STB imposed provisions
which grant BNRR and ATSF access to approximately 3,900 miles of UP-SP track.
The STB decision provides the Company's subsidiaries with greater access to Gulf
Coast and West Coast markets. The Company is currently evaluating the STB
decision and the impact of the UP-SP merger. Additionally, BNSF management is
evaluating market opportunities and alternatives. The ultimate net effect of the
UP-SP merger on BNSF is presently unknown.

RECENT ACCOUNTING PRONOUNCEMENTS

In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to Be Disposed Of" which establishes the
accounting and reporting requirements for recognizing and measuring impairment
of long-lived assets to be either held and used or held for disposal. In the
first quarter of 1996, BNSF adopted SFAS No. 121 which had no impact on the
Company's financial position or 1996 results of operations.

FORWARD-LOOKING INFORMATION

To the extent that these written statements include predictions concerning
future operations and results of operations, such statements are forward-looking
statements that involve risks and uncertainties, and actual results may differ
materially. Factors that could cause actual results to differ materially
include, but are not limited to, general economic downturns, which may limit
demand and pricing; labor matters, which may affect the costs and feasibility of
certain operations; and competition and commodity concentrations, which may
affect traffic and pricing levels.