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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, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER: 1-7667
SANTA FE ENERGY RESOURCES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 36-2722169
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
1616 SOUTH VOSS, SUITE 1000
HOUSTON, TEXAS 77057
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(713) 507-5000
(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
COMMON STOCK, $0.01 PAR VALUE NEW YORK STOCK EXCHANGE
PREFERRED SHARE PURCHASE RIGHTS NEW YORK STOCK EXCHANGE
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 1, 1999, was approximately $527,234,681.
Shares of common stock outstanding at March 1, 1999: 102,190,292
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<PAGE>
TABLE OF CONTENTS
PAGE
PART I
Items 1. and 2. Business and Properties.............................. 1
Santa Fe Excluding Monterey Resources, Inc.......... 1
General............................................. 1
Proposed Merger..................................... 2
Reserves............................................ 3
Production and Development Activities............... 3
Exploration Activities.............................. 7
Drilling Activities................................. 10
Producing Wells..................................... 10
Domestic Acreage.................................... 11
Foreign Acreage..................................... 11
Santa Fe Energy Trust............................... 11
Current Markets for Oil and Gas..................... 12
Other Business Matters.............................. 13
Item 3. Legal Proceedings.................................... 16
Item 4. Submission of Matters to a Vote of Security Holders.. 16
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters................................. 17
Item 6. Selected Financial Data.............................. 17
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................. 18
Item 8. Consolidated Financial Statements and Supplementary
Data................................................ 31
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosures................ 31
PART III
Item 10. Directors and Executive Officers of the Registrant... 32
Item 11. Executive Compensation............................... 34
Item 12. Security Ownership of Certain Beneficial Owners and
Management.......................................... 42
Item 13. Certain Relationships and Related Transactions....... 45
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K......................................... 49
<PAGE>
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
CERTAIN DEFINITIONS
As used herein, the following terms have the specific meanings set out: "Bbl"
means barrel. "MBbl" means thousand barrels. "MMBbl" means million barrels.
"Mcf" means thousand cubic feet. "MMcf" means million cubic feet. "Bcf" means
billion cubic feet. "MMBtu" means million British thermal units. "BOE" means
barrel of oil equivalent. "MBOE" means thousand barrels of oil equivalent and
"MMBOE" means million barrels of oil equivalent. "MMcfe" means million cubic
feet of natural gas equivalents. Natural gas volumes are converted to barrels of
oil equivalent using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude
oil. Oil volumes are converted to Mcfs of natural gas equivalent using the ratio
of 1.0 barrel of crude oil to 6.0 Mcf of natural gas. Unless otherwise
indicated, natural gas volumes are stated at the official temperature and
pressure basis of the area in which the reserves are located. "Replacement cost"
refers to the cost per BOE of reserves added during a year calculated by using a
fraction, of which the numerator is equal to the costs incurred by the Company
for property acquisition, exploration and development and of which the
denominator is equal to proved reserve additions from extensions, discoveries,
improved recovery, acquisitions and revisions of previous estimates. "Improved
recovery," "enhanced oil recovery" and "EOR" include all methods of
supplementing natural reservoir forces and energy, or otherwise increasing
ultimate recovery from a reservoir, such as waterfloods and CO2 (carbon dioxide)
injection.
SANTA FE EXCLUDING MONTEREY RESOURCES, INC.
Santa Fe Energy Resources, Inc. ("Santa Fe" or "the Company") is engaged in
the exploration, development, acquisition and production of crude oil and
natural gas in the continental and offshore United States and in certain
international areas. As described in Note 3 of the Notes to the Consolidated
Financial Statements, the Company completed the Spin Off of Monterey Resources,
Inc. ("Monterey") on July 25, 1997. As a result of this transaction, management
believes the consolidated results for 1997 and 1996 are not representative of
the Company's on-going operations. Consequently, in order to provide public
investors with more relevant information, the following discussions focus on the
results of the Company, excluding Monterey. Except where indicated all
historical information presented in Part I reflects the results of the Company
excluding Monterey.
GENERAL
The Company's United States ("U.S.") core areas of operations are in the
Permian Basin of West Texas and Southeastern New Mexico and offshore Gulf of
Mexico. Its international core areas are located in Southeast Asia, South
America and West Africa. The Company conducts development activities in each of
its core areas and is growing more rapidly in the international area where it
has recently brought discoveries in Indonesia and Gabon on production. The
Company's exploration activities are conducted in each of the international core
areas, particularly Southeast Asia and West Africa, the Gulf of Mexico and to a
lesser degree Southeast New Mexico.
At December 31, 1998 worldwide proved oil and gas reserves totaled 214.9
MMBOE, an increase of 26% from the 171.1 MMBOE at the beginning of the year.
Year-end reserves were comprised of 168.6 MMBbls of crude oil and liquids and
278.1 Bcf of natural gas, of which approximately 47% were domestic and 53% were
foreign. In 1998, the Company replaced 272% of its production at an average
replacement cost of $5.24. For the three-year period ended December 31, 1998,
the Company replaced 248% of its production at an average replacement cost of
$5.19. Production in 1998 averaged 40.7 MBbls of crude oil and liquids and 178.0
MMcf of natural gas per day, representing a 19% increase on a BOE basis from
1997. In 1998 the Company participated in
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the drilling of 108 development wells (47 domestic and 61 international) and 54
exploratory wells (27 domestic and 27 international) of which, 105 development
and 19 exploratory wells were successfully completed.
Capital expenditures for exploration and development projects totaled $217
million in 1998. In addition, approximately $110 million was spent on
acquisitions during the year. Due to the low commodity price environment, the
Company has reduced its capital budget in 1999 for exploration and development
to approximately $145 million. Under the new budget, capital will be allocated
to domestic gas projects plus the funding necessary to ensure that the large
international projects do not have severe delays. Exploration expenditures and
oil development projects on the Company's long-lived EOR fields in the Permian
Basin and Argentina will be reduced in 1999. Because the actual amounts expended
in the future and the results therefrom will be influenced by numerous factors,
including many beyond the Company's control, the amount of capital expended
during 1999 may vary significantly from the Company's plan.
PROPOSED MERGER
On January 13, 1999, Santa Fe entered into a Merger Agreement with Snyder Oil
Corporation ("Snyder") which provides that Snyder will be merged with and into
Santa Fe. In connection with the merger, the name of Santa Fe will be changed to
Santa Fe Snyder Corporation ("Santa Fe Snyder") and Santa Fe's authorized common
stock will be increased to 300,000,000 shares. Under the agreement, Snyder
shareholders will receive 2.05 shares of Santa Fe common stock for each share of
Snyder common stock. The Company will account for this transaction using the
purchase method of accounting as of the effective date, which is expected in the
second quarter of 1999. The merger is conditioned, among other things, upon
securing regulatory and shareholder approval.
Snyder is engaged in the production, development, acquisition and exploration
of domestic oil and gas properties, primarily in the Gulf of Mexico, the Rocky
Mountains and northern Louisiana. Snyder also has investments in two
international exploration and production companies, SOCO International plc and
Cairn Energy plc. At December 31, 1998, Snyder had estimated proved net reserves
of oil and natural gas totaling 100.3 MMBOE, of which approximately 82% were
natural gas. Average daily production by Snyder during 1998 was 30.9 MMBOE, of
which 83% was natural gas.
Special stockholder meetings will be held by Santa Fe and Snyder in the
second quarter of 1999. Approval of the merger by Santa Fe stockholders requires
the affirmative vote of the holders of a majority of the issued and outstanding
shares of Santa Fe common stock entitled to vote at the Santa Fe special
meeting. Approval by Snyder stockholders requires the affirmative vote of the
holders of a majority of the issued and outstanding shares of Snyder common
stock entitled to vote at the Snyder special meeting.
See Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Proposed Merger" for a further discussion with respect
to the effects of the proposed merger on the Company.
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RESERVES
The following tables set forth information regarding changes in the Company's
estimates of proved net reserves from January 1, 1996 to December 31, 1998 and
the Company's estimated proved developed reserves at December 31 for each of the
years 1995 through 1998.
<TABLE>
<CAPTION>
INCREASES (DECREASES)
---------------------------------------------------------------------------------------------
NET
REVISIONS EXTENSIONS, PURCHASES
BALANCE AT OF DISCOVERIES (SALES) OF BALANCE
BEGINNING PREVIOUS IMPROVED AND MINERALS AT END OF
OF PERIOD ESTIMATES RECOVERY ADDITIONS IN PLACE PRODUCTION PERIOD
--------- --------- -------- ----------- --------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
1996
Oil and condensate
(MMBbls) ................... 79.7 5.7 -- 2.2 5.6 (10.1) 83.1
Natural gas (Bcf) ............. 232.7 22.2 -- 41.9 10.2 (59.8) 247.2
Oil equivalents
(MMBOE) .................... 118.5 9.4 -- 9.2 7.3 (20.1) 124.3
1997
Oil and condensate
(MMBbls) ................... 83.1 11.2 10.6 24.9 10.3 (11.1) 129.0
Natural gas (Bcf) ............. 247.2 39.1 -- 36.1 (6.0) (63.8) 252.6
Oil equivalents
(MMBOE) .................... 124.3 17.7 10.6 30.9 9.3 (21.7) 171.1
1998
Oil and condensate
(MMBbls) ................... 129.0 (1.0) -- 33.8 21.6 (14.8) 168.6
Natural gas (Bcf) ............. 252.6 15.7 -- 58.3 16.5 (65.0) 278.1
Oil equivalents
(MMBOE) .................... 171.1 1.6 -- 43.6 24.3 (25.7) 214.9 (a)
<CAPTION>
DECEMBER 31,
----------------------------------------------
1998 1997 1996 1995
------ ------ ------ ------
Proved Developed Reserves (MMBOE)......................................... 148.4 141.8 103.2 95.0
</TABLE>
(a) At December 31, 1998, 4.1 MMBOE were subject to a 90% net profits
interest held by Santa Fe Energy Trust. See "Santa Fe Energy Trust."
Ryder Scott Company ("Ryder Scott"), a firm of independent petroleum
engineers, prepared the above estimates of the Company's total proved reserves
at December 31, 1995, 1996, and 1997. Ryder Scott also prepared the above
estimates of the Company's proved reserves at December 31, 1998 with the
exception of the Company's reserves on the Jabung Block in Indonesia, which
were prepared by the Company.
PRODUCTION AND DEVELOPMENT ACTIVITIES
UNITED STATES OPERATIONS
The Company's principal U.S. operating regions are the Permian Basin of West
Texas and Southeastern New Mexico and offshore Gulf of Mexico. Approximately 47%
of the Company's proved reserves are located in these regions. U.S. production
averaged 21.2 MBbls of crude oil and liquids and 152.1 MMcf of natural gas per
day in
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l998, remaining constant with production levels from the prior year and
accounting for approximately 66% of the Company's total production in l998. The
Company participated in 47 gross (25.1 net) domestic development wells in l998
of which 46 gross (25.0 net) were successful. Development expenditures during
l998 totaled approximately $70 million, split almost evenly among projects in
the Permian Basin (including both West Texas and Southeastern New Mexico
properties) and the Gulf of Mexico. While development spending in the Gulf of
Mexico in l999 is budgeted to be at about the same level, such expenditures in
the Permian Basin in l999 are expected to be about 50% less primarily due to the
planned deferral of expenditures on the Company's waterflood properties as a
result of the current low commodity price environment.
The Company's properties in West Texas, which produced an average of 12.6
MBbls of crude oil and liquids per day in l998, consist primarily of long-lived
EOR properties in mature fields where the Company is engaged in development
activities through the use of secondary waterfloods and tertiary CO2 floods.
Waterfloods involve the injection of water into reservoirs to drive hydrocarbons
into producing wellbores. Following the waterflood phase, certain fields may
continue to produce in response to tertiary EOR projects such as the injection
of CO2 which mixes with the oil and improves the efficiency of the waterflood.
The Wasson field, in which the Company has been active since l939, is its most
significant EOR property. Net production to the Company in l998 from this field
averaged 5.5 MBbls of crude oil and liquids per day. The Company's interest in
the Wasson field consists principally of royalty and working interests in four
units under CO2 flood. Most of the expenditures for plant, facilities, wells and
equipment necessary for the tertiary recovery projects have been made. In
addition, while expenditures relating to the purchase of CO2 for the field will
continue, the CO2 can be recycled and, therefore, such expenditures should
decline in the future.
The Company continued its development activities in Lea and Eddy Counties in
Southeastern New Mexico with a total of 18 gross (8.4 net) development wells
completed in l998. Production from this area, consisting of both oil and natural
gas, averaged 13.3 MBOE per day in l998. The Cisco Canyon project in the Indian
Basin field in Eddy County is the Company's most significant project in the
area. Net production averaged 7.4 MBOE per day for l998 and represented 10.5% of
the Company's total production. In addition, the Gaucho Unit in Lea County
produced 8.3 MMcf of natural gas per day net to the Company during l998 from
five wells. Development drilling will continue on both projects in l999.
The Company's producing properties in the Gulf of Mexico are in the shallow
water areas (less than 400 feet of water) where the Company participates in 52
producing fields on 83 blocks. Gulf area properties accounted for approximately
47% of the Company's l998 natural gas production and 35% of the Company's proved
natural gas reserves at year-end l998. The Company's most significant project in
l998 in the Gulf of Mexico was on its South Timbalier complex consisting of
Blocks 178, 179 and 186. In May l998 the Company increased its working interest
in Block 179 from 25% to 50% and Block 186 from 25% to 100% through an
acquisition totaling $36 million. With its 50% interest in Block 178 and
following the commencement of production from Block 186 in December l998,
production from the complex currently averages about 43.7 MMcfe of natural gas
per day net to the Company. In January 1999, the Company entered into a
development and exploration joint venture agreement with Westport Oil and Gas.
Under the development component of the agreement, the Company acquired working
interests ranging from 20% to 25% in discoveries on two blocks in the deeper
water of the Flex Trend and one block in the shallower water of the Shelf. Three
or four development wells are planned to be drilled on these blocks in l999.
After payout, Westport will have the option to back in for one-third of the
Company's interests in these blocks.
INTERNATIONAL OPERATIONS
In l998 the Company's production from Indonesia, Argentina and Gabon
accounted for 48% of total crude oil and liquids production and 15% of its total
natural gas production. International proved reserves at year-end l998 comprised
64% of the Company's crude oil and liquids reserves and 13% of its natural gas
reserves. The Company's international production averaged 19.5 MBbls of oil and
25.9 MMcf of natural gas per day in l998, an
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86% increase on a BOE basis from l997. Much of this increase was attributable to
the Mudi field on the Tuban Block in Indonesia which commenced production in
December l997 and averaged 6.5 MBbls of oil per day net to the Company during
l998. The Company participated in 61 gross (19.5 net) development wells in l998
of which 59 (18.9 net) were successful. International development expenditures
in l998 were approximately $70 million, and are expected to be slightly higher
in l999 primarily due to the continuation of development projects on the
Company's Jabung and Tuban Blocks in Indonesia as well as its Kowe Block in
Gabon, the commencement of development drilling in China and a new development
project in Brazil.
INDONESIA. In l998 the Company's net Indonesian production averaged 12.3
MBbls of crude oil and liquids per day from four producing concessions. The
Company sells its Indonesian oil production for U.S. dollars to markets outside
Indonesia except for its production from the Jabung Block (which averaged about
2.5 MBbls per day in l998) which is currently sold to the Indonesian state oil
agency ("Pertamina") for U.S.
dollars.
The Company operates two concessions in Irian Jaya, Indonesia's eastern most
province, which together produced an average of 3.3 MBbls of oil per day net to
the Company. The Salawati Basin concession, in which the Company holds a 33-1/3%
participation interest, is operated under a production sharing contract (a
"PSC") with Pertamina. The other concession covers the Salawati Island Block in
which the Company holds a 16-2/3% participation interest and operates the block
jointly with Pertamina (which holds a 50% interest) under the terms of a Joint
Operating Body contract (a "JOB").
The Company's Tuban Block is on the island of Java where a total of 12
successful wells have been drilled through year-end l998. Two additional
development wells are planned in l999. As stated above, production from the
block commenced in December l997, and during the fourth quarter of l998 the
Company's net production averaged 10.1 MBbls of oil per day. Following the
acquisition of an additional 12.5% interest in May l998 for approximately $49
million, the Company now holds a 25% equity interest in the block. The Company
and Pertamina (with a 50% interest) jointly operate the contract area under the
terms of a JOB.
The Company holds a 30% interest and is the operator of the Jabung Block on
the island of Sumatra under the terms of a PSC with Pertamina. Fields discovered
on the block include the North Geragai field, the Makmur field and the
three-field Betara complex consisting of the Northeast Betara, North Betara and
Gemah fields. Both oil and gas have been discovered in all fields. Oil
production commenced from the North Geragai and Makmur fields in August l997 and
January l998, respectively, and net production from the two fields at year-end
l998 was approximately 2.9 MBbls per day. Additional development wells are
planned in both fields in l999. A second plan of development for the Jabung
Block which includes both the Betara Complex as well as expansion of the Geragai
field is expected to be submitted to Pertamina in the second quarter of l999.
The plan of development will initially focus on the development of liquid
hydrocarbon reserves with initial production tentatively scheduled to commence
by late 2000. Development of the gas reserves on the Jabung block is dependent
upon entering into sales contracts for the gas. The Company is currently in
negotiations with Singapore Power concerning a long-term gas sales contract
covering the entire block. Assuming successful conclusion of the negotiations in
l999, gas sales should commence during 2001.
The PSC contracts under which the Company operates at Salawati Basin and
Jabung entitle the participants to recover all expenditures related to the
operation (the "cost recovery amount") by allocating to the participants a
portion of the crude oil production ("cost oil") sufficient, at the Indonesian
government official crude oil price ("ICP"), to offset the cost recovery amount.
ICP is determined by the Indonesian government based on the average market
prices of a basket of world crude oil prices. All unrecovered costs in any
calendar year are carried forward to future years. The balance of production
after deducting the cost recovery amount is allocated to Pertamina and the
participants (66% is allocated to Pertamina with respect to the Salawati Basin
and 71% is allocated to Pertamina with respect to the Jabung Block). After the
first five years of production, 25% of the production allocated to the
participants must be sold into the Indonesian domestic market for $0.20 per
barrel.
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Under the terms of the JOB contracts which the Company operates the Salawati
Island and Tuban Blocks, the joint venture participants are allowed to recover
the cost recovery amount, after an initial 20% (approximately 8% to the joint
venture participants and 12% to Pertamina) has been deducted, by allocating to
the joint venture participants cost oil sufficient to cover the cost recovery
amount. All unrecovered costs in any calendar year are carried forward to future
years. The balance of production after allocation of cost oil is allocated
approximately 62% to Pertamina and 38% to the joint venture participants. After
the first five years of production, 25% of the production allocated to the joint
venture participants must be sold into the Indonesian domestic market for 10% to
15% of ICP.
ARGENTINA. In l998 the Company's net production in Argentina averaged 5.4
MBbls of oil per day and 25.7 MMcf of natural gas per day. Oil production comes
from the Company's 22% working interest in the El Tordillo field in the San
Jorge Basin and its 100% working interest in the Tupungato field in the Cuyo
Basin. Gas production comes from its 19.9% working interest in the Sierra Chata
field in the Neuquen Basin.
Development activities in the El Tordillo and Tupungato fields during l998
included the drilling of 30 gross (10.5 net) development wells in addition to
performing well workovers and waterflood expansion projects. Due to lower oil
prices, development drilling in these fields slowed during the second half of
l998 and the Company has reduced its capital budget for these properties in
l999. Well workovers and some waterflood and facility work will continue at El
Tordillo and potential waterflood opportunities will be studied at Tupungato.
With the use of a new 3-D seismic survey, three wells were drilled in the
Sierra Chata field in l998 outside the previously productive limits of the
field. All three were successful, testing at a total combined rate of 35 MMcf of
natural gas per day. The Company expects to drill five additional wells in l999
to further extend the field and maintain field deliverability. Production from
the Sierra Chata field is sold under a gas contract with certain "take-or-pay"
and "delivery-or-pay" obligations with a Buenos Aires gas distribution company
and to the Chilean market via the GasAndes Pipeline. In addition, natural gas
produced in excess of contract requirements is sold on the spot market.
GABON. Oil production commenced in January 1998 from the Tchatamba Marine
field in the offshore Kowe Block and is currently producing 20.0 gross MBbls
(3.4 net) per day. The Company holds an 18.75% participatory interest (net of
the Gabonese government's 25% interest) in the exploitation license area
covering the Tchatamba Marine field, and a 25% participatory interest in the
remainder of the block's exploration area. Under the terms of the Kowe Block
PSC, the Gabonese government may elect to take a 25% participatory interest in
any exploitation areas. At year-end the contract area covered approximately
625,200 acres.
Three additional discoveries have been made on the block consisting of the
South Tchatamba, West Tchatamba and Orovinyare fields. Development activities
were undertaken in l998 and will continue this year to bring the South Tchatamba
field on production during the third quarter of l999 by tying its platform into
existing production facilities. Commencement of production from the West
Tchatamba and Orovinyare discoveries is expected to occur at the beginning of
the year 2001.
CHINA. The Company's first operated well in offshore China, the Ursa Prospect
PY4-2-1 on Block 15/34, was completed as a discovery in April 1998. In September
and October l998, a 1,600 square mile 3-D survey was acquired across Block
15/34. Based on this data, an appraisal well was designed and approved by
partners in January 1999. Drilling of this appraisal well is scheduled during
the second quarter of l999. The Company holds a 50% working interest in Block
15/34.
BRAZIL. In December l998 the Company entered into a contract with the
Brazilian oil company Petroleo Brasileiro S.A. ("Petrobras") to develop the
Carauna Block in the Potiguar Basin offshore Brazil. The Company operates the
block with a 51.4% working interest. Although there is only limited production
from the block at this time, Petrobras has drilled ten
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productive wells which have discovered six separate field areas. In l999 the
Company plans to re-enter several of these wells and install an early production
system. Two appraisal wells are also budgeted. The Company plans to commence
full production from the block during the fourth quarter of l999, and by the end
of that year net production to the Company is estimated to be about 3.0 MBbls of
oil per day.
EXPLORATION ACTIVITIES
UNITED STATES OPERATIONS
The Company's exploration in the U.S. is focused in offshore Gulf of Mexico
and to a lesser degree, Southeast New Mexico. Capital expenditures of
approximately $35 million were spent in 1998, the majority of which was for
exploratory drilling in the Gulf of Mexico. U.S. exploration capital for 1999
has been reduced to approximately $4 million.
Exploration in the Gulf of Mexico during 1998 was concentrated in the
shallower water Shelf where the Company embarked on a strategy to high grade its
assets. Deeper water opportunities will be selectively pursued. The Company
drilled 12 gross (4.1 net) exploration wells in the Gulf of Mexico with 6 gross
successful wells (2.6 net) for a success rate of 64%. The Company drilled the
South Timbalier ("S.T.") 186 #C1 and the S.T. 179 #1 wells which were completed
as discoveries. These wells commenced production in 1998 and were producing at a
combined rate of approximately 20.5 MMcf of net natural gas per day at year-end.
The Company is the operator and holds 100% and 50% working interests in these
wells, respectively. The Company acquired five Gulf of Mexico tracts during
1998, four of which are located in the deeper water Flex trend.
In Southeast New Mexico, the Company continues to focus on multiple Permian
and Pennsylvania-aged reservoirs ranging in depth from 1,500 to 16,000 feet.
Potentially significant completions were made on the Irish and Rainbow
Prospects. At the Irish Prospect, where the Company holds 1,720 gross acres (800
net acres), the first well was completed and tested at 4.1 gross MMcf of natural
gas per day from the lower Morrow Formation. At the Rainbow Prospect, where the
Company holds 4,880 gross acres (1,562 net acres), the Thistle Unit #4 was
completed and tested at 3.1 MMcf of natural gas per day. Development drilling is
likely on these prospects pending satisfactory production performance of the
discovery wells.
As discussed above, in January 1999, the Company entered into a joint venture
agreement with Westport Oil and Gas to explore for oil and gas in the deeper
waters of the Gulf of Mexico. The exploration program includes interests in
three exploration projects with the option to drill two additional prospects,
review ten of Westport's prospects in both the deep and shallow waters of the
Gulf and participate with Westport in the upcoming March lease sale.
INTERNATIONAL OPERATIONS
The Company's international exploration program is concentrated primarily in
Southeast Asia and West Africa. At year-end, the Company held interests in 25
blocks in nine countries. Capital expenditures totaled $42.3 million in 1998,
which included participation in 27 gross exploratory wells (11.1 net wells) of
which 9 gross (2.9 net) were successful. The Company plans to reduce
international exploration capital to approximately $10 million for 1999.
SOUTHEAST ASIA.
INDONESIA. The Company drilled two successful discovery wells on the Jabung
Block in 1998, the North Betara-1 and the Gemah 1. The North Betara-1 tested at
2,006 barrels of oil and condensate per day and 6.9 MMcf of natural gas per day.
The Gemah 1 tested at 1,471 barrels of condensate per day and 21.8 MMcf of
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natural gas per day. The Lambur #1 was also drilled on the Jabung Block but
failed to find commercial hydrocarbons. The Company also drilled the successful
discovery well, Amuk, on the Salawati Island Block that flowed approximately
1,750 barrels of oil per day and has commenced production.
CHINA. As stated above, the Company made its first discovery offshore China
in 1998 on Block 15/34. More than 580 net feet of oil pay were measured within
33 sands over a gross interval of 3,000 feet. Six intervals were tested with
combined flow rates of approximately 10.9 MBbls of oil per day. Subsequent to
the discovery, a 40% expansion of the block boundaries with the China National
Offshore Oil Company ("CNOOC") was negotiated. The Company holds a 50% working
interest in Block 15/34 and is the operator. The Company also participated in
the drilling of four wildcats in the South China Sea. Two of these wells were
located on Block 23/28 in the Beibu Gulf area. Both wells failed to find
commercial hydrocarbons and were subsequently plugged and abandoned. The Company
held an 80% working interest in Block 23/28. The remaining two wells were
non-operated wildcats that failed to find commercial hydrocarbons and were also
plugged and abandoned.
The Company signed a PSC with the CNOOC for the right to explore for
hydrocarbons on Block 26/35 in the South China Sea. The Company holds a 100%
working interest in the contract area and plans to acquire 2-D seismic data,
with drilling anticipated to begin in early 2000. The Company also acquired two
additional exploration blocks from the CNOOC in the Pearl River Mouth Basin near
the Ursa discovery. Contracts are expected to be signed in the first quarter of
1999.
MALAYSIA. The Company signed a PSC with Petroliam Nasional Berhad
("Petronas"), the state oil company of Malaysia, for offshore Block PM 308. This
block is located along the east coast of the Malaysian peninsula and contains
nearly 3,494,000 acres. The work program commitments for this block include
seismic reprocessing, seismic acquisition and an obligation to drill three
wells. In addition to the exploration opportunities, the partnership will have
the right to develop the Rhu Field, a potentially commercial 1992 discovery on
the block. One of the three obligation wells will be used as a Rhu Field
appraisal well in the year 2000. The Company holds an 80% working interest in
the block and is the operator.
SOUTH AMERICA
ARGENTINA. On the Bajo Baguales Block, the Company participated in an oil
discovery at the Campamento Prospect. The well was drilled to total depth of
approximately 3,600 feet and encountered two oil sands with total thickness of
more than 20 feet. Delineation and development drilling of this discovery is
scheduled to begin in 1999. A second exploration well, the Cerro Grande X-1 was
drilled on a separate structure to the south of the discovery well and was
plugged and abandoned. The Company is the operator and holds a 40% working
interest in the Bajo Baguales Block.
On Block CNQ-10, the Company drilled the Sierra Chata Norte exploration well
in September that resulted in a discovery and proved the northward extension of
the Company's Sierra Chata Field. A 3-D seismic program is scheduled to begin in
early 1999 to help delineate the extension of the Sierra Chata Field to both the
north and west.
ECUADOR. Two wells were drilled during the year on Oriente Block 11, the
Rubi-1 and the Aguas Blancas #1. The wells encountered oil accumulations that
were not sufficient to justify development and were plugged and abandoned. The
Company's obligation on Oriente Block 11 is now complete and plans to withdraw
from Ecuador are underway.
BRAZIL. The Company signed two exploration contracts in 1998 with Petrobras.
These contracts pertain to the BES-3 exploration block, which was the first
joint venture signed with Petrobras in Brazil's privatization process, and the
BPOT-2 exploration block, which
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the Company will operate. The BES-3 block is located offshore in the Espirito
Santo Basin northeast of Rio de Janeiro. The first exploratory well is
anticipated to be drilled in 2000 after additional seismic is acquired and
evaluated. The BPOT-2 block is located in the Potiguar Basin, offshore Brazil.
Under terms of the BPOT-2 contract, two wells will be drilled on the block.
Additional seismic will be shot to further evaluate the identified prospects and
determine the drilling program.
WEST AFRICA
GABON. During 1998, the Company participated in the drilling of four
exploratory wells on the Kowe Block in offshore Gabon, two of which were
successful. The East Orovinyare-1 wildcat, located in the northern area of the
block tested at approximately 400 barrels of oil per day. The Tchatamba West-1
wildcat was temporarily abandoned as a new discovery from the Madiela Zone. The
well will be tested when production facilities are installed in early 1999. The
Mpando-1 and the Isaaga-1 exploratory wells failed to find commercial
hydrocarbons and were plugged and abandoned. The Company holds a 25% working
interest in the Kowe Block.
COTE D'IVOIRE. The Company holds interests in two blocks in offshore Cote
d'Ivoire which cover approximately 359,000 acres. Two exploratory wells were
drilled on Block CI-24 during 1998. Both wells failed to find commercial
hydrocarbons and were plugged and abandoned. On Block CI-202, the Company
completed a 3-D seismic program in 1998 and plans to drill one well on the block
in 1999.
GHANA. The Company signed a contract for the Keta Block in 1997, an area of
approximately 2,594,000 acres covering both onshore and offshore portions of the
Volta River. A significant portion of this block lies in the deeper waters of
the Volta River Delta. The Company is obligated to reprocess existing seismic
data, to acquire new data and to drill at least one exploratory well during the
three-year primary term of the agreement. A 270 square kilometer 3-D seismic
program was completed in 1998 on the Dolphin and Killer Whale prospects located
in water depths shallower than 200 meters. The Company holds 100% of the working
interest in the block and is the operator.
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<PAGE>
DRILLING ACTIVITIES
The table below sets forth, for the periods indicated, the number of wells
drilled in which the Company had an economic interest. As of December 31, 1998,
wells in the process of drilling or completing included 9 gross (3.3 net)
domestic exploratory wells, 15 gross (5.8 net) domestic development wells, 1
gross (0.1 net) foreign exploratory well and 1 gross (0.3 net) foreign
development well.
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------- ------------- ------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
DEVELOPMENT WELLS
Domestic:
Completed as natural gas wells .... 25.0 9.0 32.0 7.5 12.0 3.8
Completed as oil wells ............ 21.0 16.0 22.0 9.8 28.0 14.7
Dry holes ......................... 1.0 0.1 6.0 2.2 8.0 3.0
Foreign:
Completed as natural gas wells .... 15.0 3.8 2.0 0.4 5.0 1.1
Completed as oil wells ............ 44.0 15.1 41.0 9.6 21.0 4.6
Dry holes ......................... 2.0 0.6 2.0 0.6 1.0 0.2
----- ----- ----- ----- ----- -----
Total Development .................. 108.0 44.6 105.0 30.1 75.0 27.4
----- ----- ----- ----- ----- -----
EXPLORATORY WELLS
Domestic:
Completed as natural gas wells .... 8.0 3.4 9.0 2.9 10.0 5.1
Completed as oil wells ............ 2.0 0.6 7.0 3.4 6.0 2.9
Dry holes ......................... 17.0 6.1 21.0 7.5 8.0 3.0
Foreign:
Completed as natural gas wells .... 2.0 0.7 -- -- 1.0 0.2
Completed as oil wells ............ 7.0 2.2 1.0 0.3 2.0 0.7
Dry holes ......................... 18.0 8.2 5.0 1.8 6.0 1.9
----- ----- ----- ----- ----- -----
Total Exploratory .................. 54.0 21.2 43.0 15.9 33.0 13.8
----- ----- ----- ----- ----- -----
Total ........................... 162.0 65.8 148.0 46.0 108.0 41.2
===== ===== ===== ===== ===== =====
PRODUCING WELLS
The following table sets forth the Company's ownership in producing wells at
December 31, 1998.
<TABLE>
<CAPTION>
U.S. (a) ARGENTINA INDONESIA (b) GABON TOTAL
--------------- --------------- --------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
----- ----- ----- --- ----- --- ----- --- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil ............................ 8,490 977 420 122 408 128 8 2 9,326 1,229
Natural gas .................... 561 162 24 5 14 5 -- -- 599 172
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total ....................... 9,051 1,139 444 127 422 133 8 2 9,925 1,401
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
</TABLE>
(a) Includes 75 gross wells with multiple completions.
(b) Includes 3 gross wells with multiple completions.
10
<PAGE>
DOMESTIC ACREAGE
The following table summarizes developed and undeveloped fee and leasehold
acreage in the United States at December 31, 1998. Excluded from such
information is acreage in which ownership interest is limited to royalty,
overriding royalty and other similar interests.
UNDEVELOPED DEVELOPED
-------------------- --------------------
STATE GROSS NET GROSS NET
- ----- ------- ------- ------- -------
Alabama - Offshore ......... 17,280 6,720 5,760 5,760
Alabama - Onshore .......... -- -- 824 112
Arkansas ................... 329 60 818 182
Colorado ................... 1,192 1,048 5,931 5,249
Kansas ..................... 93 63 3,433 774
Louisiana - Offshore ....... 268,389 135,172 194,043 71,574
Louisiana - Onshore ........ 4,338 1,501 6,720 1,550
Michigan ................... 36,351 18,561 -- --
Mississippi ................ 300 84 2,738 460
Montana .................... 4,751 617 1,070 55
New Mexico ................. 174,740 109,582 72,166 40,979
North Dakota ............... 3,508 1,025 3,385 979
Oklahoma ................... 5,170 5,052 20,118 7,761
Pennsylvania ............... 20 20 25 3
Texas - Offshore ........... 134,292 83,585 48,132 17,751
Texas - Onshore ............ 143,375 104,044 198,946 143,600
Utah ....................... 800 395 2,608 1,373
Wyoming .................... 17,861 9,326 21,048 11,688
------- ------- ------- -------
Total .................... 812,789 476,855 587,765 309,850
======= ======= ======= =======
FOREIGN ACREAGE
The following table summarizes foreign acreage at December 31, 1998.
UNDEVELOPED DEVELOPED
----------------------- --------------------
COUNTRY GROSS NET GROSS NET
- ------- ---------- ------- ------- -------
Argentina .................. 1,426,590 365,046 99,887 25,807
Brazil ..................... 570,040 176,142 47,020 24,173
China ...................... 2,181,928 1,549,341 -- --
Cote d'Ivoire .............. 339,585 250,625 -- --
Ecuador .................... 494,000 172,900 -- --
Gabon ...................... 612,288 153,072 12,909 3,227
Ghana ...................... 2,593,920 2,593,920 -- --
Indonesia .................. 5,988,831 2,191,735 18,390 4,152
Malaysia ................... 3,494,065 2,795,252 -- --
---------- ---------- ------- -------
Total .................... 17,701,247 10,248,033 178,206 57,359
========== ========== ======= =======
SANTA FE ENERGY TRUST
The Santa Fe Energy Trust (the "Trust") was formed in 1992 to hold 6,300,000
Depository Units ("Depository Units"), each consisting of beneficial ownership
of one unit of undivided interest in the Trust and a $20 face amount beneficial
ownership interest in a $1,000 face amount zero coupon United States Treasury
obligation maturing on or about February 15, 2008. The Trust will be liquidated
on February 15, 2008. The assets of the Trust consist of certain oil and gas
properties conveyed by the Company.
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<PAGE>
The properties conveyed to the Trust consisted of two term royalty interests
in two production units in the Wasson field in West Texas and a net profits
royalty interest in certain royalty and working interests in a diversified
portfolio of properties located in twelve states. At December 31, 1998, 4.1
MMBOE of the Company's estimated proved reserves were subject to such net
profits interest. The reserve estimates included herein reflect the conveyance
of the Wasson term royalties to the Trust.
For any calendar quarter ending on or prior to December 31, 2002, the Trust
will receive support payments to the extent that such payments are required to
provide distributions of $0.40 per Depository Unit per quarter or $2.52 million
in the aggregate. Such support payments, if needed, will come from the Company's
remaining royalty interest in one of the production units in the Wasson field
described above, and are non-recourse to the Company. If such additional
payments are made, certain proceeds otherwise payable to the Trust in subsequent
quarters may be reduced to recoup the amount of such payments. The aggregate
amount of the support payments (net of any amounts recouped) is limited to $20.0
million on a revolving basis. Through the end of 1998, the Trust had received
support payments totalling $2,168,000. During 1996 and the first six months of
1997 the Company recouped $2,074,000 of such payments. In 1999, the Company has
made an additional support payment of $779,000. Depending on various factors,
such as sales volumes and prices and the level of operating costs and capital
expenditures incurred, proceeds payable to the Trust with respect to operations
in subsequent quarters may not be sufficient to make distributions of $0.40 per
quarter. In such instances the Company would be required to make support
payments. Due to low commodity prices, almost all of the production proceeds
from Santa Fe's royalty interest in the Wasson ODC unit for the quarter ended
December 31, 1998 were used to make the support payment.
CURRENT MARKETS FOR OIL AND GAS
Substantially all of the Company's oil and gas production is sold at market
responsive prices. The revenues generated by the Company's operations are highly
dependent upon the prices of, and demand for, oil and gas. The price received by
the Company for its crude oil and natural gas depends upon numerous factors, the
majority of which are beyond the Company's control, including economic
conditions in the United States and elsewhere, the world political situation as
it affects OPEC, the Middle East and other producing countries, the actions of
OPEC and governmental regulation. The fluctuation in world oil prices continues
to reflect market uncertainty regarding the balance of world demand for and
supply of oil and gas. The fluctuation of natural gas prices reflects the
seasonal swings of storage inventory, weather conditions, and increasing
utilization of natural gas for electric generation as it affects overall demand.
Decreases in the prices of oil and gas have had, and could have in the future,
an adverse effect on the Company's development and exploration programs, proved
reserves, revenues, profitability and cash flow. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
General".
In Argentina, the Company markets its crude oil for U.S. dollars under market
responsive terms. Production from the El Tordillo field is generally exported
from Argentina and sold into the international market. Production from the
Tupungato field is sold under a long-term contract to a local refinery under
market responsive terms. Gas from the Sierra Chata field is sold under long-term
contracts in Argentina and Chile for prices ranging between $1.15 and $1.35 per
MMBtu. Gas production in excess of the contract requirements is sold on the
local spot market.
The Company sells its Indonesian crude oil production for U.S. dollars to
markets outside of Indonesia except for its production from the Jabung Block
which it sells currently to the Indonesian state oil agency for U.S. dollars.
The Company sells its Gabonese crude oil production for U.S.
dollars into the international markets.
The Company periodically hedges a portion of its oil and natural gas
production to manage its exposure to volatility in prices of oil and natural
gas. See Note 14 to the Consolidated Financial Statements.
12
<PAGE>
OTHER BUSINESS MATTERS
COMPETITION
The Company faces competition in all aspects of its business, including, but
not limited to, acquiring reserves, leases, licenses and concessions; obtaining
goods, services and labor needed to conduct its operations and manage the
Company; and marketing its oil and gas. The Company's competitors include
multinational energy companies, government-owned oil and gas companies, other
independent producers and individual producers and operators. Many competitors
have greater financial and other resources than the Company. The Company
believes that the well-defined nature of the reservoirs in its long-lived oil
fields, its expertise in EOR methods in these fields, its active development and
exploration program, its financial flexibility and its experienced management
may give it a competitive advantage over some other producers.
REGULATION OF CRUDE OIL AND NATURAL GAS
The petroleum industry is subject to various types of regulation throughout
the world, including regulation in the United States by state and federal
agencies. Domestic legislation affecting the oil and gas industry is under
constant review for amendment or expansion, frequently increasing the regulatory
burden. Also, numerous departments and agencies, both state and federal, are
authorized by statute to issue and have issued rules and regulations binding on
the oil and gas industry and its individual members, compliance with which is
often difficult and costly and which may carry substantial penalties for
non-compliance. Although the regulatory burden on the oil and gas industry
increases the cost of doing business and, consequently, affects profitability,
generally these burdens do not appear to affect the Company any differently or
to any greater or lesser extent than other companies in the industry with
similar types and quantities of production. While the Company is a party to
several regulatory proceedings before governmental agencies arising in the
ordinary course of business, the Company does not believe that the outcome of
such proceedings will have a material adverse affect on its operations or
financial condition. Set forth below is a general description of certain state
and federal regulations which have an effect on the Company's operations.
STATE REGULATION. State statutes and regulations require permits for drilling
operations, drilling bonds and reports concerning operations. Most states in
which the Company operates also have statutes and regulations governing the
conservation of oil and gas and the prevention of waste, including the
unitization or pooling of oil and gas properties and rates of production from
oil and gas wells. Rates of production may be regulated through the
establishment of maximum daily production allowables on a market demand or
conservation basis or both.
FEDERAL REGULATION. A portion of the Company's oil and gas leases are granted
by the federal government and administered by the Bureau of Land Management
("BLM") and the Minerals Management Service ("MMS"), both of which are federal
agencies. Such leases are issued through competitive bidding, contain relatively
standardized terms and require compliance with detailed BLM and MMS regulations
and orders (which are subject to change by the BLM and the MMS). For offshore
operations, lessees must obtain MMS approval for exploration plans and
development and production plans prior to the commencement of such operations.
In addition to permits required from other agencies (such as the Coast Guard,
Army Corps of Engineers and Environmental Protection Agency), lessees must
obtain a permit from the BLM or the MMS prior to the commencement of drilling.
The interstate transportation of natural gas is regulated by the Federal Energy
Regulatory Commission ("FERC") under the Natural Gas Act of 1938 and, to a
lesser extent, the Natural Gas Policy Act of 1978. Since the early 1990s, FERC's
regulatory efforts have centered largely around its generic rulemaking
proceeding, Order No. 636. Through Order No. 636 and successor orders, FERC has
undertaken to restructure the interstate pipeline industry with the goal of
providing enhanced access to, and competition among, alternative gas suppliers.
By requiring interstate pipelines to "unbundle" their sales services and to
provide their customers with direct access to any upstream pipeline capacity
held by pipelines, Order No. 636 has enabled pipeline customers to choose the
levels of transportation and storage service they require, as well as to
purchase
13
<PAGE>
gas directly from third-party merchants other than the pipelines. In general,
Order No. 636 has facilitated the transportation of gas and the direct access to
end-user markets.
With the completion of the Order No. 636 implementation process on the FERC
level, FERC's natural gas regulatory efforts have turned towards a number of
other important policies, all of which could significantly affect the marketing
of gas. Some of the more notable of these regulatory initiatives include (i) two
new generic initiatives seeking industry input regarding the pricing,
availability, and terms of service for both the short-term and long-term natural
gas capacity markets, (ii) FERC's ongoing efforts, aided by the participation of
various industry segments through the rulemaking process that resulted in Order
No. 587 and its successor orders, to implement uniform standards for pipeline
electronic bulletin boards, electronic data exchange, and basic business and
operational practices of the pipelines, (iii) the issuance of a merger policy
statement, as well as the consideration and relatively expedient approval of a
surge in merger applications (especially a number of so called "convergence"
mergers between electric utilities and gas companies), (iv) increased acceptance
of market and other non-cost-based rates, such as negotiated rates, for
interstate pipeline transmission and storage capacity, (v) a newly modified
rate-of-return on equity policy for interstate pipelines, and (vi) the
examination, through a number of formal rulemaking proceedings, of certain
general topics affecting the current energy industry (including a review of
regulations governing EX-PARTE communications, a proposed collaborative process
for energy facility applications, an updated landowner notification procedure
for pipeline environmental assessments, and the proposed elimination of a number
of outdated filing and reporting requirements for pipeline certification
applications).
In addition to natural gas regulatory concerns, the FERC's unbundling of the
wholesale electric industry through generic rulemaking proceedings in Order Nos.
888 and 889 and their successor orders may impact the natural gas industry. The
unbundling of the wholesale electric industry, along with the recent trend
toward the implementation of regional system operators and associated power
exchanges, have already been recognized as forcing electric utilities to seek
out more competitive sources of (or alternatives to) supplies for their
gas-fired generation units.
Numerous states have implemented statutory and regulatory initiatives
requiring local distribution companies ("LDCs") to develop (to various degrees)
unbundled transportation and related service options and rates. Typically, these
programs are designed to allow the LDCs' commercial, industrial, and, in more
and more cases, residential, customers to have access to transportation service
on the LDC, coupled with an ability to select third-party city-gate gas
suppliers. Similarly, several states are also addressing the unbundling of the
retail electric markets, ranging from the consideration of initial unbundling
proposals to permitting, in varying degrees, the implementation of programs
allowing direct retail access. These developments have already led a number of
industry participants to redirect significant marketing resources to these
emerging energy markets.
ENVIRONMENTAL REGULATION
Various federal, state and local laws and regulations covering the discharge
of materials into the environment, or otherwise relating to the protection of
the environment, may affect the Company's operations and costs. In particular,
the Company's oil and gas exploration, development, production and EOR
operations, its activities in connection with storage and transportation of
liquid hydrocarbons and its use of facilities for treating, processing,
recovering or otherwise handling hydrocarbons and wastes therefrom are subject
to stringent environmental regulation by governmental authorities. Such
regulation has increased the cost of planning, designing, drilling, installing,
operating and abandoning the Company's oil and gas wells and other facilities.
The Company has expended significant resources, both financial and managerial,
to comply with environmental regulations and permitting requirements and
anticipates that it will continue to do so in the future in order to comply with
stricter industry and regulatory safety standards such as those described below.
Although the Company believes that its operations and facilities are in general
compliance with applicable environmental regulations, risks of substantial costs
and liabilities are inherent in oil and gas operations and there can be no
assurance that significant costs and
14
<PAGE>
liabilities will not be incurred in the future. Moreover, it is possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies thereunder, and claims for damages to property,
employees, other persons and the environment resulting from the Company's
operations, could result in substantial costs and liabilities in the future.
Although the resulting costs cannot be accurately estimated at this time, these
requirements and risks typically apply to companies with types, quantities and
locations of production similar to those of the Company and to the oil and gas
industry in general.
OFFSHORE PRODUCTION. Offshore oil and gas operations are subject to
regulations of the United States Department of the Interior, the Department of
Transportation, the United States Environmental Protection Agency ("EPA") and
certain state agencies. In particular, the Federal Water Pollution Control Act
of 1972, as amended ("FWPCA"), imposes strict controls on the discharge of oil
and its derivatives into navigable waters. The FWPCA provides for civil and
criminal penalties for any discharges of petroleum in reportable quantities and,
along with the Oil Pollution Act of 1990 and similar state laws, imposes
substantial liability for the costs of oil removal, remediation and damages.
SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons that contributed to the release of a "hazardous substance"
into the environment. These persons include the owner or operator of a site and
companies that disposed or arranged for the disposal of the hazardous substance
found at a site. CERCLA also authorizes the EPA and, in some cases, third
parties to take actions in response to threats to the public health or the
environment and to seek to recover from the responsible classes of persons the
costs they incur. In the course of its operations, the Company has generated and
will generate wastes that may fall within CERCLA's definition of "hazardous
substances". The Company may be responsible under CERCLA for all or part of the
costs to clean up sites at which such wastes have been disposed. Certain
properties owned or used by the Company or its predecessors have been
investigated under state and Federal Superfund statutes, and the Company has
been and could be named a potentially responsible party ("PRP") for the cleanup
of some of these sites.
Adobe Resources Corporation, which was merged into the Company in 1992, was
named as a PRP with respect to the Gulf Coast Vacuum Services Superfund site
located in Abbeville, Louisiana. The Company has entered into a sharing
agreement with other PRPs to participate in the final remediation of this site.
The remediation phase is expected to be completed by June 1999, at which time
the long-term monitoring phase will commence. The Company estimates its share of
the remediation and monitoring phases to be approximately $150,000, which has
been provided for in the Company's financial statements.
Pursuant to the Contribution Agreement, Monterey agreed to indemnify and hold
harmless the Company from and against any costs incurred in the future relating
to environmental liabilities in respect to any property or interest located in
California and formerly owned or operated by the former Western Division or its
predecessors.
AIR EMISSIONS. The operations of the Company are subject to local, state and
federal regulations for the control of emissions from sources of air pollution.
Legal and regulatory requirements in this area are increasing, and there can be
no assurance that significant costs and liabilities will not be incurred in the
future as a result of new regulatory developments. In particular, the 1990 Clean
Air Act Amendments impose additional requirements that may affect the Company's
operations, including permitting of existing sources and control of hazardous
air pollutants. The Company has been and may in the future be subject to
administrative enforcement actions for failure to comply strictly with air
regulations or permits. These administrative actions are generally resolved by
payment of a monetary penalty and correction of any identified deficiencies.
Alternatively, regulatory agencies may require the Company to forego
construction or operation of certain air emission sources.
OTHER. The Company is subject to the requirements of the federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard
communication standard, the EPA community
15
<PAGE>
right-to-know regulations under Title III of the federal Superfund Amendment and
Reauthorization Act and similar state statutes require the Company to organize
information about hazardous materials used or produced in its operations.
Certain of this information must be provided to employees, state and local
governmental authorities and local citizens.
Although generally less stringent, the Company's foreign operations are
subject to similar foreign laws respecting environmental and worker safety
matters.
INSURANCE COVERAGE MAINTAINED WITH RESPECT TO OPERATIONS
The Company maintains insurance policies covering its operations in amounts
and areas of coverage normal for a company of its size in the oil and gas
exploration and production industry. These include, but are not limited to,
workers' compensation, employers' liability, automotive liability and general
liability. In addition, umbrella liability and operator's extra expense policies
are maintained. All such insurance is subject to normal deductible levels. The
Company does not insure against all risks associated with its business either
because insurance is not available or because it has elected not to insure due
to prohibitive premium costs.
EMPLOYEES
At December 31, 1998, the Company had 1,286 total employees, including 861
foreign nationals working in Indonesia and Argentina. The Company believes that
its relations with its employees are satisfactory.
ITEM 3. LEGAL PROCEEDINGS
The Company, its subsidiaries and other related companies are named
defendants in several lawsuits and named parties in certain governmental
proceedings arising in the ordinary course of business. While the outcome of
lawsuits or other proceedings against the Company cannot be predicted with
certainty, in the opinion of management, the amounts, if any, which may be
awarded in connection with any of these claims and actions could be significant
to the results of operations of any period but would not be material to the
Company's consolidated financial position.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's shareholders in the
fourth quarter of 1998.
16
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's common stock is listed on the New York Stock Exchange and
trades under the symbol SFR. The following table sets forth information as to
the last sales price per share of the Company's common stock as quoted on the
Consolidated Tape System for each calendar quarter in 1997 and 1998.
PRICE RANGE
----------------
HIGH LOW
------- -------
1997
First Quarter.......................... $15.875 $12.500
Second Quarter......................... 15.750 12.625
Third Quarter (a)...................... 15.500 8.062
Fourth Quarter......................... 14.062 9.875
1998
First Quarter.......................... $11.687 $8.812
Second Quarter......................... 11.562 9.375
Third Quarter.......................... 11.000 6.844
Fourth Quarter......................... 9.187 5.375
(a)On July 25, 1997 the Company distributed pro rata to its common shareholders
all of the shares of Monterey common stock that it owned by means of a
tax-free distribution. The market price of the Company's common stock
declined to reflect the distribution of 0.44 common shares of Monterey for
each common share of Santa Fe. Between the distribution date and November 4,
1997, the date that Monterey's common shares were exchanged for shares of
Texaco, Inc. pursuant to the merger agreement between the two companies, the
market price of Monterey's common shares ranged from a low of $13.875 to a
high of $21.1875 in the third quarter of 1997 and ranged from a low of
$19.9375 to a high of $21.5625 in the fourth quarter of 1997.
Except for the distribution of shares of Monterey common stock described
above, the Company has not paid dividends on its common stock since the third
quarter of 1993. The determination of the amount of future cash dividends, if
any, to be declared and paid is in the sole discretion of the Company's Board of
Directors and will depend on the Company's financial condition, earnings and
funds from operations, the level of its capital and exploration expenditures,
dividend restrictions in its financing agreements, its future business prospects
and other matters as the Company's Board of Directors deems relevant. For a
discussion of certain restrictions on the Company's ability to pay dividends,
see Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations- Financing Activities".
At December 31, 1998 the Company had approximately 29,190 shareholders
of record.
ITEM 6. SELECTED FINANCIAL DATA
See Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Consolidated Results, Including Monterey."
17
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The Company's U.S. core areas of operations are in the Permian Basin of West
Texas and Southeastern New Mexico and offshore Gulf of Mexico. Its international
core areas are located in Southeast Asia, South America and West Africa. The
Company conducts development activities in each of its core areas and is growing
more rapidly in the international area where it has recently brought discoveries
in Indonesia and Gabon on production. The Company's exploration activities are
conducted in each of the international core areas, particularly Southeast Asia
and West Africa, the Gulf of Mexico and to a lesser degree Southeast New Mexico.
As described in Note 3 of the Notes to the Consolidated Financial Statements,
the Company completed the Spin Off of Monterey on July 25, 1997. The
consolidated financial statements for the year ended December 31, 1997 include
seven months of Monterey's results. As a result of this transaction, management
believes the consolidated results for 1997 and 1996 are not representative of
the Company's on-going operations. Consequently, in order to provide public
investors with more relevant information, the following discussions focus on the
results of the Company, excluding Monterey.
PROPOSED MERGER
On January 13, 1999, Santa Fe entered into a Merger Agreement with Snyder Oil
Corporation which provides that Snyder will be merged with and into Santa Fe. In
connection with the merger, the name of Santa Fe will be changed to Santa Fe
Snyder Corporation and Santa Fe's authorized common stock will be increased to
300,000,000 shares. Under the agreement, Snyder shareholders will receive 2.05
shares of Santa Fe common stock for each share of Snyder common stock. The
Company will account for this transaction using the purchase method of
accounting as of the effective date, which is expected in the second quarter of
1999. The merger is conditioned, among other things, upon securing regulatory
and shareholder approval.
The Company's management believes that the merger of Santa Fe and Snyder will
create a larger, more diversified, financially stronger and more cost efficient
enterprise. Snyder's producing properties are entirely located in the United
States, primarily in the Gulf of Mexico, the Rocky Mountains and northern
Louisiana. On a pro forma combined basis, Santa Fe Snyder had estimated proved
reserves of 315 million barrels of oil equivalent at year-end 1998, of which
approximately 65% are domestic. The Company estimates that the merger will
result in annual overhead savings of approximately $20 million.
18
<PAGE>
UNAUDITED FINANCIAL STATEMENTS AND OPERATING SCHEDULES
EXCLUDING MONTEREY
The following unaudited financial statements and operating schedules were
derived from the consolidated financial statements of the Company included
elsewhere herein and set forth the results of the Company excluding Monterey
Resources, Inc. and its predecessor operations, the Western Division of the
Company, for the years ended December 31, 1997 and 1996. Income taxes were
computed on a separate company basis as if the Company had filed returns
excluding Monterey and its predecessor operations for those same years.
SANTA FE EXCLUDING MONTEREY
STATEMENT OF OPERATIONS
(In Millions, Except Per Share Amounts)
(Unaudited)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1997 1996
------- ------- -------
<S> <C> <C> <C>
Revenues:
Sales of crude oil and liquids ................... $ 171.3 $ 196.0 $ 185.5
Sales of natural gas ............................. 119.1 137.5 104.5
Other ............................................ 0.6 -- 0.4
------- ------- -------
Total revenues ................................ 291.0 333.5 290.4
------- ------- -------
Costs and expenses:
Production and operating ......................... 112.5 87.6 80.6
Exploration, including dry hole costs ............ 71.1 48.2 32.8
Depletion, depreciation and amortization ......... 136.1 105.5 110.7
Impairment of oil and gas properties ............. 87.8 -- 57.4
General and administrative ....................... 19.7 20.5 21.1
Taxes other than income .......................... 16.3 14.7 17.2
Loss (gain) on disposition of assets ............. 1.5 (3.6) (12.2)
------- ------- -------
Total costs and expenses ...................... 445.0 272.9 307.6
------- ------- -------
Income (loss) from operations .......................... (154.0) 60.6 (17.2)
Interest income .................................. 6.2 1.5 1.8
Interest expense ................................. (22.0) (12.1) (12.6)
Interest capitalized ............................. 7.2 5.7 4.0
Other income (expense) ........................... (0.3) (0.6) (1.0)
------- ------- -------
Income (loss) before income taxes and extraordinary item (162.9) 55.1 (25.0)
Current income tax (expense) benefit ............. 11.4 6.0 (6.1)
Deferred income tax (expense) benefit ............ 52.8 (25.9) 24.3
------- ------- -------
Income (loss) before extraordinary item ................ (98.7) 35.2 (6.8)
Extraordinary item - debt extinguishment costs ... -- -- (1.5)
------- ------- -------
Net income (loss) ...................................... (98.7) 35.2 (8.3)
Preferred dividend requirement ................... -- (3.6) (13.5)
Convertible preferred premium .................... -- (8.4) (33.7)
------- ------- -------
Earnings (loss) attributable to common shares .......... $ (98.7) $ 23.2 $ (55.5)
======= ======= =======
Earnings (loss) per common share, basic and diluted
Before extraordinary item ........................ $ (0.96) $ 0.24 $ (0.59)
Extraordinary item - debt extinguishment costs ... -- -- (0.02)
------- ------- -------
Per common share ................................. $ (0.96) $ 0.24 $ (0.61)
======= ======= =======
Weighted average number of shares outstanding .......... 102.6 98.6 90.6
======= ======= =======
</TABLE>
19
<PAGE>
SANTA FE EXCLUDING MONTEREY
BALANCE SHEET
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1998 1997
-------- --------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents ........................................... $ 12.1 $ 5.6
Accounts receivable, net ............................................ 53.2 70.9
Inventories ......................................................... 19.0 14.5
Other current assets ................................................ 31.7 21.8
-------- --------
Total Current Assets ............................................. 116.0 112.8
-------- --------
Properties and equipment, at cost:
Oil and gas (successful efforts method of accounting) ............... 1,956.5 1,682.4
Other ............................................................... 20.5 16.8
-------- --------
1,977.0 1,699.2
-------- --------
Accumulated depletion, depreciation, amortization and impairment .... (1,258.7) (1,049.5)
-------- --------
Net property and equipment ....................................... 718.3 649.7
-------- --------
Other Assets:
Deferred income taxes ............................................... 13.5 --
Other ............................................................... 11.2 26.4
-------- --------
Total Other Assets ............................................... 24.7 26.4
-------- --------
Total Assets ........................................................... $ 859.0 $ 788.9
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable .................................................... $ 123.3 $ 106.7
Income taxes payable ................................................ 1.2 6.5
Interest payable .................................................... 1.9 1.4
Other current liabilities ........................................... 12.8 19.4
-------- --------
Total Current Liabilities ........................................ 139.2 134.0
-------- --------
Long-term debt ......................................................... 330.6 121.7
Deferred revenues ...................................................... 3.6 3.7
Other long-term obligations ............................................ 37.2 36.3
Deferred income taxes .................................................. -- 38.5
Commitments and Contingencies (See Note 14)
Shareholders' Equity:
Preferred stock, $0.01 par value, 38.1 shares authorized, none issued -- --
Common stock, $0.01 par value, 200.0 shares authorized,
102.2 shares and 103.0 shares issued and outstanding, respectively 1.0 1.0
Paid-in capital ..................................................... 728.2 728.2
Accumulated deficit ................................................. (372.5) (273.2)
Treasury stock, at cost, 0.8 shares and 0.1 shares, respectively .... (6.8) (0.6)
Unamortized restricted stock awards ................................. (1.5) (0.7)
-------- --------
Total Shareholders' Equity ............................................. 348.4 454.7
-------- --------
Total Liabilities and Shareholders' Equity ............................. $ 859.0 $ 788.9
======== ========
</TABLE>
20
<PAGE>
SANTA FE EXCLUDING MONTEREY
STATEMENT OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Operating activities:
Net income (loss) ........................................ $(98.7) $ 35.2 $ (8.3)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depletion, depreciation and amortization .............. 136.1 105.5 110.7
Impairment of oil and gas properties .................. 87.8 -- 57.4
Deferred income taxes ................................. (52.8) 25.9 (25.2)
Loss (gain) on disposition of assets .................. 1.5 (3.6) (12.2)
Exploratory dry hole costs ............................ 38.4 23.7 10.9
Other ................................................. 3.9 5.1 6.7
Changes in operating assets and liabilities .............. (1.1) 1.4 1.8
------ ------ ------
Net cash provided by operating activities ................... 115.1 193.2 141.8
------ ------ ------
Investing activities:
Capital expenditures, including exploratory dry hole costs (191.9) (172.7) (142.0)
Acquisition of producing properties ...................... (117.6) (84.9) (34.9)
Collection on production payment ......................... -- -- 30.0
Settlements with subsidiary, net ......................... -- -- 30.3
Net proceeds from disposition of assets .................. 2.0 32.5 24.9
Dividends received from Monterey Resources, Inc. ......... -- 16.8 --
Investment in Monterey Resources, Inc. ................... -- -- (0.5)
------ ------ ------
Net cash used in investing activities ....................... (307.5) (208.3) (92.2)
------ ------ ------
Financing activities:
Issuance of Santa Fe Energy Resources, Inc. common stock . 1.6 2.8 2.4
Purchase of 7% Series convertible preferred stock ........ -- -- (94.0)
Net change in long-term debt ............................. 208.9 18.2 20.0
Cash dividends paid ...................................... -- (5.1) (14.8)
Treasury stock purchased ................................. (11.6) (0.5) (0.5)
------ ------ ------
Net cash provided by (used in) investing activities ......... 198.9 15.4 (86.9)
------ ------ ------
Net increase (decrease) in cash and cash equivalents ........ 6.5 0.3 (37.3)
Cash and cash equivalents at beginning of period ............ 5.6 5.3 42.6
------ ------ ------
Cash and cash equivalents at end of period .................. $ 12.1 $ 5.6 $ 5.3
====== ====== ======
</TABLE>
21
<PAGE>
SANTA FE EXCLUDING MONTEREY
OPERATING SCHEDULES
(UNAUDITED)
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
------- ------- -------
CRUDE OIL AND LIQUIDS PRODUCED
REVENUES (IN MILLIONS)
Sales
Domestic ........................ $ 89.4 $ 139.4 $ 142.7
Argentina ....................... 21.3 30.5 25.8
Indonesia ....................... 53.4 27.4 29.5
Gabon ........................... 7.7 -- --
------- ------- -------
171.8 197.3 198.0
Hedging ........................... 2.5 2.2 (10.2)
Net profits payments .............. (3.0) (3.5) (2.3)
------- ------- -------
$ 171.3 $ 196.0 $ 185.5
======= ======= =======
VOLUMES (MBBLS/DAY)
Domestic .......................... 21.2 21.1 19.5
Argentina ......................... 5.4 4.9 3.7
Indonesia ......................... 12.3 4.3 4.3
Gabon ............................. 1.8 -- --
------- ------- -------
40.7 30.3 27.5
======= ======= =======
SALES PRICES ($/BBL)
Unhedged
Domestic ........................ $ 11.60 $ 18.07 $ 19.96
Argentina ....................... 10.73 16.93 19.06
Indonesia ....................... 11.91 17.58 18.92
Gabon ........................... 11.59 -- --
Total ........................... 11.58 17.82 19.68
Hedged ............................ 11.74 18.02 18.66
NATURAL GAS PRODUCED
REVENUES (IN MILLIONS)
Sales
Domestic ........................ $ 111.7 $ 133.1 $ 120.9
Argentina ....................... 12.2 10.1 9.7
Indonesia ....................... 0.1 0.1 0.1
------- ------- -------
124.0 143.3 130.7
Hedging ........................... -- -- (21.4)
Net profits payments .............. (4.9) (5.8) (4.8)
------- ------- -------
$ 119.1 $ 137.5 $ 104.5
======= ======= =======
VOLUMES (MMCF/DAY)
Domestic .......................... 152.1 153.0 142.2
Argentina ......................... 25.7 21.4 20.8
Indonesia ......................... 0.2 0.3 0.4
------- ------- -------
178.0 174.7 163.4
======= ======= =======
SALES PRICES ($/MCF)
Unhedged
Domestic ........................ $ 2.01 $ 2.38 $ 2.32
Argentina ....................... 1.30 1.30 1.27
Indonesia ....................... 1.01 1.04 1.04
Total ........................... 1.91 2.25 2.18
Hedged ............................ 1.91 2.25 1.83
22
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
COSTS AND EXPENSES PER BOE, UNAUDITED
Production and operating (a) ................ $ 4.38 $ 4.05 (e) $ 4.03
Exploration, including dry hole costs ....... 2.77 2.23 (e)(f) 1.64
Depletion, depreciation and amortization..... 5.30 4.86 5.39 (h)
General and administrative .................. 0.77 0.93 (e)(f)(g) 0.88 (i)
Taxes other than income (b) ................. 0.63 0.68 0.86
Interest, net (c) ........................... 0.52 (d) 0.23 0.34
------ ------ ------
Total Costs and Expenses ................... $14.37 $12.98 $13.14
====== ====== ======
</TABLE>
a) Excludes related production, severance and ad valorem taxes.
b) Includes related production, severance and ad valorem taxes.
c) Reflects interest expense less amounts capitalized and interest income.
d) Excludes effect of $4.7 million ($0.18 per BOE) of interest income on
federal income tax audit refunds.
e) Excludes benefit of $1.3 million general and administrative ($0.06 per BOE),
$0.3 million production and operating (0.01 per BOE) and $0.4 million
exploration costs and expenses ($0.02 per BOE) related to a pension
curtailment benefit from the Monterey Spin Off in 1997.
f) Excludes effect of $0.5 million general and administrative ($0.02 per BOE)
and $0.1 million exploration costs and expenses ($0.01 per BOE) related to
compensation expenses resulting from the Spin Off in 1997.
g) Excludes effect of $1.1 million in administrative costs related to the Spin
Off of Monterey ($0.05 per BOE) in 1997.
h) Excludes effect of unproved property writedowns of $0.13 per BOE.
i) Excludes effect of $1.6 million charge related to the abandonment of an
office lease and $2.0 million in costs and expenses related to the Monterey
IPO ($0.18 per BOE).
23
<PAGE>
GENERAL
As an independent oil and gas producer, the Company's results of operations
are dependent upon the difference between the prices received for oil and gas
and the costs of finding and producing such resources. Crude oil prices are
subject to significant changes in response to fluctuations in the domestic and
world supply and demand and other market conditions as well as the world
political situation as it affects OPEC, the Middle East and other producing
countries. Crude oil prices fell in the fourth quarter of 1997 and early 1998 in
part due to uncertainties about the strength of some Asian economies and
continued to decline through the fourth quarter of 1998. In 1998 the actual
average crude oil and liquids sales price (unhedged) received by the Company
ranged from a high of $12.83 per barrel in the first quarter of 1998 to a low of
$10.32 per barrel in the fourth quarter of 1998. The Company's average crude oil
and liquids sales price (unhedged) received in January 1999 was $10.26 per
barrel. Based on operating results for 1998, the Company estimates that on an
annualized basis a $1.00 per barrel increase or decrease in its average crude
oil sales prices would result in a corresponding $10.0 million change in net
income and a $12.7 million change in cash flow from operating activities. The
price of natural gas fluctuates due to weather conditions, the level of natural
gas in storage, the relative balance between supply and demand and other
economic factors. The actual average sales price received by the Company in 1998
for its natural gas ranged from a high of $1.99 per Mcf in the second quarter of
1998 to a low of $1.85 per Mcf in the fourth quarter of 1998. The Company's
average gas price received in January 1999 was $1.69 per Mcf. Based on operating
results for 1998, the Company estimates that on an annualized basis a $0.10 per
Mcf increase or decrease in its average natural gas sales price would result in
a corresponding $4.1 million change in net income and a $5.9 million change in
cash flow from operating activities. The foregoing estimates do not give effect
to changes in any other factors, such as the effect of the Company's oil hedging
program, its debt levels and related interest expense, its reserve levels or the
level of capital expenditures, that might result from a change in crude oil and
natural gas prices. With regard to the Company's Argentina operations, the
Company sells its natural gas production under long-term contracts at prices
ranging from $1.15 to $1.35 per MMbtu.
YEAR ENDED DECEMBER 31, 1998 COMPARED WITH YEAR ENDED DECEMBER 31, 1997
OIL AND GAS REVENUES. Total revenues for 1998 of $291.0 million were 12.7%
lower than 1997, due to lower realized prices for crude oil liquids and natural
gas which were down 35% and 15%, respectively. The Company's crude oil and
liquids production for 1998 increased over 34% to 40.7 MBbls per day from 30.3
MBbls per day in 1997. The production increase was primarily due to new
production from the Mudi, N. Geragai and Makmur fields in Indonesia and the
Tchatamba field in Gabon, augmented by the acquisition of an additional working
interest in the Mudi field a full year of production from the Tupungato field in
Argentina. Natural gas production increased to 178.0 MMcf per day in 1998
compared with 174.7 MMcf per day for the same period in 1997. Gas production
from new wells in Southeast New Mexico, the Gulf of Mexico and Argentina more
than offset the loss of production from natural production declines, property
sales and weather-related disruptions in the Gulf of Mexico. Crude oil prices
realized in 1998 averaged $11.74 per barrel, including a $0.16 per barrel
hedging benefit, compared with $18.02 per barrel, net of a $0.20 per barrel
hedging benefit in 1997. Natural gas prices realized in 1998 averaged $1.91 per
Mcf, compared with an average of $2.25 per Mcf in 1997.
COSTS AND EXPENSES. Production and operating expense for the year ended
December 31, 1998 increased by 28% to $112.5 million from $87.6 million in 1997
principally due to increased crude oil and natural gas production, as noted
above. Operating costs per unit of production increased to $4.38 per BOE versus
$4.05 in 1997 primarily due to increased international production under
production sharing contracts and the weather-related disruptions in the Gulf as
mentioned above. Exploration expense in 1998 increased to $71.1 million from
$48.2 million in 1997, primarily due to dry hole costs in Cote d'Ivoire, China
and Ecuador and seismic programs in China and Gabon. Depletion, depreciation and
amortization ("DD&A") for 1998 increased to $136.1 million from $105.5 million
for the same period of 1997 primarily due to increased production.
24
<PAGE>
DD&A per BOE increased to $5.30 from $4.86 due primarily to new production from
higher cost properties in the Gulf of Mexico. Impairments of $87.8 million were
recorded in 1998 primarily on producing oil and gas properties and unproven
leasehold in the Gulf of Mexico. The impairments of oil and gas properties were
primarily the result of lower oil and gas prices which are not expected to
improve in the near term. The oil and gas impairment tests were based on
estimates of future cash flows using an initial WTI spot oil price and an
initial New York Mercantile Exchange ("NYMEX") gas price based on quoted forward
market prices which were moderately escalated. Future cash flows at December 31,
1998 were based on the Company's estimate of proved reserves and significantly
risked probable and possible reserves. The impairment of unproven leasehold was
the result of management's decision not to develop these leases.
Interest income for 1998 included $4.7 million related to refunds on federal
income tax audits. Interest expense increased by $9.9 million in 1998,
reflecting an increase in borrowings from 1997. Income taxes for 1998 included a
$6.0 million benefit related to the favorable settlement of an audit and a $2.4
million benefit related to an anticipated income tax refund. The preferred
dividend requirement decreased $3.6 million in 1998 due to the purchase and
conversion of all of the Company's outstanding preferred stock, which included
the Convertible Preferred Stock, 7% Series (the "7% Preferred") and the $.732
Series A Convertible Preferred (the "DECS"). In November 1996 the Company
purchased 3.8 million of the outstanding shares of its 7% Preferred for $24.50
per SHARE. In the second quarter of 1997, the Company converted the remaining
1.2 million outstanding shares of 7% Preferred for 2.3 million shares of common
stock. The conversion of the 7% Preferred resulted in a noncash reduction in
earnings to common shares (which is reflected as a convertible preferred premium
in the Statement of Operations) of $8.4 million in 1997. Also, in the second
quarter of 1997, the Company converted all 10.7 million outstanding shares of
its DECS into 9.1 million shares of common stock which had no effect on the
Company's earnings to common shares.
YEAR ENDED DECEMBER 31, 1997 COMPARED WITH YEAR ENDED DECEMBER 31, 1996
OIL AND GAS REVENUES. Total revenues from crude oil and natural gas sales
increased by 15% to $333.5 million for the year ended December 31, 1997 compared
with $290.4 million for the same period in 1996. The increase was due primarily
to increased crude oil and natural gas production and improved natural gas
prices, partially offset by lower realized crude oil prices. The Company's crude
oil and liquids production for 1997 increased over 10% to 30.3 MBbls per day
from 27.5 MBbls per day in 1996. The production increase was primarily due to
property acquisitions in the Permian Basin and Argentina, the Company's ongoing
exploration and development program and commencement of production at the N.
Geragai field in Indonesia. Natural gas production increased to 174.7 MMcf per
day in 1997 from 163.4 MMcf per day for the same period in 1996. New wells in
the Central Division and in the Gulf of Mexico more than offset normal
production declines and the loss of production from property sales in the Gulf.
Crude oil prices realized in 1997 averaged $18.02 per barrel, including a $0.20
per barrel hedging benefit, compared with 1996 when the average realized oil
price was $18.66 per barrel, net of a $1.02 per barrel hedging expense. Natural
gas prices realized in 1997 averaged $2.25 per Mcf, compared with an average of
$1.83 per Mcf in 1996, net of a $0.35 per Mcf hedging expense. No natural gas
was hedged in 1997.
COSTS AND EXPENSES. Production and operating expense for the year ended
December 31, 1997 increased to $87.6 million from $80.6 million in 1996 due to
increased crude oil and natural gas production, as noted above. Operating costs
per unit of production remained essentially the same at $4.05 per BOE (net of
various adjustments as noted above) versus $4.03 in 1996. Exploration expense in
1997 increased to $48.2 million from $32.8 million in 1996, primarily due to
increased drilling activity and dry hole expense in the Gulf of Mexico.
Depletion, depreciation and amortization expense for 1997 decreased to $105.5
million from $110.7 million for the same period of 1996, primarily due to the
effect of proved property impairments recorded in 1996. Gain from the
disposition of assets was $8.6 million higher in 1996 compared with 1997 due to
a $12.3 million gain on the sale of the Company's Olinda surface property in
1996.
25
<PAGE>
Income taxes for 1996 included an $8.3 million deferred tax benefit related
to certain foreign expenditures incurred in prior periods. The extraordinary
expense item of $1.5 million reported in 1996 represents costs and expenses, net
of related income taxes, associated with the retirement of certain of the
Company's debt in association with the Monterey IPO. See Note 3 to the
Consolidated Financial Statements. The preferred dividend requirement decreased
$9.9 million in 1997 due to the purchase and conversion of all of the Company's
outstanding preferred stock. With respect to the Company's purchase of the 3.8
million shares of the 7% Preferred in 1996, the $33.7 million excess of the cost
of the acquired shares over the book value of such shares is reflected in the
Statement of Operations as a convertible preferred premium.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL EXPENDITURES. In 1998, the Company's primary needs for cash were for
exploration, development and acquisition of oil and gas properties. The Company
spent $327.1 million for capital expenditures in 1998 and expects to spend
approximately $145 million in 1999. Because the actual amounts expended in the
future and the results therefrom will be influenced by numerous factors,
including many beyond the Company's control, no assurances can be given as to
the amounts that will be expended. The Board of Directors has authorized the
Company to buy back up to $50 million of its common stock to meet the
requirements of outstanding stock options and to satisfy the stock requirements
of employee benefit plans. From December 1997 through October 1998, the Company
purchased 1.3 million common shares for approximately $12 million. The Company
is not currently buying back its common stock.
CAPITAL RESOURCES. The Company's capital resources consisted of cash flow
from operating activities of $115.1 million and funds available under its bank
credit facilities including its revolving credit agreement (the "Credit
Agreement") which matures May 15, 2003. Subject to the covenants described
below, the Credit Agreement permits the Company to obtain revolving credit loans
and issue letters of credit having a maximum aggregate amount of $335 million of
which $30 million is available for letters of credit. Borrowings under the
agreement are unsecured and interest rates are tied to the agent bank's prime
rate or eurodollar offering rate, at the Company's option. Actual interest rates
varied from 6.0% to 6.4% for the year ended December 31, 1998. At December 31,
1998, the Company had $225.0 million in borrowings outstanding under the Credit
Agreement, which were classified as long-term debt on the balance sheet since
the Company has the ability and intends to refinance such amount on a long-term
basis. The Company had one letter of credit outstanding under the Credit
Agreement at December 31, 1998 for $22.1 million and one letter of credit
outside the Credit Agreement for $1.8 million.
The Credit Agreement and the Indenture for the Debentures (see Note 8 to the
Consolidated Financial Statements) include covenants that restrict the Company's
ability to take certain actions, including the ability to incur additional
indebtedness and to pay dividends or repurchase capital stock. Under the most
restrictive of these covenants, at December 31, 1998 the Company could incur
approximately $168 million of additional indebtedness of which $70 million could
be borrowings under the Credit Agreement. As of December 31, 1998, these
covenants do not allow the Company to pay dividends or repurchase capital stock.
In addition to the Credit Agreement, the Company also has one short-term
uncommitted line of credit totalling $20.0 million which is used to meet
short-term cash needs. At December 31, 1998, the Company had $6.0 million in
borrowings under these facilities, which were classified as long-term debt on
the balance sheet since the Company has the ability and intends to refinance
such amount on a long-term basis. Actual interest rates varied from 5.6% to 7.5%
for the year ended December 31, 1998.
The Company has historically funded its operations and capital spending
programs with cash flow from operations and borrowings under bank credit
facilities. The Company believes that cash flow from operations and the
borrowing availability under the Credit Agreement will be sufficient to meet its
anticipated capital requirements for 1999.
26
<PAGE>
ENVIRONMENTAL MATTERS. Almost all phases of the Company's oil and gas
operations are subject to stringent environmental regulation by governmental
authorities. Such regulation has increased the costs of planning, designing,
drilling, installing, operating and abandoning oil and gas wells and other
facilities. The Company has expended significant financial and managerial
resources to comply with such regulations. Although the Company believes its
operations and facilities are in general compliance with applicable
environmental regulations, risks of substantial costs and liabilities are
inherent in oil and gas operations. It is possible that other developments, such
as increasingly strict environmental laws, regulations and enforcement policies
or claims for damages to property, employees, other persons and the environment
resulting from the Company's operations, could result in significant costs and
liabilities in the future. As has been done in the past, the Company intends to
fund its cost of environmental compliance from operating cash flows. See Items 1
and 2. "Business and Properties, Other Business Matters - Environmental
Regulation" and Note 14 to the Consolidated Financial Statements.
INDONESIA. The Company's Asian producing operations are located in Indonesia.
During the last two years, Indonesia and other Asian countries experienced
significant devaluations in their currencies and hyper-inflation, which have
resulted in disruptions and uncertainties in financial markets, and political
and social instability. These uncertainties resulted in the resignation of
Indonesia's President Suharto after 32 years in office. Although Indonesia has a
well established history of honoring its contractual commitments and concession
terms, it is uncertain which political party will take control over Indonesia's
government in elections scheduled this summer or whether the new government will
seek reforms in, or take other actions with respect to, governmental concessions
and production sharing contracts.
One effect of the currency devaluation has been to reduce certain operating
and administrative costs incurred by the Company in its Indonesian operations,
thus reducing the number of cost recovery barrels it retains in reimbursement of
such expenses, and to reduce the value of certain receivables and payables which
are denominated in the local currency, the rupiah. In addition, the Company has
experienced delays in collecting some receivables, but has been able to collect
the amounts owed in full. The Company has experienced disruptions in the
delivery of some services and goods, which has led to delays in certain
operations and associated production.
The Company sells its Indonesian production for U.S. dollars generally
outside of Indonesia. The Company currently sells its production from the North
Geragai and Makmur fields to the Indonesian state oil agency for U.S. dollars.
In 1998 the Company's Indonesian operations generated $9.1 million of income
from operations and $28.8 million in cash flow from operating activities. While
the financial uncertainties in Asia have not had a significant effect on the
Company's operations in Indonesia to date, the Company cannot predict with any
certainty the future effects of continued financial disruptions, if any, on its
income from Indonesian operations and future development activity in Indonesia.
DIVIDENDS. The determination of the amount of future cash dividends, if any,
to be declared and paid on the Company's common stock is at the sole discretion
of the Company's Board of Directors and is dependent on financial condition,
earnings and available funds from operations, level of capital and exploration
expenditures, dividend restrictions as set forth in financing agreements, future
business prospects and other matters deemed relevant.
CONSOLIDATED RESULTS, INCLUDING MONTEREY
For the year ended December 31, 1997, the Company reported total revenues of
$514.7 million, total costs and expenses of $403.9 million and earnings to
common shares of $42.7 million or $0.43 per share. These results reflect the
consolidation of Monterey Resources for the first seven months of the year. For
the year ended December 31, 1996 the Company reported total revenues of $583.3
million, total costs and expenses of $493.8 million and a loss to common shares
of $10.8 million or $0.12 per share. Monterey Resources is included in the
Company's consolidated results for all of 1996.
27
<PAGE>
YEAR ENDED DECEMBER 31, 1998 COMPARED WITH YEAR ENDED DECEMBER 31, 1997
OIL AND GAS REVENUES. Total revenues from crude oil and natural gas decreased
to $290.4 million in 1998 from $493.8 million in 1997. The decrease is primarily
due to the contribution of Monterey for seven months of 1997 combined with lower
realized prices in 1998. Monterey contributed $180.8 million in crude oil and
natural gas revenues in 1997.
COSTS AND EXPENSES. Total costs and expenses increased to $445.0 million in
1998 from $403.9 million in 1997. The increase is primarily due to impairments
of oil and gas properties of $87.8 million, higher DD&A expense and dry hole
costs in 1998, partially offset by Monterey's $131.0 million contribution to
expenses in 1997.
The Company had no preferred dividend requirement in 1998 due to the
conversion of all of the Company's outstanding preferred stock in 1997. The
Company recognized reductions in earnings attributable to common shares of $8.4
million in 1997 related to the conversion of the Company's 7% Preferred as
described above. See Notes 9 and 10 to the Consolidated Financial Statements.
YEAR ENDED DECEMBER 31, 1997 COMPARED WITH YEAR ENDED DECEMBER 31, 1996
OIL AND GAS REVENUES. Total revenues from crude oil and natural gas decreased
to $493.8 million in 1997 from $561.2 million in 1996. The decrease is primarily
due to the contribution of Monterey for a full year in 1996 compared with seven
months in 1997. Monterey contributed $292.3 million in crude oil and natural gas
revenues in 1996 compared with $180.8 million in 1997. The loss of revenue due
to the Spin Off of Monterey was partially offset by higher production volumes
and increased gas prices in 1997.
COSTS AND EXPENSES. Total costs and expenses decreased to $403.9 million in
1997 from $493.8 million in 1996. The decrease is primarily due to a decrease in
Monterey's share of expenses from $186.2 million in 1996 to $131.0 million in
1997 coupled with $57.4 million of oil and gas property impairments recorded in
1996.
Income taxes in 1996 include an $8.3 million deferred tax benefit related to
certain foreign expenditures incurred in prior periods. The extraordinary
expense item of $6.0 million is related to the retirement of certain of the
Company's debt in association with the Monterey IPO. See Note 3 to the
Consolidated Financial Statements. The Company's preferred dividend requirement
decreased in 1997 due to the purchase and conversion of all of the Company's
outstanding preferred stock. The Company recognized reductions in earnings
attributable to common shares of $8.4 million and $33.7 million in 1997 and
1996, respectively, related to the repurchase and conversion of the Company's 7%
Preferred Stock as described above. See Notes 10 and 11 to the Consolidated
Financial Statements.
28
<PAGE>
SELECTED FINANCIAL DATA (UNAUDITED)
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Consolidated Selected Financial Data,
Including Monterey
Income Statement Data
Revenues ..................................... $ 291.0 $ 514.7 $ 583.3 $ 449.4 $ 404.2
Income (loss) from operations ................ $ (154.0) $ 110.8 $ 89.5 $ 53.9 $ 48.2
Earnings (loss) attributable to
common shares ............................. $ (98.7) $ 42.7 $ (10.8) $ 11.8 $ 5.4
Basic and diluted per share data
Before extraordinary item ................. $ (0.96) $ 0.43 $ (0.05) $ 0.13 $ 0.06
Extraordinary item - debt
extinguishment ......................... -- -- (0.07) -- --
Per common share .......................... $ (0.96) $ 0.43 $ (0.12) $ 0.13 $ 0.06
Weighted average number
of shares outstanding ..................... 102.6 98.6 90.6 90.2 89.9
Balance Sheet Data
Properties and equipment, net ................ $ 718.3 $ 649.7 $ 909.8 $ 889.5 $ 843.0
Total assets ................................. 859.0 788.9 1,129.1 1,073.8 1,081.0
Long-term debt ............................... 330.6 121.7 278.5 344.4 350.4
Convertible preferred stock .................. -- -- 19.7 80.0 80.0
Shareholders' equity ......................... 348.4 454.7 526.8 437.7 423.3
</TABLE>
YEAR 2000
The risks associated with the Year 2000 problem are the results of computer
technology utilizing two digits rather than four to define a specific year.
Absent corrective actions, a computer program or embedded chip that is date
sensitive may recognize a date using "00" as the year 1900 rather than the year
2000. This could result in system failures or miscalculations causing
disruptions to various activities and operations.
The Company has developed a plan to identify those risks related to the Year
2000 problem, to remediate systems and equipment where required and to test for
Year 2000 compliance. The Company has identified all critical computer systems
and determined the remediation that will be performed. The Company has already
made the required modifications to its domestic accounting systems, is in the
process of making modifications to Indonesian accounting systems and plans to
install a new accounting system in Argentina by mid-year 1999. The Company has
engaged an outside consulting firm to assist in reviewing field equipment used
in its oil and gas producing operations for Year 2000 issues. The Company
expects to complete its inventory and assessment of all field equipment in the
first quarter of 1999. The Company expects to complete all remediation of
critical systems by June 30, 1999 and to test all of these systems in 1999. The
Company recognizes that, notwithstanding the efforts described above, the
Company could experience disruptions to its operations or administrative
functions, including those resulting from non-compliant systems utilized by
unrelated third party governmental and business entities. The Company is in the
process of developing a business contingency plan in order to mitigate potential
disruption to business operations. The Company expects to complete this
contingency plan by the second quarter of 1999 but also expects to refine this
plan throughout 1999. With regard to risks relating to third parties, the
Company has implemented a program to request Year 2000 certification or other
assurance from its significant customers, transporters, partners and suppliers.
29
<PAGE>
The Company has reviewed and evaluated its most reasonably likely worst case
scenario with regard to the Year 2000. Management believes that it is taking
every reasonable precaution to detect, remediate and test all critical computer
systems and equipment. Management believes that the most reasonably likely worst
case scenario would involve failure of production equipment in the field, which
would result in disruption of those operations affected until the problem is
solved and possibly expose the Company to contractual penalties and other
liabilities.
The Company is in the process of reviewing Snyder's computer systems and Year
2000 compliance program to determine which systems will be retained by Santa Fe.
See Part I, Items 1 and 2, "Business and Properties" for further discussion on
the proposed merger.
Through December 31, 1998 the Company has spent $0.4 million for identifying,
remediating and testing systems for Year 2000 related problems. The Company
currently estimates that its Year 2000 related costs will be between $1.0
million and $2.0 million, but this estimate may change as a result of the review
of the equipment used in its oil and gas producing operations.
MARKET RISKS
The Company is exposed to market risk, which includes adverse changes in
commodity prices and interest rates as discussed below.
COMMODITY PRICE RISK. The Company produces and sells crude oil, liquids and
natural gas. As a result, the Company's financial results can be significantly
affected as these commodity prices fluctuate widely in response to changing
market factors. The Company made a limited use of futures contracts during the
year to reduce its exposure to declines in market prices. The Company used the
hedge method of accounting for these instruments and, as a result, gains and
losses on commodity futures contracts were generally offset by similar changes
in the realized prices of the commodities. At December 31, 1998, the company had
no open crude oil sales hedges.
INTEREST RATE RISK. The Company's exposure to changes in interest rates
primarily results from its short-term and long-term debt with both fixed and
floating interest rates. To date, the Company has not deemed it necessary to
enter into any financial instruments, such as interest rate swaps, because
interest rates have remained at historically low levels.
FORWARD-LOOKING STATEMENTS
In its discussion and analysis of financial condition and results of
operations and elsewhere herein, the Company has included certain statements
(other than statements of historical fact) that constitute forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. When used herein, the words
"budget," "budgeted," "anticipates," "expects," "believes," "seeks,"
"estimates," "intends" or "projects" and similar expressions are intended to
identify forward-looking statements. It is important to note that the Company's
actual results could differ materially from those projected by such
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable and such
forward-looking statements are based upon the best data available at the time
this report is filed with the Securities and Exchange Commission, no assurance
can be given that such expectations will prove correct. Factors that could cause
the Company's results to differ materially from the results discussed in such
forward-looking statements include, but are not limited to, the following:
production variances from expectations, volatility of oil and gas prices,
hedging results, the need to develop and replace its reserves, the substantial
capital expenditures required to fund its operations, exploration risks,
environmental risks, the inability to successfully integrate Snyder's
operations, uncertainties about estimates of reserves, competition litigation,
government regulation
30
<PAGE>
and political risks, uncertainties associated with the Year 2000 issue and the
ability of the Company to implement its business strategy. All such
forward-looking statements in this document are expressly qualified in their
entirety by the cautionary statements in this paragraph.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See the Consolidated Financial Statements and supplementary data listed in
the accompanying Index to Financial Statements, Supplemental Data and Financial
Statement Schedules on page 49 herein. Information required by other schedules
required under Regulation S-X is either not applicable or is included in the
financial statements or notes thereto.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
31
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
EXECUTIVE OFFICERS OF SANTA FE
Listed below are the names, ages (as of February 1, 1999) and positions of
all executive officers of Santa Fe (excluding executive officers who are also
directors of Santa Fe) and their business experience during the past five years.
Each executive officer holds office until his or her successor is elected or
appointed or until his or her earlier death, resignation or removal.
HUGH L. BOYT, 53 President and Chief Operating Officer since April 1, 1998.
From March 1, 1990 until April 1998, Mr. Boyt served as Senior Vice President
- Production.
JERRY L. BRIDWELL, 55 Senior Vice President - Exploitation and Acquisitions
since January 1, 1999. From 1986 until January 1999, Mr. Bridwell served as
Senior Vice President - Exploration and Land.
JANET F. CLARK, 44 Senior Vice President, Chief Financial Officer and
Treasurer since April 1, 1998. From January 1, 1997 until April 1998, Ms.
Clark served as Vice President and Chief Financial Officer. Ms. Clark was
with Southcoast Capital Corporation from January 1994 until she joined Santa
Fe. While with Southcoast Capital, Ms. Clark served as Vice President from
January 1994 to June 1996 and as Director, Corporate Finance, from June 1996
to December 1996.
CHARLES G. HAIN, 52 Senior Vice President - Corporate Services since July 1,
1998. From May 1994 until July 1998 Mr. Hain served as Vice President - Human
and Data Resources and from 1988 until May 1994 he served as Vice President -
Employee Relations.
TIMOTHY S. PARKER, 46 Senior Vice President - Exploration and Land since
January 1, 1999. From April 1, 1998 until January 1, 1999, Mr. Parker served
as Vice President - Exploration and from September 1, 1995 until April 1998
he served as Division Exploration Manager, International. Mr. Parker served
as Corporate Exploration Manager from May 1, 1994 until September 1, 1995 and
from 1988 until May 1, 1994 he served as Division Manager, Exploration.
DUANE C. RADTKE, 50 Senior Vice President - Production since April 1, 1998.
From July 1, 1993 to April 1998, Mr. Radtke served as President - Santa Fe
Energy Resources, Inc. Southeast Asia Companies.
E. EVERETT DESCHNER, 58 Vice President - International Production since April
1, 1998. From April 1990 until April 1998, Mr. Deschner served as Vice
President - Engineering and Evaluation.
KATHY E. HAGER, 47 Vice President - Public Affairs since January 1997. From
January 1994 to January 1997, Ms. Hager served as Director, Investor
Relations.
DAVID L. HICKS, 49 Vice President - Law and General Counsel since March 1991.
GREGORY M. HOFFMAN, 43 Vice President - Corporate Business Development since
October 1997. From November 1996 to October 1997, Mr. Hoffman served as
Manager, Corporate Acquisitions and from May 1, 1991 until November 1996, he
served as Manager, Business Development.
MICHAEL S. WILKES, 48 Vice President and Controller since January 1, 1999.
From 1987 until January 1999, Mr. Wilkes served as Controller.
32
<PAGE>
DIRECTORS OF SANTA FE
CURRENT DIRECTORS. Listed below are the names and ages (as of February 1,
1999) of, and certain information about, all the current directors of the
Company. The indicated periods of service as a director of the Company include
service during the time the Company was a subsidiary of Santa Fe Pacific
Corporation.
FIRST ELECTED
NAME, AGE AND BUSINESS EXPERIENCE A DIRECTOR
-------------
DIRECTORS CONTINUING IN OFFICE UNTIL 1999
Allan V. Martini, 71............................................... 1990
Retired Vice President Exploration and Production and director of
Chevron Corporation (petroleum operations) since August 1988. Mr.
Martini served in that position from July 1986 until his retirement.
Reuben F. Richards, 69............................................. 1992
Chairman of the Board, Terra Industries, Inc. (agribusiness) from
December 1982 until his retirement in March 1996; Chief Executive
Officer thereof from December 1982 to May 1991 and President thereof
from July 1983 to May 1991; Chairman of the Board, Engelhard
Corporation (specialty chemicals, engineering materials and precious
metals management services) from May 1985 to December 1994 and
director thereof since prior to 1990; Chairman of the Board Minorco
(U.S.A.) Inc. from May 1990 to March 1996 and Chief Executive
Officer and President from February 1994 to March 1996. Mr. Richards
is also a director of Ecolab, Inc. (cleaning and sanitizing
products), Engelhard Corporation and Potlatch Corporation (forest
products).
Kathryn D. Wriston, 59............................................. 1990
For the past five years, director of various corporations and
organizations, including Northwestern Mutual Life Insurance Company
(life insurance) and The Stanley Works (manufacturer of tools).
DIRECTORS CONTINUING IN OFFICE UNTIL 2000
William E. Greehey, 62,............................................ 1991
Chairman of the Board, Chief Executive Officer and director of
Valero Energy Corporation (refining and marketing) since 1983.
DIRECTORS CONTINUING IN OFFICE UNTIL 2001
Melvyn N. Klein, 57................................................ 1993
Attorney and Counselor at Law; private investor; the sole
stockholder of a general partner of GKH Partners, L.P., an
investment partnership. Mr. Klein is also a principal of Questor
Management Company, and director of Anixter International
(distributor of networking products), Bayou Steel Corporation
(specialty steel manufacturer) and Hanover Compressor Corporation
(provider of full service natural gas compression and fabricator of
compressors and production equipment).
James L. Payne, 61................................................. 1986
Chairman of the Board and Chief Executive Officer of the Company
since June 1990 and President from January 1990 until April 1, 1998.
Mr. Payne was President of Santa Fe Energy Company, a predecessor in
interest of the Company from January 1986 to January
33
<PAGE>
1990 when he became President of the Company. Mr. Payne is also a
director of Pool Energy Services Co. (oilfield services) and BJ
Services (oilfield services).
ITEM 11. EXECUTIVE COMPENSATION
REPORT OF THE COMPENSATION AND BENEFITS COMMITTEE
The Compensation and Benefits Committee (the "Committee") has been chartered
by the Board to review salaries and other compensation of officers, including
Mr. Payne, the Company's Chief Executive Officer, and key employees on an annual
basis. Following review, the Committee submits recommendations to the Board
regarding such salaries and compensation. In addition, the Committee selects
officers and key employees for participation in incentive compensation plans,
establishes performance goals for those officers and key employees who
participate in such plans and reviews and monitors benefits under all employee
plans of the Company.
COMPENSATION POLICIES FOR EXECUTIVE OFFICERS
As a result of an extensive review undertaken in 1995 with the assistance of
Hay Management Consultants, a performance based executive compensation program
was developed. The overall program was reviewed by Hay in 1998 and it was
determined by the Committee that the program continued to be appropriate, is
competitive, reinforces the Company's business strategy and supports objectives
for enhanced shareholder value. It is designed to attract, retain and motivate
key employees by providing total compensation opportunities consistent with
those maintained by the Company's peer group. The group used for this purpose
includes companies from the peer group used for purposes of the performance
graph, which companies the Committee believes approximate the Company's size and
asset mix. The program allows compensation to vary significantly based on
performance results, balance objectives for short-term operating performance,
and encourages stock ownership among key employees.
Base salaries for the executive and key employee group are maintained near
the median competitive position for comparable positions among the peer group.
Annual incentive opportunities are targeted to provide compensation between the
median and upper quartile of the Company's peer group described above. Long-term
incentive opportunities are provided through grants of stock options and Phantom
Units made pursuant to the Company's 1990 Incentive Stock Compensation Plan and
the 1995 Incentive Stock Compensation Plan for Non-executive Employees and
Directors (the "Stock Plans") and are targeted between median and upper quartile
award levels with upside opportunities based on sustained performance and
creation of shareholder value.
As a result of the review undertaken by Hay in 1998, it was determined that
Messrs. Payne, Boyt and Bridwell would not receive salary adjustments, while Ms.
Clark and Mr. Radtke as well as certain other executive officers and key
employees would receive modest increases.
Annual incentives are provided through the Incentive Compensation Plan (the
"IC Plan"). Goals are established which, if met at the target objective, will
result in the executive officer being paid 50 percent of the maximum amount for
which the individual is eligible. All executive officers participate in the IC
Plan with maximum payout percentages of base salary in 1998 ranging from 100
percent for Mr. Payne to 40 percent. The Committee may increase or decrease the
ultimate award by 25 percent at its discretion.
The goals established for 1998 were based upon discretionary cash flow per
share, production, reserve replacement, the performance of the Company's common
stock as compared to the peer group shown in the performance graph and an
individual discretionary award. The awards were subject to reduction by 50% in
the event the Company failed to achieve net income to common shareholders.
Discretionary cash flow per share is
34
<PAGE>
defined as net cash provided by operating activities before changes in operating
assets and liabilities minus exploration dry hole costs plus total exploration
expense minus capitalized interest divided by the average number of common
shares outstanding. The discretionary cash flow and production goals each
comprised 25% of the total award with the reserve replacement and stock price
performance goals each comprising 20% of the total award. The individual
discretionary award was potentially payable up to 10% of the total award. With
the exception of the stock performance goal and the discretionary award, the
goals were compared against profit plan projections. The discretionary cash flow
and production goals were not met, the reserve replacement goal was met in full
and the stock price performance goal was met at the 50% level. An average
individual discretionary award of 8% was also granted. Since the Company failed
to achieve net income to common shareholders, the payout was reduced by 50%. The
Committee, however, exercised its discretion and increased all awards by 25% of
the maximum potential award thereby causing an overall average payout of 44%.
In addition to the above described cash payments, the executive officers and
key employees are eligible to participate in grants made under the Stock Plans.
In order to further the identity of interest of employees with that of its
shareholders, all forms of compensation under the Stock Plan relate to common
stock.
As part of the ongoing strategy discussed above, in July and October 1998,
the Committee granted Mr. Payne, the executive officers other than Mr. Bridwell
and other key employees Non-Qualified Stock Options ("NQSOs") as noted in the
table entitled "Option/SAR Grants in Last Fiscal Year". The October grant was
made in lieu of a salary increase for most individuals including Mr. Payne. All
grants were made at fair market value. The July awards vest as to one-third of
the grant per year over a three-year period and the October awards vest at the
conclusion of a three year period.
Also, as part of the strategy discussed above, in December 1998, the
Committee granted a total of 200,943 Phantom Units to 21 individuals, including
Mr. Payne and the executive officers other than Mr. Bridwell. Mr. Payne received
49,050 Units, Mr. Boyt 17,857 Units, Ms. Clark 12,799 Units, and Mr. Radtke
12,799 Units. The remaining individuals participating in the grant received
Units in amounts ranging from 5,357 to 12,799. The Units are earned over a three
year period commencing January 1, 1999 with ultimate payout, if any, to be made
in an equivalent number of shares of common stock. The Committee established
four equally weighted goals which must be attained over this three-year period.
Full payment will result if discretionary cash flow (as described above) and
production volumes equal the three year projected levels established by the 1999
profit plan, the common stock price performance equals the S&P 500 Index over
the three year period and the common stock price at the end of the three years
equals an established target. If the above goals are substantially exceeded,
possible payouts may increase by 100 percent. Failure to meet a threshold goal
level will result in the reduction or total elimination of a payout.
CHIEF EXECUTIVE COMPENSATION
The review of executive compensation discussed above included a review of Mr.
Payne's compensation. As in the case of most of the executive officers, as a
result of the review of the peer group, it was determined that Mr. Payne's
salary not be increased in 1998. Mr. Payne did receive a grant of 110,000 NQSOs
with a strike price of $10.625 in June 1998 and 200,000 NQSOs with a strike
price of $8.125 in October 1998.
SECTION 162 (M) OF THE INTERNAL REVENUE CODE OF 1986, AS AMENDED
The Committee continues to review implications of the $1 million pay cap
rules set forth in Section 162 (m) of the Internal Revenue Code of 1986, as
amended, and takes this into account when establishing and reviewing
compensation policies.
35
<PAGE>
COMPENSATION AND BENEFITS COMMITTEE
William E. Greehey, Chairman
Reuben F. Richards
Kathryn D. Wriston
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
No member of the Compensation and Benefits Committee was an officer or
employee of the Company in 1996, 1997 or 1998. Mr. Greehey is Chairman of the
Board and Chief Executive Officer of Valero Energy Corporation. During 1998, an
affiliate of Valero paid the Company $641,519 for compression of natural gas.
These fees were determined on an arm's length basis. Mr. Greehey did not have a
direct or personal interest in the above transactions and his interest arises
only because of his position as an officer and director of Valero and as a
director of the Company.
The following table summarizes certain information regarding compensation
paid or accrued by the Company during each of the last three fiscal years to the
Chief Executive Officer and each of the Company's four other most highly
compensated executive officers:
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION PAYOUTS
------------ ---------
SECURITIES
UNDERLYING LTIP ALL OTHER
OPTIONS/SARS PAYOUT COMPENSATION
YEAR SALARY $ BONUS $ (1) #S (2) $ (3) $ (4)
--------- --------- ----------- ---------- --------- ------------
<S> <C> <C> <C> <C> <C> <C>
James L. Payne .................... 1998 515,000 231,750 310,000 -- 28,767
Chairman of the Board 1997 515,000 562,464 60,000 -- 30,500
and Executive Officer 1996 515,000 708,125 225,000 515,025 30,900
Hugh L. Boyt ...................... 1998 245,000 90,956 125,000 -- 13,447
President and Chief 1997 230,000 171,271 20,000 -- 13,400
Operating Office 1996 230,000 215,625 70,000 140,625 13,800
Jerry L. Bridwell ................. 1998 230,000 77,625 -- -- 10,920
Senior Vice President - 1997 230,000 188,398 20,000 -- 11,560
Exploration and Land 1996 230,000 172,500 70,000 140,625 12,420
Janet F. Clark (5) ................ 1998 225,000 75,938 110,000 -- 11,747
Senior Vice President - 1997 206,250 138,558 135,000 -- 7,159
Finance, Chief Financial 1996 -- -- -- -- --
Officer and Treasurer
Duane C. Radtke ................... 1998 199,250 63,885 115,000 -- 10,935
Senior Vice President - 1997 187,000 122,541 20,000 -- 10,640
Production 1996 170,208 146,850 45,000 87,495 9,684
</TABLE>
(1)The bonus amounts shown for 1998 were payable in cash, while the amounts in
1997 and 1996, although determined on a cash basis, were actually paid in
shares of common stock pursuant to the IC Plan. For 1997, Messrs. Payne,
Boyt, Bridwell, Ms. Clark and Mr. Radtke received 9,798, 3,282, 3,282, 2,414
and 2,135 shares of Bonus Stock and 44,091, 9,846, 14,769, 10,862, and 9,606
shares of Restricted Stock, respectively. For 1996, Messrs. Payne, Boyt,
Bridwell and Radtke received 6,460, 2,084, 3,067 and 1,059 shares of Bonus
Stock and 41,200, 9,200, 0, and 8,544 shares of Restricted Stock,
respectively.
36
<PAGE>
(2)As a result of the Spin-Off by the Company in July 1997, all outstanding
NQSOs were adjusted to reflect the effect of the transaction on the value of
the Company's common stock. The anti-dilution formula follows the Internal
Revenue Service approved guidelines for adjusting Qualified Incentive Stock
Options and took into account the average sales prices for the Company's
common stock for a period of time before and after the Spin-Off. As a result
of the adjustment, the number of options outstanding increased by a factor of
1.7045 and the strike price was reduced accordingly at that time. The Company
will receive the same overall consideration for the underlying securities
upon exercise of the option. All outstanding Phantom Units were also adjusted
utilizing the same formula. All other terms and conditions of the options and
the Phantom Units remained unchanged.
As a result of the adjustment, the number of options granted in 1996 as shown
in the table to Messrs. Payne, Boyt, Bridwell and Radtke were increased to
383,513, 119,316, 119,316 and 76,703, respectively. The options shown as
granted in 1997 for these individuals were granted following the Spin-Off and
no adjustment was made to these options. Ms. Clark received two option grants
in 1997. The first grant of 100,000 options was made prior to the Spin-Off
and was increased to 170,450 options as a result of the adjustment. The
second grant of 35,000 options was made following the Spin-Off and therefore
no adjustment was made to these options.
(3)The amounts reflect the value of shares of common stock received as a result
of the accelerated payout of the Phantom Units in November 1996.
(4)Amounts shown reflect matches made by the Company for employee contributions
to the Santa Fe Energy Resources, Inc. Savings Investment Plan as well as the
performance match. (See "- Benefit Plans - Savings Plan" for a description of
the Savings Investment Plan and the performance match). The performance match
is contributed in the year following the performance and therefore total
amounts shown for 1996, 1997 and 1998 include the match made for 1995, 1996
and 1997 results, respectively. The Company made a performance match in
February 1999 for 1998 results for Messrs. Payne, Boyt, Bridwell, Ms. Clark
and Mr. Radtke in the amount of $1,408 for each individual. In addition,
amounts shown for 1997 and 1998 also include the match made by the Company
relating to deferrals under the Deferred Compensation Plan. (See "- Benefit
Plans Savings Plan" for a description of the Deferred Compensation Plan).
These amounts are also subject to the performance match outlined in the
Savings Investment Plan. In February 1999, the Company allocated to accounts
maintained by Messrs. Payne, Boyt, Bridwell, Ms. Clark and Mr. Radtke $3,124,
$749, $312, $572 and $345, respectively, as a performance match.
(5) Ms. Clarks's employment with the Company commenced on January 1, 1997.
STOCK OPTION GRANTS DURING 1998
The following table sets forth information with respect to grants of options
pursuant to the Stock Plan. The NQSOs were granted at market on the date of the
grant and as to the first grant shown vests one-third per year over a three-year
period. The second grant shown vests in full, three years following the grant
date.
37
<PAGE>
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS POTENTIAL REALIZABLE
------------------------------- VALUE AT ASSUMED
NUMBER OF PERCENT OF RATES OF STOCK
SECURITIES TOTAL PRICE
UNDERLYING OPTIONS/SARS EXERCISE APPRECIATION FOR
OPTIONS/SARS GRANTED TO OR BASE OPTION TERM
GRANTED EMPLOYEES IN PRICE EXPIRATION --------------------------
NAME #S FISCAL YEAR ($/SH) DATE 5% ($) 10% ($)
- -------------- --------- ----------- --------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
James L. Payne .................. 110,000 6.28% 10.625 6/29/08 735,009 1,862,696
200,000 11.43% 8.125 10/28/08 1,021,960 2,589,820
Hugh L. Boyt .................... 45,000 2.57% 10.625 6/29/08 300,685 762,012
80,000 4.57% 8.125 10/28/08 408,784 1,035,928
Jerry L. Bridwell ............... -- -- -- -- -- --
Janet F. Clark .................. 45,000 2.57% 10.625 6/29/08 300,685 762,012
65,000 3.71% 8.125 10/28/08 332,137 841,691
Duane C. Radtke ................. 55,000 3.14% 10.625 6/29/08 367,504 931,348
60,000 3.43% 8.125 10/28/08 306,588 776,946
</TABLE>
AGGREGATED OPTION/SAR EXERCISES DURING 1998 AND OPTION/SAR
VALUES AT DECEMBER 31, 1998
<TABLE>
<CAPTION>
NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS/SARS
SHARES OPTIONS/SARS AT AT DECEMBER 31, 1998 (1)
ACQUIRED VALUE DECEMBER 31, 1998 ($)
ON REALIZED ----------------------------- ------------------------------
NAME EXERCISE ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- -------- --- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
James L. Payne...................... - -- 1,507,842 477,838 1,236,815 24,426
Hugh L. Boyt........................ - -- 470,143 178,105 422,404 8,549
Jerry C. Bridwell................... - -- 552,971 53,105 422,404 8,549
Janet F. Clark...................... - -- 125,300 190,150 -- --
Duane C. Radtke..................... - -- 137,915 153,900 183,333 4,885
</TABLE>
(1) The closing price of common stock on December 31, 1998 was $7.25.
LONG TERM INCENTIVE PLANS AWARDS IN 1998
<TABLE>
<CAPTION>
NUMBER OF PERFORMANCE OR OTHER ESTIMATED FUTURE PAYOUT UNDER
SHARES, UNITS PERIOD UNTIL NON-STOCK PRICE-BASED PLANS
OR OTHER MATURATION OR THRESHOLD TARGET MAXIMUM
NAME RIGHTS # PAYOUT # # #
- ---- -------- ----------------- --------- ------- ---------
<S> <C> <C> <C> <C> <C>
James L. Payne ............... 49,050 1/1/99 - 12/31/01 7,357 49,050 98,100
Hugh L. Boyt ................. 17,857 1/1/99 - 12/31/01 2,678 17,857 35,714
Jerry L. Bridwell ............ -- 1/1/99 - 12/31/01 -- -- --
Janet F. Clark ............... 12,799 1/1/99 - 12/31/01 1,919 12,799 25,598
Duane C. Radtke .............. 12,799 1/1/99 - 12/31/01 1,919 12,799 25,598
</TABLE>
In December 1998, the individuals described above (as well as other executive
officers and key employees) received grants of Phantom Units pursuant to the
Stock Plans in the amounts indicated. The grant was effective January 1, 1999
with the Units being earned over a three-year period. Ultimate payout, if any,
is to be made in an equivalent number of shares of common stock. Four equally
weighted goals have been established which must be attained over the three-year
performance period. Full payout at the target level will result if discretionary
cash flow and production volumes equal the three year projected levels
established by the 1999 profit plan, the common stock price performance equals
the S&P 500 Index over the three-year period and the common stock price at the
end of the three years equals an established target. If the above
38
<PAGE>
goals are substantially exceeded, possible payouts may increase to the maximum
shown. Failure to meet a threshold level, shown above as the combined threshold
level of all four goals, will result in a reduction or total elimination of a
payout.
CHANGE IN CONTROL
The Stock Plans and the IC Plan contain "Change in Control" provisions. A
Change in Control is generally defined to occur if (a) any "person" becomes the
beneficial owner of securities representing 25% or more of the voting power of
the Company's outstanding securities; or (b) during any period of two
consecutive years, individuals who at the beginning of such period constitute
the Board of Directors cease to constitute at least a majority of the Board; or
(c) the Company's stockholders approve a merger or consolidation of the Company
with another corporation and the voting securities of the Company outstanding
immediately prior thereto do not represent 65% of the combined voting power of
the voting securities outstanding immediately thereafter; or (d) the Company's
stockholders approve a plan of complete liquidation or an agreement for the sale
or disposition by the Company of all or substantially all of its assets. The
proposed merger with Snyder described in Part I, Items 1 and 2. "Business and
Properties - Proposed Merger" would result in a Change in Control. Therefore, at
the time of the merger all stock options granted under the Stock Plans would
become exercisable, all restrictions on Restricted Stock would lapse, all goals
associated with Phantom Units awards would be deemed met at the maximum level
and such awards would become payable in cash and each participant in the IC Plan
who remains employed at year-end would be entitled to the maximum bonus that
would have been payable if all performance goals had been met in full.
PERFORMANCE GRAPH
The following performance graph compares the performance of the common stock
to the S&P 500 Index and to an index composed of independent oil and gas
companies which the Company believes have an asset base and operations which are
comparable to those of the Company.
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN (1) AMONG
SANTA FE ENERGY RESOURCES, INC.
THE S&P 500 INDEX AND A PEER GROUP (2)
MEASUREMENT PERIOD SANTA FE ENERGY
(FISCAL YEAR COVERED) RESOURCES, INC. PEER GROUP S & P 500
--------------------- --------------- ---------- ---------
12/93 100 100 100
12/94 86 88 101
12/95 104 107 139
12/96 150 140 171
12/97 217 133 229
12/98 140 92 294
(1)$100 invested on December 31, 1993 in stock or index - including
reinvestment of dividends. Fiscal year ending December 31.
(2)This group of companies, which includes the Company, also currently includes
Anadarko Petroleum Corp., Apache Corp., Barrett Resources Corp., Burlington
Resources, Cabot Oil & Gas, Cross Timbers Oil Co., Devon Energy, Enron Oil &
Gas, Mitchell Energy & Development, Noble Affiliates, Inc., Ocean Energy
(reflects value of United Meridian Corporation through date of merger with
Ocean Energy on March 27, 1998) Oryx Energy Co., PennzEnergy (formerly
Pennzoil Co.), Pioneer Natural Resources, Pogo Producing Company, Seagull
Energy Corp, Vastar Resources, Inc., and Vintage Petroleum. Due to activities
such as reorganizations and mergers, additions and deletions are made to the
group from time to time.
39
<PAGE>
BENEFIT PLANS
The Company maintains a 401(k) savings plan and a retirement income plan. In
addition, the Company has entered into employment agreements with certain
officers and key employees and maintains a severance program for all full-time
salaried employees. These plans and agreements are briefly described below.
SAVINGS PLAN. The Company has adopted the Santa Fe Energy Resources Savings
Investment Plan. The Savings Investment Plan offers eligible employees an
opportunity to make long-term investments on a regular basis through salary
contributions, which are supplemented by matching employer contributions.
Substantially all salaried employees are eligible to participate on the first
day of the month after their date of hire. The Company will match an employee's
contribution up to 4% of such employee's compensation.
In addition to the employer match described above, at the end of each fiscal
year, the Company's performance is evaluated using the same performance measures
used in the IC Plan. If the performance meets or exceeds goals for that year,
participants will receive up to another fifty cents on each regular matching
dollar contributed by the Company. The regular employer matching contributions
as well as the performance match are made in common stock. The goals were 44%
met in 1998 and a partial performance match was made in February 1999.
The Savings Investment Plan is intended to qualify as a Section 401(k) cash
or deferred compensation arrangement whereby an employee's contributions and the
employer's matching contributions are not subject to federal income taxes at the
time of the contribution to the Savings Investment Plan, and the Savings
Investment Plan is subject to the restrictions imposed by the Code. A variety of
investment alternatives are offered, including a fund which is invested in
common stock.
The Company also maintains a Deferred Compensation Plan whereby employees
earning in excess of $100,000 per year are allowed to defer all or a portion of
their salary until any future year or retirement. These amounts are not matched
by the Company. Employees earning in excess of $160,000 per year many also defer
up to 4% of such excess and the amount will be matched by the Company. The
amount contributed is also subject to the performance match described above in
the Savings Investment Plan.
RETIREMENT PLANS. The Company has adopted the Santa Fe Energy Resources
Retirement Income Plan, a qualified defined benefit plan for substantially all
salaried employees, and the Santa Fe Energy Resources Supplemental Retirement
Plan. The Supplemental Plan will pay benefits to Retirement Plan participants
where the Retirement Plan formula produces a benefit to members in excess of
limits imposed by ERISA and applicable government regulations. It also includes
amounts deferred under the Deferred Compensation Plan as pensionable
compensation. Benefits which have accrued to the Company's participants under
both the Retirement Income Plan and Supplemental Plan are shown below for
selected compensation levels and years of service. As of December 31, 1998,
Messrs. Payne, Boyt, Bridwell, Radtke and Ms. Clark were credited with 16.8,
15.2, 24.8, 6.7 and 2.0 years of service under the plans, respectively.
40
<PAGE>
PENSION PLAN TABLE
YEARS OF SERVICE
AVERAGE YEARLY -----------------------------------------------------------
COMPENSATION 15 20 25 30 35
- ------------------- --------- --------- --------- --------- ---------
$250,000........... $ 45,000 $ 60,000 $ 75,000 $ 112,000 $ 131,000
$350,000........... $ 63,000 $ 84,000 $ 106,000 $ 158,000 $ 185,000
$450,000........... $ 82,000 $ 109,000 $ 137,000 $ 205,000 $ 239,000
$550,000........... $ 101,000 $ 134,000 $ 168,000 $ 251,000 $ 293,000
$650,000........... $ 119,000 $ 159,000 $ 199,000 $ 298,000 $ 348,000
$750,000........... $ 138,000 $ 184,000 $ 230,000 $ 344,000 $ 402,000
$850,000........... $ 156,000 $ 208,000 $ 261,000 $ 391,000 $ 456,000
$950,000........... $ 175,000 $ 233,000 $ 292,000 $ 437,000 $ 510,000
Benefit figures shown are amounts payable based on a straight life annuity
assuming retirement by the participant at age 62 in 1998 without a joint
survivorship provision. The benefits listed in the above table are not subject
to any deduction for social security or other offset amounts.
Benefits under the plans are computed based on a participant's total basic
compensation for the 60 consecutive months during the ten-year period
immediately prior to the termination of his covered employment for which his
total compensation is the highest, divided by 60. If a participant has not
received compensation for 60 consecutive months during such ten-year period, his
compensation shall equal the total of his compensation for the longest period of
consecutive months during such ten-year period divided by the total number of
months of compensation so considered.
Compensation recognized under the plans is the total basic compensation,
including any elective salary deferral amounts excluded from income pursuant to
Section 125 or 402 of the Code, plus overtime, shift differentials and bonuses
(whether cash or stock) paid pursuant to recurring bonus programs, including
compensation deferred under the Deferred Compensation Plan, but excluding any
special or extraordinary bonuses and any other items of compensation. A
participant's basic compensation is the regular rate of pay specified for his
position and does not include automobile allowances, imputed income under any
group term life insurance program, moving expense or other reimbursements,
fringe benefits, or similar items.
The pension compensation therefore differs from the compensation listed in
the Summary Compensation Table in several respects. Pension compensation is
based on average compensation as explained above. It does not include restricted
stock awards, stock options and other compensation in the "All Other
Compensation" column (i.e., employer matching contributions to the Savings
Investment Plan and the performance match). It also does not include special or
extraordinary bonuses.
The pension compensation of officers listed in the Summary Compensation Table
is listed below:
PENSION COMPENSATION
NAME (FINAL AVERAGE PAY)
- ------------ -------------------
James L. Payne........................................... $ 799,900
Hugh L. Boyt............................................. $ 339,900
Jerry L. Bridwell........................................ $ 338,400
Duane C. Radtke.......................................... $ 251,600
Janet F. Clark........................................... $ 303,100
EMPLOYMENT AGREEMENTS. The Company has entered into employment agreements
(the "Employment Agreements") covering 14 employees of the Company (including
each of the individuals named in the Summary Compensation Table). The Employment
Agreements are intended to encourage such employees to remain in the employ of
the Company. The initial term of each Employment Agreement expires on December
41
<PAGE>
31, 1999; however, beginning on January 1, 1998 and on each January 1
thereafter, the term is automatically extended for an additional one-year
period, unless by September 30 of the preceding year the Company gives notice
that the Employment Agreement will not be so extended. The term of the
Employment Agreement, however, is automatically extended for a minimum period of
24 months following a Change in Control (three years in the case of Mr. Payne).
A Change in Control is defined substantially the same as in the Stock Plans.
In the event that following a Change in Control (and during the term of the
Employment Agreement) employment is terminated by the employee for "Good Reason"
or the employee is involuntarily terminated by the Company other than for
"Cause" (as those terms are defined in the Employment Agreements), or if during
the six months preceding a Change in Control, the employee's employment is
terminated by the employee for Good Reason or by the Company other than for
Cause, and such termination is demonstrated to be connected with the Change in
Control, the Employment Agreements provide for payment of certain amounts to the
employee based on the employee's salary and bonus under the IC Plan; payout of
nonvested restricted stock, phantom units, stock options, if any, and
continuation of certain insurance benefits on a tax neutral basis for a period
of up to 24 months (36 months in the case of Mr. Payne). The payments and
benefits are payable pursuant to the Employment Agreement only to the extent
they are not paid out under the terms of any other plan of the Company. The
payments and benefits provided by the Employment Agreements may be further
limited by certain restrictions commonly known as Parachute Payment limitations
as set forth in the Employee Agreements. In the event Mr. Payne's payments would
exceed the Parachute Payment Limits, he will be made "whole" on a net after-tax
basis for any excise tax incurred. Without giving effect to such limitation, the
estimated value of the payments and benefits that Messrs. Payne, Boyt, Bridwell,
Ms. Clark and Mr. Radtke and all executive officers as a group would be entitled
to receive if a qualifying termination occurred on February 1, 1999 would be
$3,022,096, $858,022, $795,360, $628,726 and $668,532 and $9,135,126,
respectively.
SEVERANCE PROGRAM. The Company has adopted severance programs for all
full-time salaried employees who are terminated by the Company or terminated or
constructively terminated by an acquiring company, other than for Cause (as
defined in the Severance Program). However, following a Change in Control
(defined substantially the same as in the Stock Plans), an executive officer or
key employee who has entered into an Employment Agreement is not eligible to
receive duplicate benefits under the Employment Agreement and Severance Program.
A participant in the severance programs is generally entitled to an amount of up
to 78 months' pay based upon a participant's age, length of service and highest
rate of base salary in effect during the 24-month period preceding his
termination, provided that the aggregate of such payment does not exceed two
times the participant's actual salary for the 12-month period preceding the date
of termination. In addition, a participant is entitled to continuation of health
and life insurance benefits for up to a period of two years.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
To the best of the Company's knowledge, the following persons are the only
persons who are beneficial owners of more than five percent of the Company's
common stock based upon the number of shares outstanding on February 1, 1999:
NUMBER OF
SHARES OF
COMMON PERCENT
NAME AND ADDRESS STOCK (1) OF CLASS
------------------ ------------- --------
HC Associates (2).................................. 5,203,091 5.1
200 West Madison Street
38th Floor
Chicago, IL 60606
42
<PAGE>
NUMBER OF
SHARES OF
COMMON PERCENT
NAME AND ADDRESS STOCK (1) OF CLASS
------------------ ------------- --------
MacKay-Shields Financial Corporation (3)............ 7,500,700 7.3
9 West 57th Street
New York, NY 10019
FMR Corp. (4).......................................10,225,572 10.0
82 Devonshire Street
Boston, MA 02109
(1)Each holder has claimed the sole voting and investment power concerning
these shares except as noted below.
(2)As reported at May 31, 1995, HC Associates, a Delaware general partnership
("HC") is the owner of 5,203,091 shares (approximately 5.1 percent) of the
Company's common stock. HC was organized in December 1992 for the purpose
of, among other things, acquiring, holding, selling, exchanging and
otherwise dealing with shares of the Company's common stock. The partners
of HC (and their respective percentage interests in HC) are GKH
Investments, L.P. (the "GKH Fund") (92.743587%), GKH Partners, L.P. ("GKH")
as nominee for GKH Private Limited ("GKHPL") (3.506488%), Cockrell Equity
Partners, L.P. (1.089978%) and Cockrell Investment Partners, L.P.
(2.659947%). The sole general partner of the GKH Fund, a Delaware limited
partnership, is GKH. Pursuant to a management agreement, GKH manages assets
on behalf of GKHPL. The number of shares described above does not include
39,100 shares of Common Stock acquired in September 1994 by GKH on behalf
of GKHPL and the GKH Fund. The general partners of GKH are JAKK Holding
Corp., a Nevada corporation ("JAKK"), DWL Lumber Corporation, a Delaware
corporation ("DWL"); and HGM Associates Limited Partnership, an Illinois
limited partnership ("HGMLP"). The sole general partner of HGMLP is HGM
Corporation, a Nevada corporation ("HGM"). Melvyn N. Klein is the sole
director and stockholder of JAKK and serves as its president, treasurer and
secretary. Mr. Klein disclaims beneficial ownership of the shares of the
Company's common stock owned by HC, GKH, GKHPL and the GKH Fund. Dan W.
Lufkin is president, director and sole stockholder, Craigh Leonard is
secretary and a director and Douglas J. McBride is assistant secretary and
a director of DWL. Thomas J. Pritzker is Chairman of the Board, president
and a director, Glen Miller is vice president, treasurer and a director and
Harold S. Handelsman is vice president and secretary of HGM.
(3)As reported at February 16, 1999, as of December 31, 1998, MacKay-Shields
Financial Corporation, an investment advisor, was the beneficial owner of
7,500,700 shares of the Company's common stock. Clients of MacKay-Shields
Financial Corporation have the right to receive and the ultimate power to
direct the receipt of dividends from, or the proceeds of the sale of, such
securities. No interest of any such client relates to more than 5% of the
outstanding securities of the Company.
(4)As reported at February 10, 1999, as of January 31, 1999 Fidelity
Management & Research Company ("Fidelity"), 82 Devonshire Street, Boston,
Massachusetts 02109, a wholly owned subsidiary of FMR Corp. and an
investment adviser registered under Section 203 of the Investment Advisers
Act of 1940, was the beneficial owner of 9,367,655 shares or 9.2% of the
common stock outstanding of the Company as a result of acting as investment
adviser to various investment companies registered under Section 8 of the
Investment Company Act of 1940.
43
<PAGE>
The ownership of one investment company, Fidelity Dividend Growth Fund,
amounted to 7,963,600 or 7.5% of the common stock outstanding of the
Company. Fidelity Dividend Growth Fund has its principal business office at
82 Devonshire Street, Boston, Massachusetts 02109.
Edward C. Johnson, 3d, FMR Corp., through its control of Fidelity, and the
Fidelity Funds each has the power to dispose of the 9,367,655 shares owned
by the funds. Neither FMR Corp. nor Edward C. Johnson 3d, Chairman of FMR
Corp., has the sole power to vote or direct the voting shares owned
directly by the Fidelity Funds, which power resides with the Funds' Board
of Trustees. Fidelity carries out the voting of the shares under written
guidelines established by the Funds' Board of Trustees.
Fidelity Management Trust Company ("FMT"), 82 Devonshire Street, Boston,
Massachusetts 02109, a wholly owned subsidiary of FMR Corp. and a bank as
defined in Section 3(a)(6) of the Securities Exchange Act of 1934, is the
beneficial owner of 857,917 shares or less than 1% of common stock
outstanding of the Company as a result of its serving as investment manager
of the institutional account(s). Mr. Johnson and FMR Corp., through its
control of FMT, each has dispositive power over 857,917 shares and sole
power to vote or to direct the voting of 701,679 shares, and no power to
vote or to direct the voting of 156,230 shares of common stock owned by the
institutional accounts(s) as reported above.
Members of Mr. Johnson's family and trust for their benefit are the
predominant owners of Class B shares of common stock of FMR Corp.,
representing approximately 49% of the voting power of FMR Corp. Mr. Johnson
owns 12% and Abigail Johnson owns 24.5% of the aggregate outstanding voting
stock of FMR Corp. Mr. Johnson is Chairman of FMR Corp. and Abigail P.
Johnson is a Director of FMR Corp. The Johnson family group and all other
Class B shareholders have entered into a shareholders' voting agreement
under which all Class B shares will be voted in accordance with the
majority vote of Class B shares. Accordingly, through their ownership of
voting common stock and the execution of the shareholders' voting
agreement, members of the Johnson family may be deemed, under the
Investment Company Act of 1940, to form a controlling group with respect to
FMR Corp.
The following table sets forth the amount of common stock beneficially owned
as of February 1, 1999, by each of the directors and executive officers and by
all directors and executive officers as a group. Unless otherwise noted, each of
the named persons and members of the group has sole voting and investment power
with respect to the shares shown.
<TABLE>
<CAPTION>
NAME OF DIRECTOR, SHARES OWNED PERCENT
EXECUTIVE OFFICER OR GROUP BENEFICIALLY OF CLASS
------------------------------------ --------------- ----------
<S> <C> <C>
William E. Greehey (1).................................... 91,317 -
Melvyn N. Klein (2)....................................... 5,090,294 4.9
Allan V. Martini (1)...................................... 49,998 -
Reuben F. Richards (1).................................... 48,478 -
Kathryn D. Wriston (1).................................... 48,720 -
James L. Payne (3)........................................ 1,931,912 1.9
Hugh L. Boyt (4).......................................... 549,176 -
Jerry L. Bridwell (5)..................................... 687,864 -
Janet F. Clark (6)........................................ 156,973 -
Duane C. Radtke (7)....................................... 203,679 -
Directors and Executive Officers as a Group - 17 (8)...... 10,114,384 9.9
</TABLE>
(1) Includes 39,091 shares which could be received upon the exercise of options
within 60 days. The weighted average exercise price of such options is
$7.2985.
44
<PAGE>
(2) Includes 5,048,083 shares of common stock which may be deemed to be owned
by GKH primarily through its participation in HC Associates. See "-
Security Ownership of Certain Beneficial Owners" for a description of
ownership of common stock by HC Associates. Mr. Klein is the sole
stockholder of one of the general partners in GKH, the general partner of
GKH Investments, L.P. and the nominee for GKH Private Limited and disclaims
beneficial ownership of the shares held by HC Associates. Also includes
39,091 shares which could be received upon the exercise of options within
60 days. The weighted average exercise price of such options is $7.2985.
(3) Mr. Payne's stock ownership includes 67,584 shares of common stock arising
from participation in the Company's Savings Investment Plan and 1,507,843
shares of common stock which could be received upon the exercise of options
within 60 days. The weighted average exercise price of such options is
$7.83. In addition, Mr. Payne's total includes 1,000 shares owned by his
wife. Mr. Payne disclaims beneficial ownership of these shares. Finally,
the total shares shown reflect 81,240 shares of Restricted Stock, which are
subject to forfeiture pursuant to the terms of the Stock Plan.
(4) Mr. Boyt's stock ownership includes 8,127 shares of common stock arising
from participation in the Company's Savings Investment Plan and 470,143
shares of common stock which could be received upon the exercise of options
within 60 days. The weighted average exercise price of such options is
$6.94. Finally, the total shares shown reflect 17,892 shares of Restricted
Stock which are subject to forfeiture pursuant to the terms of the Stock
Plan.
(5) Mr. Bridwell's stock ownership includes 45,006 shares of common stock
arising from participation in the Company's Savings Investment Plan and
552,971 shares of common stock which could be received upon the exercise of
options within 60 days. The weighted average exercise price of such options
is $7.91. In addition, Mr. Bridwell's total includes 2,472 shares owned by
his children. Finally, the total shares shown reflect 14,769 shares of
Restricted Stock which are subject to forfeiture pursuant to the terms of
the Stock Plan.
(6) Ms. Clark's stock ownership includes 3,198 shares of common stock arising
from participation in the Company's Savings Investment Plan and 125,300
shares of common stock which could be received upon the exercise of options
within 60 days. The weighted average exercise price of such options is
$8.45. Finally, the total shares shown reflect 10,862 shares of Restricted
Stock which are subject to forfeiture pursuant to the terms of the Stock
Plan.
(7) Mr. Radtke's stock ownership includes 12,445 shares of common stock arising
from participation in the Company's Savings Investment Plan and 137,914
shares of common stock which could be received upon the exercise of options
within 60 days. The weighted average exercise price of such options is
$6.29. Finally, the total shares shown reflect 15,302 shares of Restricted
Stock which are subject to forfeiture pursuant to the terms of the Stock
Plan.
(8) The stock ownership described includes 247,360 shares arising from
participation in the Company's Savings Investment Plan, 205,875 shares of
Restricted Stock and 4,195,922 shares which could be received upon the
exercise of options within 60 days.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Mr. Payne is also a director of Pool Energy Services Co., which provides
various oilfield services. During 1998 the Company paid Pool subsidiaries an
aggregate of $117,651 for services performed on properties operated by the
Company. Mr. Payne is also a director of BJ Services which also provides various
oilfield services. During 1998 the Company paid BJ Services an aggregate of
$1,314,953 for services performed on properties operated by the Company. Mr.
Payne has no direct or personal interest in these services. His
45
<PAGE>
interest arises only because of his position as an officer of the Company and a
director of Pool Energy Services Co. and BJ Services. In the opinion of the
Company, the amounts paid for services performed by Pool and BJ Services were
competitive and were normal and customary in the industry.
Mr. Klein is the sole stockholder of a general partner in GKH. The Company
entered into an Agreement Regarding Shelf Registration dated March 24, 1995,
with HC Associates ("HC") which owns more than 5% of the Company's common stock
whereby the Company agreed that upon written demand (which demand may be
submitted to the Company once, provided such registration is effected and the
registration statement is declared effective) from HC, GKH, GKH Investments,
L.P., Cockrell Equity Partners, L.P. and Cockrell Investment Partners, L.P.
(collectively, the "Selling Stockholders") at any time prior to March 27, 2000
to file with the Securities and Exchange Commission a registration statement to
register the offer and sale, from time to time, by the Selling Stockholders of
up to 5,203,091 shares of the Company's common stock beneficially owned by them
as of March 24, 1995, subject to certain specified restrictions. The Company is
obligated to pay all expenses incidental to such registration, excluding
underwriting discounts, commissions, fees or disbursements of legal counsel for
the Selling Stockholders. This agreement was amended in 1997 to include two
demand rights (provided that any one-demand cover at least 40% of its holdings)
and up to two piggyback rights.
See also "- Compensation Committee Interlocks and Insider Participation" and
"- Security Ownership of Certain Beneficial Owners."
OTHER INFORMATION CONCERNING DIRECTORS. In 1998, the Board met six times, and
each member of the Board as it was composed at the time attended at least 75% of
the total number of meetings of the Board and the total number of meetings held
by all committees of the Board on which he or she served.
DIRECTORS COMPENSATION. Directors who are not employees of the Company or its
subsidiaries receive an annual cash retainer fee of $10,000 (plus an additional
$2,000 annual retainer for the committee chairmen). Non-employee directors also
receive a fee of $1,000 for each meeting of the Board attended, and a fee of
$1,000 for each committee meeting attended plus expenses. In addition, pursuant
to the Stock Plans, non-employee directors receive annually (i) 2,000 shares of
Common Stock with a six month restriction period during which such shares cannot
be transferred and (ii) 5,000 NQSOs per year having a strike price of the Fair
Market Value (as defined in the Stock Plan) on the date of grant. In addition,
all newly elected directors receive a one-time grant of 10,000 NQSOs with a
strike price of the Fair Market Value on the date the director is first elected.
In connection with the amendment of the 1990 Stock Plan in 1996, current
directors received a similar one-time grant of 10,000 NQSOs effective February
1, 1996.
BOARD COMMITTEES. In 1998, the Board maintained Audit, Compensation and
Benefits, Executive and Nominating Committees. Following are the members of each
committee and brief descriptions of the functions of the Board Committees. All
chairpersons of the above committees are non-employee directors.
The members of the Audit Committee are Kathryn D. Wriston (Chairman), Reuben
F. Richards and Melvyn N. Klein. The principal functions of the Audit Committee,
which met three times during 1998, include overseeing the performance and
reviewing the scope of the audit function of independent accountants. The Audit
Committee also reviews, among other things, audit plans and procedures, the
Company's policies with respect to conflicts of interest and the prohibition on
the use of corporate funds or assets for improper purposes, changes in
accounting policies, and the use of independent accountants for non-audit
services.
The members of the Compensation and Benefits Committee are William E. Greehey
(Chairman), Kathryn D. Wriston and Reuben F. Richards. The principal function of
the Compensation and Benefits Committee, which met four times in 1998, is to
administer all executive compensation and benefit plans of the Company. In
addition, the Committee reviews the actions of the Pension Benefits Committee
which is composed of
46
<PAGE>
employees of the Company, making recommendations to the Board of Directors
concerning future membership of that committee and such other recommendations as
may be necessary or appropriate, and recommending to the Board of Directors
substantive amendments to the Company's retirement plan. Members of the
Compensation and Benefits Committee are not eligible to participate in any
benefit plans of the Company that they administer except the Stock Plans
pursuant to which grants may be made only as described above.
The members of the Executive Committee are Melvyn N. Klein (Chairman),
William E. Greehey, James L. Payne, Allan V. Martini and Reuben F. Richards. The
Executive Committee, which did not meet in 1998, may exercise, during periods
between meetings of the Board of Directors, all powers of the Board in the
management and business of the Company, subject to limitations imposed by the
Bylaws, Certificate of Incorporation or applicable law.
The members of the Nominating Committee are Allan V. Martini (Chairman),
Kathryn D. Wriston and James L. Payne. The Nominating Committee, which met once
in 1998, receives recommendations for review and evaluates the qualifications of
and selects and recommends to the Board of Directors, nominees for election as
Directors. The Nominating Committee will consider nominees recommended by
shareholders. Any such recommendation, together with the nominee's
qualifications and consent to be considered as a nominee, should be sent to in
writing to the Secretary of the Company not less than 90 days nor more than 120
days prior to the annual meeting.
47
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED ON THE 5TH DAY OF MARCH
1999.
SANTA FE ENERGY RESOURCES, INC.
(Registrant)
By: /S/ JANET F. CLARK
Janet F. Clark
Senior Vice President
Chief Financial Officer and Treasurer
(Principal Financial and Accounting Officer)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS IN THE CAPACITIES AND ON
THE DATES INDICATED.
SIGNATURE TITLE DATE
/S/ JAMES L. PAYNE Chairman of the Board March 5, 1999
James L. Payne and Chief Executive Officer
and Director
(Principal Executive Officer)
/S/ JANET F. CLARK Senior Vice President March 5, 1999
Janet F. Clark Chief Financial Officer and
Treasurer
(Principal Financial and
Accounting Officer)
/S/WILLIAM E. GREEHEY Director March 5, 1999
William E. Greehey
/S/ MELVYN N. KLEIN Director March 5, 1999
Melvyn N. Klein
/S/ ALLAN V. MARTINI Director March 5, 1999
Allan V. Martini
/S/REUBEN F. RICHARDS Director March 5, 1999
Reuben F. Richards
/S/KATHYRN D. WRISTON Director March 5, 1999
Kathryn D. Wriston
48
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
(A) The following documents are filed as part of this report:
PAGE
(1) Financial Statements
Report of Management.......................................... 50
Report of Independent Accountants............................. 51
Consolidated Statement of Operations -
Years Ended December 31, 1998, 1997 and 1996............... 52
Consolidated Balance Sheet - December 31, 1998 and 1997....... 53
Consolidated Statement of Cash Flows -
Years Ended December 31, 1998, 1997 and 1996............... 54
Consolidated Statement of Shareholders' Equity -
Years Ended December 31, 1998, 1997 and 1996............... 55
Notes to Consolidated Financial Statements.................... 56
(2) Supplemental Schedule
Schedule II - Valuation and Qualifying Accounts and Reserves.. 81
Exhibits
See Index of Exhibits which appears on page 82 herein.
(B) REPORTS ON FORM 8-K
The Company filed a Report on Form 8-K on December 11, 1998 announcing that
the date of its 1999 Annual Meeting of Stockholders will be held on May 11,
1999.
The Company filed a Report on Form 8-K on February 24, 1999 announcing that
the date of the Company's 1999 Annual Meeting of Stockholders will not be on May
11, 1999, as previously announced, due to the timing of the Company's Special
Meeting of Stockholders in connection with the proposed acquisition by the
Company of the outstanding stock of Snyder Oil Company. The Company will
announce the new date of the Annual Meeting when it has been determined by the
Board.
49
<PAGE>
REPORT OF MANAGEMENT
To the Stockholders of Santa Fe Energy Resources, Inc.
Management of Santa Fe is responsible for preparing the accompanying
financial statements and for assuring their integrity and objectivity. The
statements were prepared in accordance with generally accepted accounting
principles and fairly present the transactions and financial position of the
Company. The financial statements include amounts that are based on management's
best estimates and judgments.
The Company's financial statements have been audited by
PricewaterhouseCoopers LLP, independent accountants selected by the Audit
Committee and approved by the stockholders. Management has made available to
PricewaterhouseCoopers LLP all of the Company's financial records and related
data, as well as the minutes of stockholders' and directors' meetings.
Management of the Company has established and maintains a system of internal
accounting controls that is designed to provide reasonable assurance that assets
are safeguarded, transactions are properly recorded and executed in accordance
with management's authorization, and the books and records accurately reflect
the disposition of assets. The system of internal controls includes appropriate
division of responsibility. The Company maintains an internal audit department
that conducts a comprehensive program of internal audits and independently
assesses the effectiveness of the internal controls.
The Board of Directors exercises its oversight role with respect to the
Company's system of internal controls primarily through its Audit Committee,
which is composed of directors who are not officers or employees of the Company.
It meets regularly with members of management, the internal auditors and the
independent accountants to discuss the adequacy of the Company's internal
controls, financial statements and the nature, extent and results of the audit
effort. Both the internal auditors and the independent accountants have free and
direct access to the Audit Committee without the presence of management.
James L. Payne Janet F. Clark
Chairman of the Board, Senior Vice President
Chief Executive Officer and Director Chief Financial Officer and Treasurer
(Principal Executive Officer) (Principal Financial and Accounting Officer)
50
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Santa Fe Energy Resources, Inc.
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a)(1) on page 49 present fairly, in all material
respects, the financial position of Santa Fe Energy Resources, Inc. and its
subsidiaries at December 31, 1998 and 1997, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1998, in conformity with generally accepted accounting principles. In
addition, in our opinion, the financial statement schedule listed in the index
appearing under Item 14(a)(2) on page 49 presents fairly, in all material
respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. These financial statements and
financial statement schedule are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements and
financial statement schedule 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.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 1, 1999
51
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales of crude oil and liquids produced ......................................... $ 171.3 $ 355.7 $ 455.4
Sales of natural gas produced ................................................... 119.1 138.1 105.8
Sales of crude oil purchased .................................................... -- 20.5 21.1
Other ........................................................................... 0.6 0.4 1.0
-------- -------- --------
Total revenues ............................................................... 291.0 514.7 583.3
-------- -------- --------
Costs and expenses:
Production and operating ........................................................ 112.5 158.9 188.4
Cost of crude oil purchased ..................................................... -- 22.0 20.8
Exploration, including dry hole costs ........................................... 71.1 49.1 34.5
Depletion, depreciation and amortization ........................................ 136.1 127.8 148.2
Impairment of oil and gas properties ............................................ 87.8 -- 57.4
General and administrative ...................................................... 19.7 28.1 30.1
Taxes other than income ......................................................... 16.3 21.6 26.5
Loss (gain) on disposition of assets ............................................ 1.5 (3.6) (12.1)
-------- -------- --------
Total costs and expenses ..................................................... 445.0 403.9 493.8
-------- -------- --------
Income (loss) from operations ......................................................... (154.0) 110.8 89.5
Interest income ................................................................. 6.2 2.5 1.9
Interest expense ................................................................ (22.0) (23.8) (37.6)
Interest capitalized ............................................................ 7.2 6.7 5.2
Other income (expense) .......................................................... (0.3) (0.6) (1.0)
-------- -------- --------
Income (loss) before income taxes, minority interest
and extraordinary item ............................................................. (162.9) 95.6 58.0
Current income tax (expense) benefit ............................................ 11.4 (8.9) (22.7)
Deferred income tax (expense) benefit ........................................... 52.8 (27.3) 8.4
-------- -------- --------
Income (loss) before minority interest and extraordinary item ......................... (98.7) 59.4 43.7
Minority interest in Monterey Resources, Inc. ................................... -- (4.7) (1.3)
-------- -------- --------
Income (loss) before extraordinary item ............................................... (98.7) 54.7 42.4
Extraordinary item - debt extinguishment costs .................................. -- -- (6.0)
-------- -------- --------
Net income (loss) ..................................................................... (98.7) 54.7 36.4
Preferred dividend requirement .................................................. -- (3.6) (13.5)
Convertible preferred premium ................................................... -- (8.4) (33.7)
-------- -------- --------
Earnings (loss) attributable to common shares ......................................... $ (98.7) $ 42.7 $ (10.8)
======== ======== ========
Earnings (loss) per common share, basic and diluted
Before extraordinary item ....................................................... $ (0.96) $ 0.43 $ (0.05)
Extraordinary item - debt extinguishment costs .................................. -- -- (0.07)
-------- -------- --------
Per common share ................................................................ $ (0.96) $ 0.43 $ (0.12)
======== ======== ========
Weighted average number of shares outstanding ......................................... 102.6 98.6 90.6
======== ======== ========
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
52
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1998 1997
-------- --------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents ........................................................................... $ 12.1 $ 5.6
Accounts receivable, net ............................................................................ 53.2 70.9
Inventories ......................................................................................... 19.0 14.5
Other current assets ................................................................................ 31.7 21.8
-------- --------
Total Current Assets ............................................................................. 116.0 112.8
-------- --------
Properties and equipment, at cost:
Oil and gas (successful efforts method of accounting) ............................................... 1,956.5 1,682.4
Other ............................................................................................... 20.5 16.8
-------- --------
1,977.0 1,699.2
-------- --------
Accumulated depletion, depreciation, amortization and impairment .................................... (1,258.7) (1,049.5)
-------- --------
Net property and equipment ....................................................................... 718.3 649.7
-------- --------
Other Assets:
Deferred income taxes ............................................................................... 13.5 --
Other assets ........................................................................................ 11.2 26.4
-------- --------
Total Other Assets ............................................................................... 24.7 26.4
-------- --------
Total Assets ........................................................................................... $ 859.0 $ 788.9
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable .................................................................................... $ 123.3 $ 106.7
Income taxes payable ................................................................................ 1.2 6.5
Interest payable .................................................................................... 1.9 1.4
Other current liabilities ........................................................................... 12.8 19.4
-------- --------
Total Current Liabilities ........................................................................ 139.2 134.0
-------- --------
Long-term debt ......................................................................................... 330.6 121.7
Deferred revenues ...................................................................................... 3.6 3.7
Other long-term obligations ............................................................................ 37.2 36.3
Deferred income taxes .................................................................................. -- 38.5
Commitments and Contingencies (See Note 14)
Shareholders' Equity
Preferred stock, $0.01 par value, 38.1 shares authorized, none issued ............................... -- --
Common stock, $0.01 par value, 200.0 shares authorized,
102.2 shares and 103.0 shares issued and outstanding, respectively ............................... 1.0 1.0
Paid-in capital ..................................................................................... 728.2 728.2
Accumulated deficit ................................................................................. (372.5) (273.2)
Treasury stock, at cost, 0.8 shares and 0.1 shares, respectively .................................... (6.8) (0.6)
Unamortized restricted stock awards ................................................................. (1.5) (0.7)
-------- --------
Total Shareholders' Equity ............................................................................. 348.4 454.7
-------- --------
Total Liabilities and Shareholders' Equity ............................................................. $ 859.0 $ 788.9
======== ========
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
53
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN MILLIONS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
------- ------- -------
<S> <C> <C> <C>
Operating activities:
Net income (loss) ..................................................................... $ (98.7) $ 54.7 $ 36.4
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depletion, depreciation and amortization ........................................... 136.1 127.8 148.2
Impairment of oil and gas properties ............................................... 87.8 -- 57.4
Deferred income taxes .............................................................. (52.8) 27.3 (11.2)
Loss (gain) on disposition of assets ............................................... 1.5 (3.6) (12.1)
Exploratory dry hole costs ......................................................... 38.4 23.7 11.2
Minority interest in Monterey Resources, Inc. ...................................... -- 4.7 1.3
Other .............................................................................. 3.9 5.7 6.7
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable ......................................... 20.6 11.3 (19.8)
Decrease (increase) in inventories ................................................. (2.6) (2.3) (3.0)
Increase (decrease) in accounts payable ............................................ (16.0) 15.3 19.2
Increase (decrease) in interest payable ............................................ 0.5 1.7 (1.9)
Increase (decrease) in income taxes payable ........................................ (5.3) (15.0) 18.4
Net change in other assets and liabilities ......................................... 1.7 3.3 (22.7)
------- ------- -------
Net cash provided by operating activities ................................................ 115.1 254.6 228.1
------- ------- -------
Investing activities:
Capital expenditures, including exploratory dry hole costs ............................ (191.9) (218.6) (185.7)
Acquisition of producing properties ................................................... (117.6) (197.8) (37.8)
Net proceeds from disposition of assets ............................................... 2.0 40.8 16.7
------- ------- -------
Net cash used in investing activities .................................................... (307.5) (375.6) (206.8)
------- ------- -------
Financing activities:
Issuance of Monterey Energy Resources, Inc. common stock .............................. -- -- 123.6
Issuance of Santa Fe Energy Resources, Inc. common stock .............................. 1.6 2.8 2.4
Purchase of 7% Series convertible preferred stock ..................................... -- -- (94.0)
Principal payments on long-term borrowings ............................................ -- -- (70.0)
Net change in long-term lines of credit ............................................... 208.9 118.2 4.0
Cash dividends paid ................................................................... -- (8.5) (14.8)
Treasury stock purchased .............................................................. (11.6) (0.5) (0.5)
------- ------- -------
Net cash provided by (used in) investing activities ...................................... 198.9 112.0 (49.3)
------- ------- -------
Net increase (decrease) in cash and cash equivalents ..................................... 6.5 (9.0) (28.0)
Cash and cash equivalents at beginning of period ......................................... 5.6 14.6 42.6
------- ------- -------
Cash and cash equivalents at end of period ............................................... $ 12.1 $ 5.6 $ 14.6
======= ======= =======
Supplemental disclosure of cash flow information:
Interest paid ......................................................................... $ 21.1 $ 11.5 $ 38.6
Income taxes paid ..................................................................... $ 5.2 $ 17.8 $ 2.0
</TABLE>
The accompanying notes an are integral part
of these consolidated financial statements.
54
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(IN MILLIONS)
<TABLE>
<CAPTION>
1998 1997 1996
----------------------- -------------------- ------------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
$.732 SERIES A CONVERTIBLE PREFERRED STOCK
Balance, beginning of year ......................... -- $ -- 10.7 $ 91.4 10.7 $ 91.4
Conversion of $.732
Series A preferred stock ........................ -- -- (10.7) (91.4) -- --
-------- -------- -------- -------- -------- --------
Balance, end of year ............................... -- $ -- -- $ -- 10.7 $ 91.4
-------- -------- -------- -------- -------- --------
COMMON STOCK
Balance, beginning of year ......................... 103.0 $ 1.0 91.0 $ 0.9 90.3 $ 0.9
Issuances related to employee stock
compensation and savings plans .................. -- -- 0.7 -- 0.7 --
Conversion of $.732
Series A preferred stock ........................ -- -- 9.1 0.1 -- --
Conversion of convertible
preferred stock, 7% series ...................... -- -- 2.2 -- -- --
-------- -------- -------- -------- -------- --------
Balance, end of year ............................... 103.0 $ 1.0 103.0 $ 1.0 91.0 $ 0.9
-------- -------- -------- -------- -------- --------
PAID-IN CAPITAL
Balance, beginning of year ......................... $ 728.2 $ 601.3 $ 501.1
Issuances related to employee stock
compensation and savings plans .................. -- 7.6 6.7
Issuance of Monterey Resources, Inc.
common stock .................................... -- -- 93.5
Conversion of $.732
Series A preferred stock ........................ -- 91.3 --
Conversion of convertible
preferred stock, 7% Series ...................... -- 28.0 --
-------- -------- --------
Balance, end of year ............................... $ 728.2 $ 728.2 $ 601.3
-------- -------- --------
ACCUMULATED DEFICIT
Balance, beginning of year ......................... $ (273.2) $ (166.5) $ (155.7)
Net income (loss) .................................. (98.7) 54.7 36.4
Issuances related to employee stock
compensation and savings plans .................. (0.6) -- --
Purchase of 7% Series A
convertible preferred stock ..................... -- -- (33.7)
Conversion of convertible
preferred stock, 7% Series ...................... -- (8.4) --
Dividends declared ................................. -- (3.6) (13.5)
Spin Off of Monterey Resources, Inc. ............... -- (149.4) --
-------- -------- --------
Balance, end of year ............................... $ (372.5) $ (273.2) $ (166.5)
-------- -------- --------
TREASURY STOCK
Balance, beginning of year ......................... (0.1) $ (0.6) -- $ (0.3) -- $ --
Issuances related to employee stock
compensation and savings plans .................. 0.6 5.4 -- 0.2 -- 0.2
Purchase of treasury stock ......................... (1.3) (11.6) (0.1) (0.5) -- (0.5)
-------- -------- -------- -------- -------- --------
Balance, end of year ............................... (0.8) $ (6.8) (0.1) $ (0.6) -- $ (0.3)
-------- -------- -------- -------- -------- --------
UNAMORTIZED RESTRICTED STOCK AWARDS
Balance, beginning of year ......................... $ (0.7) $ -- $ --
Issuances related to employee stock
compensation and savings plans .................. (2.6) (2.4) --
Amortization of restricted stock awards ............ 1.8 1.7 --
-------- -------- --------
Balance, end of year ............................... $ (1.5) $ (0.7) $ --
-------- -------- --------
TOTAL SHAREHOLDERS' EQUITY ............................ $ 348.4 $ 454.7 $ 526.8
======== ======== ========
</TABLE>
The accompanying notes are an integral
part of these consolidated financial statements.
55
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements of Santa
Fe Energy Resources, Inc. ("Santa Fe" or the "Company") and its subsidiaries
include the accounts of all wholly owned subsidiaries and Monterey Resources,
Inc. ("Monterey") until Spin Off. Prior to its initial public offering in
November 1996, the Company owned 100% of the outstanding common stock of
Monterey. At December 31, 1996, the Company owned 82.8% of the outstanding
common stock of Monterey, See Note 3 - Spin Off of Monterey Resources, Inc. The
Company's Spin Off of Monterey was completed July 25, 1997.
All significant intercompany accounts and transactions have been eliminated.
Certain amounts in prior periods have been reclassified to conform to current
presentation.
OIL AND GAS OPERATIONS. The Company follows the successful efforts method of
accounting for its oil and gas exploration and production activities. Costs
(both tangible and intangible) of productive wells and development dry holes, as
well as the cost of prospective acreage, are capitalized. The costs of drilling
and equipping exploratory wells which do not find proved reserves are expensed
upon determination that a well does not justify commercial development. Other
exploratory costs, including geological and geophysical costs and delay rentals,
are charged to expense as incurred.
Depletion and depreciation of proved properties are computed on an individual
field basis using the unit-of-production method based upon proved oil and gas
reserves attributable to the field. Certain other oil and gas properties are
depreciated or amortized on a straight-line basis. In the fourth quarter of
1995, the Company adopted Statement of Financial Accounting Standards No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" ("SFAS 121"), which resulted in a non-cash impairment charge
(additional depletion and depreciation) of $87.8 million and $57.4 million in
1998 and 1996, respectively. Impairments of $87.8 million were recorded in 1998
primarily on producing oil and gas properties and unproven leasehold in the Gulf
of Mexico. The impairments of oil and gas properties were primarily the result
of lower oil and gas prices which are not expected to improve in the near term.
The oil and gas impairment tests were based on estimates of future cash flows
using an initial WTI spot oil price and an initial New York Mercantile Exchange
("NYMEX") gas price based on quoted forward market prices which were moderately
escalated. Future cash flows at December 31, 1998 were based on the Company's
estimate of proved reserves and significantly risked probable and possible
reserves. The impairment of unproven leasehold was the result of management's
decision not to develop these leases.
The Company provides for future abandonment and site restoration costs with
respect to certain of its oil and gas properties. The Company estimates that
with respect to these properties such future costs total approximately $22.5
million and such amount is being accrued over the expected life of the
properties. At December 31, 1998 and 1997, accumulated depletion, depreciation,
amortization and impairment included $12.3 million and $10.0 million,
respectively, of such costs.
The value of undeveloped acreage is aggregated and the portion of such costs
estimated to be nonproductive, based on historical experience, is amortized to
expense over the average holding period. Additional amortization may be
recognized based upon periodic assessment of prospect evaluation results. The
cost of properties determined to be productive is transferred to proved
properties; the cost of properties determined to be nonproductive is charged to
accumulated amortization.
56
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Maintenance and repairs are expensed as incurred; major renewals and
improvements are capitalized. Gains and losses arising from sales of assets are
included in income currently.
REVENUE RECOGNITION. Revenues from the sale of crude oil and liquids produced
are generally recognized upon the passage of title, net of royalties and net
profits interests.
Revenues from natural gas production are generally recorded using the
entitlement method, net of royalties and net profits interests. Sales proceeds
in excess of the Company's entitlement are included in deferred revenues and the
Company's share of sales taken by others is included in other assets. At
December 31, 1998, the Company's deferred revenues for sales proceeds received
in excess of the Company's entitlement were $3.2 million with respect to 2.5
MMcf and the asset related to the Company's share of sales taken by others was
$1.2 million with respect to 0.9 MMcf.
The Company periodically hedges a portion of its oil and gas sales. See Note
14 - Commitments and Contingencies - Oil and Gas Hedging.
Revenues from sales of crude oil purchased relate to the sales of low
viscosity crude oil purchased and blended with certain of Monterey's high
viscosity, low gravity crude oil production, either to facilitate pipeline
transportation or to realize higher margins. The cost to purchase such crude oil
is reflected as an expense.
EARNING PER SHARE. Earnings per share are based on computation requirements
as set forth in Statement of Financial Accounting Standards No. 128, "Earnings
per Share" ("SFAS 128"). See Note 4 - Earnings Per Share.
ACCOUNTS RECEIVABLE. Accounts Receivable relates primarily to sales of oil
and gas and amounts due from joint interest partners for expenditures made by
the Company on behalf of such partners. The Company reviews the financial
condition of potential purchasers and partners prior to signing sales or joint
interest agreements. At December 31, 1998 and 1997 the Company's allowance for
doubtful accounts receivable, which is reflected in the consolidated balance
sheet as a reduction in accounts receivable, totaled $1.6 million and $2.7
million, respectively. Accounts receivable totalling $1.1 million and $0.3
million were written off as uncollectible in 1998 and 1997, respectively.
INVENTORIES. Inventories are generally valued at the lower of cost (average
price or first-in, first-out) or market. Crude oil inventories at December 31,
1998 and 1997 were $5.7 million and $3.7 million, respectively, and materials
and supplies inventories at such dates were $13.3 million and $10.8 million,
respectively.
ENVIRONMENTAL EXPENDITURES. Environmental liabilities are recognized when the
expenditures are considered probable and can be reasonably estimated.
Measurement of liabilities is based on currently enacted laws and regulations,
existing technology and undiscounted site-specific costs. Generally, such
recognition coincides with the Company's commitment to a formal plan of action.
INCOME TAXES. The Company follows the asset and liability approach to
accounting for income taxes. Deferred tax assets and liabilities are determined
using the tax rate for the period in which those amounts are expected to be
received or paid, based on a scheduling of temporary differences between the tax
bases of assets and liabilities and their reported amounts. Under this method of
accounting for income taxes, any future changes in income tax rates will affect
deferred income tax balances and financial results.
57
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FUNCTIONAL CURRENCY. The functional currency of the Company and its
subsidiaries is the U.S. dollar.
USE OF ESTIMATES. The preparation of the Company's financial statements in
conformity with generally accepted accounting principles requires the Company to
make certain estimates and assumptions that affect the reported amounts of
assets and liabilities and the disclosure of contingent assets and liabilities
and the periods in which certain items of revenue and expense are included.
Actual results may differ from such estimates.
NEW ACCOUNTING STANDARDS. Effective January 1, 1998, the Company adopted
Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive
Income" ("SFAS 130"). SFAS 130 establishes new rules for the reporting and
display of comprehensive income and its components. Comprehensive income is net
income, plus certain other items that are recorded directly to shareholders'
equity. Currently, the Company has no comprehensive income other than net
income.
Effective January 1, 1998, the Company adopted Statement of Financial
Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and
Related Information" ("SFAS 131"). SFAS 131 supersedes Statement of Financial
Accounting Standards No. 14, "Financial Reporting for Segments of a Business
Enterprise", replacing the "industry segment" approach with the "management"
approach. The management approach designates the internal organization that is
used by management for making operating decisions and assessing performance as
the source of the Company's reportable segments. SFAS 131 also requires
disclosures about products and services, geographic areas and major customers.
The adoption of SFAS 131 did not affect results of operations or financial
position but did affect the disclosure of segment information See Note 9 -
Segment Information. Interim period disclosures will commence in the first
quarter ending March 31, 1999.
Effective January 1, 1998, the Company adopted Statement of Financial
Accounting Standards No. 132, "Employers' Disclosures about Pension and Other
Postretirement Benefits" ("SFAS 132"). SFAS 132 revises employers' disclosures
about pension and other postretirement benefit plans. It does not change the
asset or obligation measurement or the net periodic cost recognition of those
plans. It standardizes the disclosure requirements for pensions and other
postretirement benefits to the extent practicable, requires additional
information on changes in the benefit obligations and fair values of plan assets
that will facilitate financial analysis, and eliminates certain disclosures that
are no longer useful. The adoption of the Statement had no effect on the
Company's reported consolidated net income See Note 13 - "Pension and Other
Postretirement Benefits".
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"), which is effective for all fiscal quarters
of all fiscal years beginning after June 15, 1999. The Company intends to
implement the provisions of the Statement beginning with the first quarter of
2000. SFAS 133 will require the Company to recognize all derivatives, as defined
in the Statement, on the balance sheet at fair value. Derivatives that are not
hedges must be adjusted to fair value through income. If the derivative is a
hedge, depending on the nature of the hedge, changes in the fair value of
derivatives either will be offset against the change in fair value of the hedged
assets, liabilities, or firm commitments through earnings or will be recognized
in other comprehensive income until the hedged item is recognized in earnings.
The ineffective portion of a derivative's change in fair value will be
immediately recognized in earnings. The Company has not yet determined the
impact that the adoption of SFAS 133 will have on its earnings and statement of
financial position.
58
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. PROPOSED MERGER
On January 13, 1999, Santa Fe entered into a Merger Agreement with Snyder Oil
Corporation ("Snyder") which provides that Snyder will be merged with and into
Santa Fe. In connection with the merger, the name of Santa Fe will be changed to
Santa Fe Snyder Corporation ("Santa Fe Snyder") and Santa Fe's authorized common
stock will be increased to 300,000,000. Under the agreement, Snyder shareholders
will receive 2.05 shares of Santa Fe common stock for each share of Snyder
common stock. The Company will account for this transaction using the purchase
method of accounting as of the effective date, which is expected in the second
quarter of 1999. The merger is conditioned, among other things, upon securing
regulatory and shareholder approval.
NOTE 3. SPIN OFF OF MONTEREY RESOURCES, INC.
In 1996 the Company formed Monterey Resources Inc. ("Monterey") to assume the
operations of the Company's Western Division (the "Western Division") which
conducted the Company's oil and gas operations in the State of California. In
November 1996, prior to the initial public offering (the "IPO") discussed below,
pursuant to a contribution and conveyance agreement (the "Contribution
Agreement"), among other things: (i) the Company contributed to Monterey
substantially all of the assets and properties of the Western Division, subject
to the retention by the Company of a production payment, as defined below, and
certain other assets; (ii) the Company retained a $30.0 million production
payment (the "Production Payment") with respect to certain properties in the
Midway-Sunset field; (iii) Monterey assumed all obligations and liabilities of
the Company associated with or allocated to the assets and properties of the
Western Division, including $245.0 million of indebtedness in respect of Santa
Fe's 10.23% Series E Notes due 1997, 10.27% Series F Notes due 1998 and 10.61%
Series G Notes due 2005 (the "Series E Notes", "Series F Notes" and "Series G
Notes", respectively) and (iv) Monterey agreed to purchase from the Company an
$8.3 million promissory note receivable related to the sale to a third party of
certain surface acreage located in Orange County, California. Also prior to the
IPO, Monterey and the Company entered into a $75.0 million revolving credit
facility with a group of banks (the "Monterey Credit Facility") and borrowed
$16.0 million which was retained by the Company.
In November 1996 Monterey sold 9,335,000 shares of its common stock for total
consideration of $123.6 million (after deducting underwriting discounts of $9.1
million and other related costs of $2.6 million). The proceeds from the IPO were
used in part to (i) repay the Series E Notes and Series F Notes ($70.0 million)
and pay a prepayment penalty thereon of $2.5 million; (ii) retire the Production
Payment ($30.0 million); (iii) repay the $16.0 million outstanding under the
Monterey Credit Facility; and (iv) pay a $2.0 million fee with respect to a
supplement to the indenture relating to the Company's 11% Senior Subordinated
Debentures due 2004. Subsequent to the IPO, Monterey issued $175.0 million in
aggregate principal amount of 10.61% Senior Notes due 2005 (the "Monterey Senior
Notes") to holders of the Series G Notes in exchange for the cancellation of
such notes and paid a $1.3 million consent fee in connection therewith.
The costs and expenses related to the retirement of the Company's outstanding
debt, as discussed above, and approximately $3.4 million of deferred debt issue
costs and related transaction costs were reflected in the Company's 1996
Statement of Operations as an extraordinary item, net of $3.2 million in income
taxes.
Prior to the Spin Off, the Company owned 82.8% of Monterey's outstanding
common stock. On July 25, 1997 the Company distributed pro rata to its common
shareholders all of the shares of Monterey's common stock that it owned by means
of a tax-free distribution (the "Spin Off"). Pursuant to the terms of a letter
agreement dated June 13, 1996, upon consummation of the Spin Off, fees
aggregating $3.3 million were paid
59
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
by Monterey to Chase Securities Inc. and Petrie Parkman & Co., Inc. In addition,
a fee of $0.4 million was paid to GKH Partners, L.P., of which $0.2 million was
paid by the Company and $0.2 million was paid by Monterey. One of the Company's
former directors was associated with Chase Securities and another current
director is associated with GKH Partners.
Monterey agreed to indemnify the Company if at any time during the one-year
period subsequent to consummation of the Spin Off (or if certain tax legislation
is enacted and is applicable, such longer period as is required for the Spin Off
to be tax free to the Company) Monterey takes certain actions, the effects of
which result in the Spin Off being taxable to the Company. As of March 1, 1999,
the Company does not believe that any such actions occurred during the one-year
period that would have had such effect on the Spin Off.
Prior to the Spin Off, Monterey purchased all the common stock of McFarland
Energy, Inc. ("McFarland Energy") for $106.2 million in cash and $2.3 million of
assumed debt.
Pursuant to the Contribution Agreement, Monterey agreed to indemnify and hold
harmless the Company from and against any costs incurred in the future relating
to environmental liabilities of the Western Division assets (other than those
retained by the Company), and any costs or liabilities that may arise in the
future that are attributable to laws, rules or regulations in respect to any
property or interest therein located in California and formerly owned or
operated by the Western Division or its predecessors.
The following table sets forth certain financial information for the Company,
on an unaudited pro forma basis assuming that the Spin Off occurred prior to the
beginning of the periods presented (1):
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------
1997 1996
------------ ----------------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues........................... $ 333.5 $ 290.4
Income (loss) from operations...... 60.3 (15.1)
Net income (loss).................. 35.0 (5.5)
Earnings (loss) to common shares... 23.0 (52.7)
Earnings (loss) per common share,
basic and diluted................ $ 0.23 $ (0.58)
- -----------
(1) Costs and expenses related to the Spin Off of Monterey have been excluded
from the year ended December 31, 1997 pro forma presentations as follows:
(i) $2.0 million in pension curtailments and (ii) $0.6 million in
compensation expenses; (iii) $1.1 million in Spin Off related costs and
expenses, and for the year ended December 31, 1996 as follows: (iv) $2.0
million in costs related to the Monterey IPO and (v) $1.5 million in debt
extinguishment costs, net of $1.0 million tax expense, related to the
Monterey IPO.
The Company recorded the following reductions on the balance sheet in 1997 as
a result of the Spin Off of Monterey (in millions):
Current assets.................................... $ 45.7
Property and equipment, net....................... 537.5
Other assets...................................... 1.6
Current liabilities............................... 49.0
Long-term debt.................................... 277.3
Other long-term obligations....................... 3.8
Deferred income taxes............................. 74.2
Minority interest in Monterey Resources, Inc...... 31.1
Shareholders' equity.............................. 149.4
60
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4. EARNINGS PER SHARE
The following table sets forth the components of the Company's basic and
diluted earnings per share calculations:
<TABLE>
<CAPTION>
EARNINGS (LOSS) WEIGHTED
ATTRIBUTABLE AVERAGE OF
TO COMMON COMMON SHARES PER SHARE
SHARES OUTSTANDING AMOUNT
--------------- --------------- ---------
<S> <C> <C> <C>
Year Ended December 31, 1998
Basic ........................................................................ $ (98.7) 102.6
Effect of dilutive stock options ............................................. -- 1.8
Effect of dilutive performance awards ........................................ -- 0.4
--------------- ---------------
Basic and diluted ............................................................ $ (98.7) 104.8 $ (0.96)
=============== =============== =========
Year Ended December 31, 1997
Basic ........................................................................ $ 42.7 98.6
Effect of dilutive stock options ............................................. -- 1.8
Effect of dilutive performance awards ........................................ -- 0.2
--------------- ---------------
Basic and diluted ............................................................ $ 42.7 100.6 $ 0.43
=============== =============== =========
Year Ended December 31, 1996
Basic before extraordinary item .............................................. $ (4.8) 90.6
Effect of dilutive stock options ............................................. -- 0.7
--------------- ---------------
Basic and diluted before extraordinary item .................................. $ (4.8) 91.3 $ (0.05)
=============== =============== =========
Basic and diluted - extraordinary item ....................................... $ (6.0) 91.3 $ (0.07)
=============== =============== =========
Basic and diluted after extraordinary item ................................... $ (10.8) 91.3 $ (0.12)
=============== =============== =========
</TABLE>
The Company had 5.2 million, 1.4 million and 1.9 million stock options
outstanding in 1998, 1997 and 1996, respectively, which were not included in the
computation of diluted earnings per share because the exercise price of these
options was greater than the average market price of the common shares. The
Company also had convertible preferred stock in 1997 and 1996 which was
antidilutive. Given that the Company reported a loss in 1998 and 1996, the
potential effects of dilutive stock options and performance awards were not
included in the computation of diluted earnings per share.
NOTE 5. SANTA FE ENERGY TRUST
The Santa Fe Energy Trust (the "Trust") was formed in 1992 to hold 6,300,000
Depository Units ("Depository Units"), each consisting of beneficial ownership
of one unit of undivided interest in the Trust and a $20 face amount beneficial
ownership interest in a $1,000 face amount zero coupon United States Treasury
obligation maturing on or about February 15, 2008. The Trust will be liquidated
on February 15, 2008. The assets of the Trust consist of certain oil and gas
properties conveyed by the Company.
For any calendar quarter ending on or prior to December 31, 2002, the Trust
will receive additional support payments to the extent that it needs such
payments to distribute $0.40 per Depository Unit per quarter. The source of such
support payments, if needed, will be limited to the Company's remaining royalty
interest in certain of the properties conveyed to the Trust. If such support
payments are made, certain proceeds otherwise payable to the Trust in subsequent
quarters may be reduced to recoup the amount of such support payments. The
aggregate amount of the additional royalty payments (net of any amounts
recouped) will be limited to $20.0 million on a revolving basis. Through the end
of 1998, the Trust had received support payments totalling $2,168,000. During
1996 and the first six months of 1997 Santa Fe recouped $2,074,000 of such
payments. In 1999, the Company
61
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
has made an additional support payment of $779,000. Depending on various
factors, such as sales volumes and prices and the level of operating costs and
capital expenditures incurred, proceeds payable to the Trust with respect to
operations in subsequent quarters may not be sufficient to make distributions of
$0.40 per quarter. In such instances the Company would be required to make
support payments. Due to low commodity prices, almost all of the production
proceeds from Santa Fe's royalty interest in the Wasson ODC unit for the quarter
ended December 31, 1998 were used to make the support payment. At December 31,
1998 and 1997, accounts payable included $2.6 million and $3.5 million,
respectively, due to the Trust.
NOTE 6. CASH FLOWS
The Company considers all highly liquid investments with a maturity of three
months or less when purchased to be cash equivalents.
The following balances represent noncash adjustments to the Company's
Consolidated Balance Sheet as of December 31, 1998, related to the acquisition
of an additional interest in the Tuban Production Sharing Contract on the island
of Java in Indonesia from Total S.A.:
TOTAL S.A.
ACQUISITION
-------------
(in millions)
Accounts receivable............................. $ 2.9
Inventories..................................... 1.9
Other assets.................................... 3.4
Accounts payable................................ 3.4
Other long-term obligations..................... 0.1
Deferred income taxes........................... 0.9
The following balances represent noncash adjustments to the Company's
Consolidated Balance Sheet as of December 31, 1997, related to Monterey's
acquisition of McFarland Energy, the Company's Spin Off of Monterey and the
Company's acquisition of interests in the Tupungato field in Argentina:
<TABLE>
<CAPTION>
MCFARLAND MONTEREY TUPUNGATO
ACQUISITION SPIN OFF ACQUISITION TOTAL
----------- -------- ----------- --------
(In millions)
<S> <C> <C> <C> <C>
Accounts receivable ................................... $ 7.0 $ (38.4) $ 1.3 $ (30.1)
Inventories ........................................... 0.3 (2.4) 0.7 (1.4)
Accounts payable ...................................... 0.5 (27.6) 0.6 (26.5)
Income taxes payable .................................. -- 0.1 -- 0.1
Interest payable ...................................... -- (6.3) -- (6.3)
Other assets and liabilities .......................... (0.3) 10.1 1.2 11.0
Long-term debt ........................................ 2.3 (277.3) -- (275.0)
</TABLE>
In December 1996, the Company sold the surface rights to approximately 116
surface acres in Orange County, California to an unaffiliated party for total
consideration of $24.2 million and recognized a $12.3 million gain. The Company
received $15.9 million in cash and an $8.3 million note, which was purchased by
Monterey for cash. In 1997 Monterey received cash payment for the note.
62
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7. INCOME TAXES
Federal income tax returns through 1991 have been audited and are closed,
while subsequent years are unaudited. Certain state franchise tax returns for
years 1984 through 1990 are currently under audit. In November 1996, the Company
and Monterey executed a tax sharing agreement, which transferred to Monterey all
obligations attributable to these franchise tax liabilities for these years.
Total pretax income (loss) for the years ended December 31, 1998, 1997 and
1996 was taxed under the following jurisdictions (in millions):
1998 1997 1996
------ ------ ------
Domestic ............................ $(126.1) $ 88.0 $ 46.4
Foreign ............................. (36.8) 7.6 2.4
------ ------ ------
$(162.9) $ 95.6 $ 48.8
====== ====== ======
The Company's total income tax expense (benefit) for the years ended December
31, 1998, 1997 and 1996 consisted of the following items (in millions):
1998 1997 1996
------- ------- -------
Current
U.S. federal ............. $ (11.2) $ 2.3 $ 13.6
State .................... (2.1) 1.4 5.1
Foreign .................. 1.9 5.2 3.6
------- ------- -------
(11.4) 8.9 22.3(a)
------- ------- -------
Deferred
U.S. federal ............. $ (41.6) $ 26.7 $ 4.7
State .................... -- 0.7 1.3
Foreign .................. (11.2) (0.1) (17.2)(b)
------- ------- -------
(52.8) 27.3 (11.2)
------- ------- -------
$ (64.2) $ 36.2 $ 11.1(a)
======= ======= =======
(a) Includes $3.2 million income tax benefit which is reflected in extraordinary
item - debt extinguishment costs. See Note 3 - "Spin off of Monterey
Resources, Inc.".
(b) Includes benefit of $8.3 million related to certain prior period foreign
expenditures.
The Company's deferred income tax (assets) liabilities at December 31, 1998
and 1997 are composed of the following differences between financial and tax
reporting (in millions):
1998 1997
------- -------
Capitalized costs and write-offs ................. $ 47.2 $ 81.0
------- -------
Gross deferred tax liability ..................... 47.2 81.0
------- -------
Accruals not currently deductible for tax purposes (3.0) (20.0)
Alternative minimum tax carryforwards ............ (16.9) (15.2)
Net operating loss carryforwards ................. (26.6) --
Foreign deferred asset ........................... (14.1) (6.2)
Other ............................................ (0.1) (1.1)
------- -------
Gross deferred tax assets ........................ (60.7) (42.5)
------- -------
Deferred tax (asset) liability ................... $ (13.5) $ 38.5
======= =======
63
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the Company's total income tax expense computed by
applying the statutory U.S. federal income tax rate to the Company's total
income (loss) before income taxes for the years ended December 31, 1998, 1997
and 1996 is presented in the following table (in millions):
<TABLE>
<CAPTION>
1998 1997 1996
------- ------- -------
<S> <C> <C> <C>
U.S. federal income taxes at statutory rate .............. $ (57.0) $ 33.4 $ 17.1
Increase (reduction) resulting from:
State income taxes, net of federal effect ............. (1.4) 1.4 4.3
Foreign income taxes in excess of (less than) U.S. rate 2.8 2.4 (14.4)
U.S. tax on foreign reinvested earnings ............... 0.6 0.5 2.8
Prior period tax adjustments .......................... (9.3) -- 1.7
Other ................................................. 0.1 (1.5) (0.4)
------- ------- -------
$ (64.2) $ 36.2 $ 11.1
======= ======= =======
</TABLE>
NOTE 8. FINANCING AND DEBT
Long-term debt at December 31, 1998 and 1997 consisted of the following
balances (in millions):
DECEMBER 31,
-----------------------------------------
1998 1997
------------------- -------------------
CURRENT LONG-TERM CURRENT LONG-TERM
------- --------- ------- ---------
Santa Fe
11% Senior Subordinated Debentures $ -- $ 99.6 $ -- $ 99.5
Lines of credit borrowings ....... -- 231.0 -- 22.2
------- --------- ------- ---------
$ -- $ 330.6 $ -- $ 121.7
======= ========= ======= =========
Aggregate total maturities of long-term debt during the next five years are
as follows: 1999 - none; 2000 - none; 2001 - none; 2002 - none and 2003 - $231.0
million.
The Company has a revolving credit agreement (the "Credit Agreement") which
matures May 15, 2003. Subject to the covenants described below, the Credit
Agreement permits the Company to obtain revolving credit loans and issue letters
of credit having a maximum aggregate amount of $335 million of which $30 million
is available for letters of credit. Borrowings under the agreement are unsecured
and interest rates are tied to the agent bank's prime rate or eurodollar
offering rate, at the Company's option. At December 31, 1998, the Company had
$225.0 million in borrowings outstanding under the Credit Agreement, which were
classified as long-term debt on the balance sheet since the company has the
ability and intends to refinance such amount on a long-term basis. The Company
had one letter of credit outstanding under the Credit Agreement at December 31,
1998 for $22.1 million and one letter of credit outside the Credit Agreement for
$1.8 million. The actual interest rates varied from 6.0% to 6.4% for the year
ended December 31, 1998.
In a public offering in May 1994, the Company issued $100.0 million of 11%
Senior Subordinated Debentures due 2004 (the "Debentures"). The Debentures were
issued for 99.266% of face value, and the Company received proceeds of $96.1
million after deducting related costs and expenses of $3.2 million. The
Debentures, which mature May 15, 2004, are not redeemable prior to May 15, 1999
and may be redeemed after such date at the option of the Company at prices set
forth in the indenture for the Debentures. Under certain circumstances, the
Company may be required to redeem the Debentures for 101% of the principal
amount. The Debentures are general unsecured subordinated obligations of the
Company.
64
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Credit Agreement and the Indenture for the Debentures include covenants
that restrict the Company's ability to take certain actions, including the
ability to incur additional indebtedness and to pay dividends or repurchase
capital stock. Under the most restrictive of these covenants, at December 31,
1998 the Company could incur approximately $168 million of additional
indebtedness of which $70 million could be borrowings under the Credit
Agreement. As of December 31, 1998, these covenants do not allow the Company to
pay dividends or repurchase capital stock.
In addition to the Credit Agreement, the Company also has one short-term
uncommitted line of credit totalling $20.0 million which is used to meet
short-term cash needs. At December 31, 1998, the Company had $6.0 million in
borrowings under these facilities, which were classified as long-term debt on
the balance sheet since the company has the ability and intends to refinance
such amount on a long-term basis. Actual interest rates varied from 5.6% to 7.5%
for the year ended December 31, 1998.
NOTE 9. SEGMENT INFORMATION
The principal business of the Company consists of the exploration,
development and acquisition of oil and gas properties and the production and
sale of crude oil and liquids and natural gas. The Company has determined that
its reportable segments are those that are based on the Company's method of
internal reporting, which disaggregates its business by geographic area. The
Company's reportable segments are the United States, Argentina, Indonesia, and
Other International. Other International represents various exploration and
development projects in China, Gabon, Ecuador, Cote d'Ivoire and other
international arenas. The prior years' segment information has been restated to
present the Company's four reportable segments.
The accounting policies of the segments are the same as those described in
the "Summary of Significant Accounting Policies." The Company evaluates the
performance of its segments and allocates resources based
principally on operating income or loss.
The table below presents information about the reported segments for the
years ending December 31, 1998, 1997 and 1996. Other reconciling items include
other corporate income and expenses, hedging activities and overhead costs not
allocated to specific geographic areas. Asset information by reportable segment
is not presented because such information is not a factor used by management to
evaluate the performance of the segments.
<TABLE>
<CAPTION>
EARNINGS (LOSS)
BEFORE INCOME DEPLETION,
TAXES, MINORITY DEPRECIATION
INTEREST AND AMORTIZATION (LOSS) GAIN
TOTAL OPERATING EXTRAORDINARY AND ON SALE OF
REVENUES INCOME (LOSS) ITEM IMPAIRMENT ASSETS
-------- ------------- --------------- ------------ ----------
<S> <C> <C> <C> <C> <C>
1998:
United States ......... $ 194.5 $ (73.0) $ (73.0) $ 179.4 $ (1.5)
Argentina ............. 33.6 1.0 1.0 13.1 --
Indonesia ............. 53.5 5.5 5.5 19.7 --
Other International ... 7.7 (57.2) (57.2) 3.5 --
Other reconciling items 1.7 (30.3) (39.2) 8.2 --
-------- ------------- --------------- ------------ ----------
Total Consolidated $ 291.0 $ (154.0) $ (162.9) $ 223.9 $ (1.5)
======== ============= =============== ============ ==========
</TABLE>
TABLE CONTINUED ON NEXT PAGE
65
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
EARNINGS (LOSS)
BEFORE INCOME DEPLETION,
TAXES, MINORITY DEPRECIATION
INTEREST AND AMORTIZATION (LOSS) GAIN
TOTAL OPERATING EXTRAORDINARY AND ON SALE OF
REVENUES INCOME (LOSS) ITEM IMPAIRMENT ASSETS
-------- ------------- --------------- ------------ ----------
<S> <C> <C> <C> <C> <C>
1997:
United States ......... $ 444.8 $ 133.8 $ 133.8 $ 106.1 $ 3.6
Argentina ............. 40.7 15.3 15.3 8.9 --
Indonesia ............. 27.8 (0.7) (0.7) 6.9 --
Other International ... (0.6) (11.7) (11.7) 0.8 --
Other reconciling items 2.0 (25.9) (41.1) 5.1 --
-------- ------------- --------------- ------------ ----------
Total Consolidated $ 514.7 $ 110.8 $ 95.6 $ 127.8 $ 3.6
======== ============= =============== ============ ==========
1996:
United States ......... $ 552.1 $ 177.3 $ 177.3 $ 156.1 $ 0.1
Argentina ............. 35.8 16.4 16.4 7.9 --
Indonesia ............. 29.6 (12.8) (12.8) 24.6 --
Other International ... -- (19.9) (19.9) 5.1 (0.3)
Other reconciling items (34.2) (71.5) (103.0) 11.9 12.3
-------- ------------- --------------- ------------ ----------
Total Consolidated $ 583.3 $ 89.5 $ 58.0 $ 205.6 $ 12.1
======== ============= =============== ============ ==========
</TABLE>
For the year ending December 31, 1998, revenues from two purchasers
represented approximately $38.9 million and $34.3 million of the Company's
consolidated revenues. In 1997, one purchaser accounted for approximately $55.2
million of consolidated revenues and in 1996, three purchasers accounted for
approximately $66.7 million, $105.7 million and $64.8 million of consolidated
revenues. All of these amounts represent sales in the United States segment.
The following table represents enterprise-wide information for long-lived
assets. These assets include net property and equipment and other long-term
assets:
LONG-LIVED ASSETS
------------------------------
1998 1997 1996
------ ------ ------
United States .............................. $427.8 $461.7 $819.4
Argentina .................................. 127.9 114.7 69.0
Indonesia .................................. 141.1 86.8 61.6
Other International ........................ 46.2 12.9 1.6
------ ------ ------
Total Consolidated ...................... $743.0 $676.1 $951.6
====== ====== ======
NOTE 10. CONVERTIBLE PREFERRED STOCK, 7% SERIES
In November 1996, the Company purchased 3.8 million of the outstanding shares
of its Convertible Preferred Stock, Series 7% (the "7% Preferred") for $24.50
per share. The excess of the cost of the acquired shares ($94.0 million,
including related costs of $1.7 million) over the book value of such shares,
$33.7 million, is reflected in the Statement of Operations as a Convertible
preferred premium. In the second quarter of 1997, the Company converted the
remaining 1.2 million outstanding shares of 7% Preferred for 2.3 million shares
of common stock. The conversion of the 7% Preferred resulted in a non-cash
reduction in earnings to common shares which is reflected as an $8.4 million
Convertible preferred premium in the 1997 Statement of Operations.
66
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. SHAREHOLDERS' EQUITY
$.732 SERIES A CONVERTIBLE PREFERRED STOCK. In the second quarter of 1997 the
Company converted all 10.7 million outstanding shares of its $.732 Series A
Convertible Preferred Stock (the "DECS") into 9.1 million shares of common
stock. There was no charge to earnings as a result of the conversion of the
DECS.
PREFERRED STOCK. The Board of Directors of the Company is empowered, without
approval of the shareholders, to cause shares of preferred stock to be issued in
one or more series, and to determine the number of shares in each series and the
rights, preferences and limitations of each series. Among the specific matters
which may be determined by the Board of Directors are the annual rate of
dividends; the redemption price, if any; the terms of a sinking or purchase
fund, if any; the amount payable in the event of any voluntary liquidation,
dissolution or winding up of the affairs of the Company; conversion rights, if
any; and voting powers, if any.
TREASURY STOCK. The Company's Board of Directors has authorized the Company
to buy back up to $50 million of its common stock to meet the requirements of
outstanding stock options and to satisfy the stock requirements of employee
benefit plans. In 1998 and 1997, the Company purchased 1,276,697 shares and
53,500 shares, for approximately $11.6 million and $0.5 million, respectively.
Currently, the Company is not buying back any of its common stock.
SHAREHOLDER RIGHTS PLAN. The Company has adopted a shareholder rights plan
(the "Rights Plan") whereby preferred stock purchase rights (the "Rights") were
distributed to holders of the Company's common stock. The Rights will expire on
July 25, 1999. The Rights will be exercisable only if a person acquires
beneficial ownership of 15 percent or more of the Company's common stock (an
"Acquiring Person"), or commences a tender offer which would result in ownership
of 15 percent or more of such stock. Under the Rights Plan, one Right to
purchase one one-hundredth of a share of a new series of junior preferred stock
of the Company at an exercise price of $42.00 per one one-hundredth of a share
(subject to adjustment) were issued for each outstanding share of the Company's
common stock held at the close of business on March 3, 1997.
If any person becomes an Acquiring Person, each Right will entitle the holder
to purchase, at the Right's then current exercise price, shares of the Company's
common stock having a value of twice the Right's exercise price. In addition,
if, after a person becomes an Acquiring Person, the Company is involved in a
merger or other business combination transaction with another person in which
the Company is not the surviving corporation, or under certain other
circumstances, each Right will entitle its holder to purchase, at the Right's
then current exercise price, shares of common stock of the other person having a
value of twice the Right's exercise price.
The Company will generally be entitled to redeem the Rights in whole, but not
in part, at $0.01 per Right payable in cash or common stock, subject to
adjustment, at any time until 10 business days (subject to extension) after the
first public announcement that an Acquiring Person has become such.
The terms of the Rights may be amended by the Company without the approval of
the holders of the Rights at any time the Rights are redeemable. At any time the
Rights are no longer redeemable the terms may be amended only to (i) cure any
ambiguity; (ii) correct or supplement any provision which may be defective or
inconsistent with other provisions; (iii) shorten or lengthen any time period;
or (iv) change or supplement the provisions in any manner which the Company
deems necessary or desirable, so long as such change does not adversely affect
the interests of the holders of the Rights.
67
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. STOCK OPTION PLANS
Under the terms of the Santa Fe Energy Resources 1990 Incentive Stock
Compensation Plan (the "1990 Plan"), the Company may grant options and awards
with respect to no more than 10,320,527 shares of common stock to officers,
directors and key employees. Under the terms of the Santa Fe Energy Resources
1995 Incentive Stock Compensation Plan (the "1995 Plan"), the Company may grant
options and awards with respect to not more than 1,000,000 shares of common
stock per year to employees other than executive officers and directors. Awards
made under the terms of the 1990 Plan and the 1995 Plan (collectively the
"Plans") may be made in the form of Restricted Stock, Bonus Stock, Phantom Units
and Stock Appreciation Rights, as such terms are defined in the Plans.
Options under the terms of the Plans are granted at the average market price
on the date of grant and have a ten-year term with vesting periods ranging from
six months to three years. The following table summarizes the activity with
respect to options outstanding under the Plans during 1998, 1997 and 1996:
<TABLE>
<CAPTION>
1998 1997 1996
---------------------- ---------------------- ----------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
SHARES EXERCISE SHARES EXERCISE SHARES EXERCISE
(THOUSANDS) PRICE (THOUSANDS) ($/SHARE) (THOUSANDS) PRICE
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year . 8,068.5 $ 7.69 5,392.0 $ 12.07 4,441.7 $ 11.85
Grants ........................... 1,783.6 9.68 873.1 9.73 1,240.5 12.07
Revaluation due to Spin Off ...... -- -- 3,119.0 7.27 -- --
Cancellations .................... (222.0) 11.29 (919.7) 11.31 (9.9) 10.73
Exercises ........................ (243.9) 6.84 (395.9) 7.23 (280.3) 8.73
--------- --------- ---------
Outstanding at end of year ....... 9,386.2 8.01 8,068.5 7.69 5,392.0 12.07
========= ========= ========= =========
Exercisable at end of year ....... 6,560.9 6,037.3 4,265.6
========= ========= =========
Weighted average fair value of
Options granted during the year $ 4.88 $ 5.73 $ 6.67
</TABLE>
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option-pricing model with the following assumptions: (i)
expected dividend yield - 0.0%; (ii) expected stock price volatility - 25 to
26%; (iii) risk-free interest rate - 4 to 6%; and (iv) expected life of options
- - 10 years.
The following table summarizes certain information with respect to options
outstanding under the Plans at December 31, 1998:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
- ------------------------------------------------------------------------ -----------------------------
WEIGHTED AVG.
REMAINING WEIGHTED AVG. WEIGHTED AVG.
SHARES CONTRACTUAL EXERCISE SHARES EXERCISE
RANGE OF EXERCISE PRICES (THOUSANDS) LIFE PRICE (THOUSANDS) PRICE
- ------------------------ ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
$4.00 to $ 7.00 ........ 4,206.7 6 years $ 5.77 3,864.7 $ 5.67
$8.00 to $12.00 ........ 4,609.8 7 years $ 9.33 2,126.5 $ 8.77
$13.00 to $15.00 ....... 569.7 2 years $ 13.81 569.7 $ 13.81
------------- -------------
9,386.2 6,560.9
============= =============
</TABLE>
In December 1995, the Company granted 0.1 million Phantom Units to certain
executive officers which were to be earned over a three-year period commencing
January 1, 1996. The Phantom Units vested as a result of the Monterey IPO. The
Company recognized $1.6 million in expense in 1996 with respect to such Phantom
Units.
68
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During 1998, 1997 and 1996 the Company granted 0.1 million, 0.2 million and
0.1 million, respectively, shares of restricted stock to certain executive
officers and other employees. At December 31, 1998, 0.5 million shares were
available for options or awards under the 1990 Plan and 0.1 million shares were
available under the 1995 Plan.
In 1998 the Company issued 0.2 million shares of restricted stock under its
incentive compensation plan. These restricted shares vest one-third per year
over a three year period. The value of these shares at the grant date is being
amortized over the vesting period of the shares. The unamortized portion of
these awards at December 31, 1998 and 1997, was $1.5 million and $.7 million,
respectively.
As a result of the Spin Off of Monterey in July 1997, all outstanding Stock
Options were adjusted to reflect the effect of the transaction on the value of
the Company's common stock. The anti-dilution formula utilized follows the
Internal Revenue Service approved guidelines for adjusting Qualified Incentive
Stock Options and took into account the average sales prices for the Company's
common stock for a period of time before and after the Spin Off. As a result of
the adjustment the number of options outstanding increased by a factor of 1.7045
and the strike price was reduced accordingly in order to preserve the value of
either in the money or out of the money spread in existence at the time. The
Company will receive the same overall consideration for the underlying
securities upon exercise of the option. All outstanding Phantom Units were also
adjusted utilizing the same formula. All other terms and conditions of the
options and the Phantom Units remained unchanged.
The Company has elected to continue to account for stock-based compensation
costs in accordance with APB Opinion No. 25. Earnings (loss) attributable to
common shares and the related per share amounts would have been reduced as is
reflected by the pro forma amounts in the following table (in millions, except
per share data):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
AS REPORTED:
Earnings (loss) attributable to common shares ........ $ (98.7) $ 42.7 $ (10.8)
Earnings (loss) per common share, basic and diluted .. $ (0.96) $ 0.43 $ (0.12)
PROFORMA:
Earnings (loss) attributable to common shares ........ $ (102.4) $ 41.4 $ (12.6)
Earnings (loss) per common share, basic and diluted .. $ (1.00) $ 0.42 $ (0.14)
</TABLE>
NOTE 13. PENSION AND OTHER POSTRETIREMENT BENEFITS
In the fourth quarter of 1998, the Company adopted SFAS 132 which revised
disclosures about pension and other postretirement benefit plans. Disclosures
regarding pension benefits represent the combination of three plans the Company
offers its employees. These plans include (i) a defined benefit retirement plan
(the "SFER Plan") covering substantially all salaried employees, (ii) a
nonqualified supplemental plan (the "Supplemental Plan") which pays benefits to
participants in the SFER Plan in those instances where the SFER Plan formula
produces a benefit in excess of limits established by ERISA and The Tax Reform
Act of 1986 and (iii) a pension plan for certain persons employed in foreign
locations (the "Foreign Plan"). Disclosures regarding other benefits represent
health care and life insurance benefits for substantially all employees who
retire under the provisions of a Company-sponsored retirement plan and their
dependents.
69
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the status of those plans and benefits
described above at December 31, 1998 and 1997 (in millions):
<TABLE>
<CAPTION>
PENSION BENEFITS OTHER BENEFITS
----------------- -----------------
1998 1997 1998 1997
------ ------ ------ ------
<S> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at beginning of year .................. $ 42.2 $ 44.4 $ 6.6 $ 7.3
Service cost ............................................. 1.7 1.9 0.4 0.5
Interest cost ............................................ 3.1 3.2 0.5 0.5
Contribution by plan participants ........................ -- -- 0.1 0.1
Curtailment .............................................. -- (3.4) -- (0.7)
Settlement ............................................... -- (3.3) -- --
Actuarial (gain) loss .................................... 3.8 1.9 1.0 (0.5)
Benefits paid ............................................ (2.1) (2.5) (0.5) (0.6)
------ ------ ------ ------
Benefit obligation at end of year ........................ $ 48.7 $ 42.2 $ 8.1 $ 6.6
------ ------ ------ ------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year ........... $ 37.1 $ 36.1 $ -- $ --
Actual return on plan assets ............................. 0.2 6.6 -- --
Company contribution ..................................... -- 0.2 0.4 0.5
Contribution by plan participants ........................ -- -- 0.1 0.1
Benefits paid ............................................ (2.1) (5.8) (0.5) (0.6)
------ ------ ------ ------
Fair value of plan assets at end of year ................. $ 35.2 $ 37.1 $ -- $ --
------ ------ ------ ------
Funded status ............................................ $(13.5) $ (5.1) $ (8.1) $ (6.6)
Contributions ............................................ -- -- 0.1 0.1
Unrecognized net (gain) loss ............................. 4.4 (2.7) 0.2 (0.8)
Unrecognized prior service cost .......................... 0.5 0.5 -- --
Unrecognized net transition (asset) obligation ........... (0.5) (0.5) 2.3 2.5
------ ------ ------ ------
Prepaid (accrued) benefit cost ........................... $ (9.1) $ (7.8) $ (5.5) $ (4.8)
====== ====== ====== ======
WEIGHTED AVERAGE ASSUMPTIONS AT YEAR END:
Discount rate ............................................ 6.75% 7.50% 6.75% 7.50%
Expected return on plan assets ........................... 9.50% 9.50% -- --
Rate of compensation increase ............................ 4.75% 5.25% 4.75% 5.25%
Health care trend rate ................................... -- -- 6.00% 6.00%
EFFECTS OF CHANGES IN ASSUMED HEALTH CARE COST TREND RATE:
EFFECT OF A ONE PERCENTAGE POINT INCREASE
Effect on postretirement benefit obligation .............. $ 0.7 $ 0.5
Effect on total of service and interest cost components .. $ 0.1 $ 0.1
EFFECT OF A ONE PERCENTAGE POINT DECREASE
Effect on postretirement benefit obligation .............. $ (0.6) $ (0.4)
Effect on total of service and interest cost components .. $ (0.1) $ (0.1)
</TABLE>
70
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PENSION PLAN OTHER BENEFITS
----------------------------- ---------------------------
1998 1997 1996 1998 1997 1996
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
COMPONENTS OF NET PERIODIC BENEFIT COST:
Service cost ................................ $ 1.7 $ 1.9 $ 1.8 $ 0.4 $ 0.5 $ 0.5
Interest cost ............................... 3.1 3.2 3.1 0.5 0.5 0.5
Expected return on plan assets .............. (3.4) (3.3) (3.1) -- -- --
Amortization of transition obligation ....... -- (0.1) (0.1) 0.2 0.2 0.3
Amortization of loss (gain) ................. (0.1) -- (0.1) -- -- --
Curtailment charges (credits) ............... -- (2.4) -- -- 0.3 --
------- ------- ------- ------- ------- -------
Net periodic benefit cost ................... $ 1.3 $ (0.7) $ 1.6 $ 1.1 $ 1.5 $ 1.3
======= ======= ======= ======= ======= =======
</TABLE>
The aggregate projected benefit obligation, the aggregate accumulated benefit
obligation and the aggregate fair value of plan assets for plans with benefit
obligations in excess of plan assets were $48.7 million, $40.0 million and $35.2
million, respectively, as of December 31, 1998 and $42.2 million, $34.3 million
and $37.1 million, respectively, as of December 31, 1997.
SAVINGS PLAN
The Company has a savings plan available to substantially all salaried
employees and intended to qualify as a deferred compensation plan under Section
401(k) of the Internal Revenue Code (the "401(k) Plan"). The Company matches
employee contributions for amounts up to 4% of each employee's base salary. In
addition, if at the end of each fiscal year the Company's performance for such
year has exceeded certain predetermined criteria, each participant will receive
an additional matching contribution equal to 50% of the regular matching
contribution. The Company's contributions to the 401(k) Plan, which are made in
the form of the Company's common stock and charged to expense, totaled $1.3
million in 1998, $1.6 million in 1997 and $1.2 million in 1996.
The Company also has a savings plan with respect to certain personnel
employed in foreign locations. The plan is an unsecured creditor of the Company
and at December 31, 1998 and 1997 the Company's liability with respect to the
plan totaled $0.6 million and $0.4 million, respectively.
NOTE 14. COMMITMENTS AND CONTINGENCIES
OIL AND GAS HEDGING. The Company periodically hedges a portion of its oil and
gas sales to provide a certain minimum level of cash flow from its sales of oil
and gas. While the hedges are generally intended to reduce the Company's
exposure to declines in market price, the Company's gain from increases in
market price may be limited. The Company uses various financial instruments
whereby monthly settlements are based on differences between the prices
specified in the instruments and the settlement prices of certain futures
contracts quoted on the New York Mercantile Exchange ("NYMEX") or certain other
indices. Generally, in instances where the applicable settlement price is less
than the price specified in the contract, the Company receives a settlement
based on the difference; in instances where the applicable settlement price is
higher than the specified price, the Company pays an amount based on the
difference. The instruments utilized by the Company differ from futures
contracts in that there is no contractual obligation which requires or allows
for the future delivery of the product. Gains or losses on hedging activities
are recognized in oil and gas revenues in the period in which the hedged
production is sold.
71
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude oil sales hedges resulted in a $2.5 million increase, a $2.2 million
increase and a $21.4 million decrease in revenues in 1998, 1997 and 1996,
respectively. At December 31, 1998, the Company had no open crude oil sales
hedges.
At December 31, 1998 and 1997, the Company had no open natural gas sales
hedges. Natural gas sales hedges resulted in a decrease in revenues of $21.4
million in 1996.
As of March 1, 1999, the Company has not entered into any additional hedging
agreements.
ENVIRONMENTAL REGULATION. The Company's oil and gas operations are subject to
stringent environmental regulation by government authorities. Such regulation
has increased the costs of planning, designing, drilling, installing, operating
and abandoning oil and gas wells and associated facilities. The Company has
expended significant financial and managerial resources to comply with such
regulations. Although the Company believes its operations and facilities are in
general compliance with applicable environmental regulations, the risk of
substantial costs and liabilities are inherent to oil and gas operations. It is
possible that other developments, such as increasingly strict environmental
laws, regulations and enforcement policies or claims for damages to property,
employees, other persons and the environment resulting from the Company's
operations, could result in significant costs and liabilities in the future. As
it has in the past, the Company intends to fund the future costs of
environmental compliance from operating cash flows.
Adobe Resources Corporation, which was merged into the Company in 1992, was
named as a PRP with respect to the Gulf Coast Vacuum Services Superfund site
located in Abbeville, Louisiana. The Company has entered into a sharing
agreement with other PRPs to participate in the final remediation of this site.
The remediation phase is expected to be completed by June 1999, at which time
long-term monitoring will commence. The Company estimates its share of the
remediation and monitoring phases to be approximately $150,000, which has been
provided for in the Company's financial statements.
OPERATING LEASES. The Company has noncancellable agreements with terms
ranging from one to ten years to lease office space, office equipment and
certain production equipment in foreign locations. Minimum rental payments due
under the terms of these agreements are: 1999 - $14.7 million, 2000 - $13.8
million, 2001 - $9.2 million, 2002 - $8.7 million, 2003 - $4.9 million and $26.4
million thereafter. Rental expense under the terms of noncancellable agreements
totaled $15.2 million in 1998, $10.8 million in 1997 and $5.9 million in 1996.
OTHER MATTERS. In connection with the development of the Sierra Chata gas
field in Argentina in which the Company has a 19.9% working interest, a gas
contract with "take-or-pay" and "delivery-to-pay" obligations was executed in
1994 with a gas distribution company.
There are other claims and actions, including certain other environmental
matters, pending against the Company. In the opinion of management, the amounts,
if any, which may be awarded in connection with any of these claims and actions
could be significant to the results of operations of any period but would not be
material to the Company's consolidated financial position.
72
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 15. FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of the financial instruments disclosed herein is not
representative of the amount that could be realized or settled, nor does the
fair value amount consider the tax consequences, if any, of realization or
settlement. The following table reflects the financial instruments for which the
fair value differs from the carrying amount of such financial instrument in the
Company's December 31, 1998 and 1997 balance sheets (in millions):
1998 1997
------------------- -------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ------- -------- -------
Liabilities:
Long-term debt ................. $ 330.6 $ 336.4 $ 121.7 $ 130.7
The fair value of the Company's 11% Senior Subordinated Debentures is based
on market prices. The fair value of the Company's fixed-rate long-term debt is
based on current borrowing rates available for financing with similar terms and
maturities. With respect to the Company's floating-rate debt, the carrying
amount approximates fair value.
NOTE 16. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
1998:
Revenues ............................................. $ 68.8 $ 77.8 $ 75.9 $ 68.5 $ 291.0
Gross profit (loss) (a) .............................. (0.9) 5.4 (18.8) (120.0) (134.3)
Loss (gain) on sale of assets ........................ -- 1.2 0.2 0.1 1.5
Income (loss) from operations ........................ (5.3) 0.8 (23.9) (125.6) (154.0)
Net income (loss) .................................... (0.3) 0.4 (17.8) (81.0) (98.7)
Earnings (loss) attributable to common shares ........ (0.3) 0.4 (17.8) (81.0) (98.7)
Earnings (loss) per common share
Basic ............................................. $ -- $ -- $ (0.17) $ (0.79) $ (0.96)
Diluted ........................................... -- -- (0.17) (0.79) (0.96)
Weighted average shares outstanding .................. 102.7 102.9 102.6 102.2 102.6
The following table includes the results of Monterey for the first seven months of 1997
1997 (b):
Revenues ............................................. $ 173.9 $ 149.8 $ 101.8 $ 89.2 $ 514.7
Gross profit (a) ..................................... 62.9 37.3 25.8 12.9 138.9
Loss (gain) on sale of assets ........................ (2.3) 0.2 (1.9) 0.4 (3.6)
Income from operations ............................... 55.8 27.2 20.8 7.0 110.8
Net income ........................................... 27.9 12.5 10.7 3.6 54.7
Earnings attributable to common shares ............... 25.5 2.9 10.7 3.6 42.7
Earnings per common share
Basic (c) ......................................... $ 0.28 $ 0.03 $ 0.10 $ 0.04 $ 0.43
Diluted (c) ....................................... 0.27 0.03 0.10 0.04 0.43
Weighted average shares outstanding .................. 91.2 97.0 102.9 103.0 98.6
</TABLE>
(a) Revenues less operating expenses other than general and administrative.
(b) The second quarter of 1997 includes an $8.4 million Convertible preferred
premium (see Note 10).
(c) Per share amounts may not add across due to the changes in the average
number of common shares outstanding.
73
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
Information with respect to the Company's oil and gas producing activities is
presented in the following tables. Reserve quantities as well as certain
information regarding future production and discounted cash flows were
determined by independent petroleum consultants, Ryder Scott Company, for all
years presented, with the exception of the Company's reserves on the Jabung
Block in Indonesia at December 31, 1998, which were prepared by the Company.
OIL AND GAS RESERVES
The following table sets forth the Company's net proved oil and gas reserves
at December 31, 1995, 1996, 1997 and 1998 and the changes in net proved oil and
gas reserves for the years ended December 31, 1996, 1997 and 1998.
<TABLE>
<CAPTION>
CRUDE OIL AND LIQUIDS (MMBLS)
---------------------------------------------------------------
TOTAL
OTHER EXCLUDING
U.S. ARGENTINA INDONESIA INT'L. TOTAL MONTEREY
----- --------- --------- ------ ----- ---------
<S> <C> <C> <C> <C> <C> <C>
Balance of Proved Reserves
at December 31, 1995 ............. 258.6 12.8 7.8 -- 279.2 79.7
Revisions of previous estimates ..... 15.6 (0.2) 2.3 -- 17.7 5.7
Improved recovery techniques ........ 14.4 -- -- -- 14.4 --
Extensions, discoveries
and other additions .............. 0.6 1.3 0.3 -- 2.2 2.2
Purchases of minerals-in-place ...... 10.7 2.8 -- -- 13.5 5.9
Sales of minerals-in-place .......... (0.3) -- -- -- (0.3) (0.3)
Production .......................... (24.3) (1.4) (1.5) -- (27.2) (10.1)
----- --------- --------- ------ ----- ---------
Balance of Proved Reserves
at December 31, 1996 ............. 275.3 15.3 8.9 -- 299.5 83.1
Revisions of previous estimates ..... 6.9 2.1 2.2 -- 11.2 11.2
Improved recovery techniques ........ 10.6 -- -- -- 10.6 10.6
Extensions, discoveries
and other additions .............. 1.0 3.9 15.6 4.4 24.9 24.9
Purchases of minerals-in-place ...... 3.9 6.4 -- -- 10.3 10.3
Sales of minerals-in-place .......... -- -- -- -- -- --
Spin Off of Monterey Resources ...... (205.8) -- -- -- (205.8) --
Production .......................... (18.3) (1.8) (1.6) -- (21.7) (11.1)
----- --------- --------- ------ ----- ---------
Balance of Proved Reserves ..........
at December 31, 1997 ............. 73.6 25.9 25.1 4.4 129.0 129.0
Revisions of previous estimates ..... (7.5) (5.2) 11.7 -- (1.0) (1.0)
Extensions, discoveries
and other additions .............. 1.8 0.9 22.0 9.1 33.8 33.8
Purchases of minerals-in-place ...... 1.3 -- 6.4 13.9 21.6 21.6
Sales of minerals-in-place .......... -- -- -- -- -- --
Production .......................... (7.7) (2.0) (4.5) (0.6) (14.8) (14.8)
----- --------- --------- ------ ----- ---------
Balance of Proved Reserves ..........
at December 31, 1998 ............. 61.5 19.6 60.7 26.8 168.6 168.6
===== ========= ========= ====== ===== =========
Proved Developed Reserves
at December 31,
1995 .......................... 206.5 7.1 6.0 -- 219.6 62.5
1996 .......................... 224.1 8.5 6.5 -- 239.1 68.1
1997 .......................... 68.0 15.2 21.8 -- 105.0 105.0
1998 .......................... 56.5 12.3 39.5 1.8 110.1 110.1
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NATURAL GAS (BCF)
------------------------------------------------------
TOTAL
EXCLUDING
U.S. ARGENTINA INDONESIA TOTAL MONTEREY
----- --------- --------- ------ ---------
<S> <C> <C> <C> <C> <C>
Balance of Proved Reserves
at December 31, 1995 ............. 209.9 34.7 0.5 245.1 232.7
Revisions of previous estimates ..... 25.9 (2.4) (0.2) 23.3 22.2
Improved recovery techniques ........ -- -- -- -- --
Extensions, discoveries
and other additions .............. 40.8 1.1 -- 41.9 41.9
Purchases of minerals-in-place ...... 11.7 0.6 -- 12.3 12.3
Sales of minerals-in-place .......... (2.1) -- -- (2.1) (2.1)
Production .......................... (53.4) (7.6) (0.1) (61.1) (59.8)
----- --------- --------- ------ ---------
Balance of Proved Reserves
at December 31, 1996 ............. 232.8 26.4 0.2 259.4 247.2
Revisions of previous estimates ..... 22.7 16.4 -- 39.1 39.1
Improved recovery techniques ........ -- -- -- -- --
Extensions, discoveries
and other additions .............. 34.9 1.2 -- 36.1 36.1
Purchases of minerals-in-place ...... 7.0 -- -- 7.0 7.0
Sales of minerals-in-place .......... (13.0) -- -- (13.0) (13.0)
Spin Off of Monterey Resources ...... (11.6) -- -- (11.6) --
Production .......................... (56.5) (7.8) (0.1) (64.4) (63.8)
----- --------- --------- ------ ---------
Balance of Proved Reserves ..........
at December 31, 1997 ............. 216.3 36.2 0.1 252.6 252.6
Revisions of previous estimates ..... 9.4 6.3 -- 15.7 15.7
Extensions, discoveries
and other additions .............. 54.6 3.7 -- 58.3 58.3
Purchases of minerals-in-place ...... 18.8 -- -- 18.8 18.8
Sales of minerals-in-place .......... (2.3) -- -- (2.3) (2.3)
Production .......................... (55.5) (9.4) (0.1) (65.0) (65.0)
----- --------- --------- ------ ---------
Balance of Proved Reserves ..........
at December 31, 1998 ............. 241.3 36.8 -- 278.1 278.1
===== ========= ========= ====== =========
Proved Developed Reserves
at December 31,
1995 .......................... 170.2 33.3 0.5 204.0 194.8
1996 .......................... 193.6 25.9 0.2 219.7 210.2
1997 .......................... 184.8 35.6 0.1 220.5 220.5
1998 .......................... 194.8 35.0 -- 229.8 229.8
</TABLE>
74
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Proved reserves are estimated quantities of crude oil and natural gas which
geological and engineering data indicate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
Indonesian reserves represent an entitlement to gross reserves in accordance
with a production sharing contract. These reserves include estimated quantities
allocable to the Company for recovery of operating costs as well as quantities
related to the Company's net equity share after recovery of costs. Accordingly,
these quantities are subject to fluctuations with an inverse relationship to the
price of oil. If oil prices increase, the reserve quantities attributable to the
recovery of operating costs decline. Although this reduction would be offset
partially by an increase in the net equity share, the overall effect would be a
reduction of reserves attributable to the Company. The Company has certain
commitments with respect to the delivery of natural gas which the Company
believes it can fulfill from its proved reserves and supply contracts with other
companies.
At December 31, 1998, 1.8 million barrels of crude oil reserves and 13.6
billion cubic feet of natural gas reserves were subject to a 90% net profits
interest held by Santa Fe Energy Trust.
ESTIMATED PRESENT VALUE OF FUTURE NET CASH FLOWS
Estimated future net cash flows from the Company's proved oil and gas
reserves at December 31, 1998, 1997 and 1996 are presented in the following
table (in millions, except as noted):
<TABLE>
<CAPTION>
TOTAL
OTHER EXCLUDING
U.S. ARGENTINA INDONESIA INT'L. TOTAL MONTEREY
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1998:
Future cash inflows .................... $ 1,067.1 $ 217.7 $ 582.8 $ 262.3 $ 2,129.9 $ 2,129.9
Future production costs ................ (445.2) (130.2) (251.0) (95.3) (921.7) (921.7)
Future development costs ............... (90.5) (42.4) (127.9) (77.6) (338.4) (338.4)
Future income tax expenses ............. (31.5) -- (18.7) (20.3) (70.5) (70.5)
--------- --------- --------- --------- --------- ---------
Net future cash flows ............... 499.9 45.1 185.2 69.1 799.3 799.3
Discount at 10% for timing of cash flows (183.8) (15.3) (71.9) (46.3) (317.3) (317.3)
--------- --------- --------- --------- --------- ---------
Present value of future net cash flows
from proved reserves ................ $ 316.1 $ 29.8 $ 113.3 $ 22.8 $ 482.0 $ 482.0
========= ========= ========= ========= ========= =========
Present value of pretax future net cash
flows from proved reserves .......... $ 336.0 $ 29.8 $ 126.0 $ 26.7 $ 518.5 $ 518.5
========= ========= ========= ========= ========= =========
Average sales prices:
Oil ($/Barrel) ...................... $ 9.94 $ 8.70 $ 10.14 $ 9.77 $ 9.81 $ 9.81
Natural gas ($/Mcf) ................. 1.94 1.29 -- -- 1.85 1.85
TABLE CONTINUED ON NEXT PAGE
</TABLE>
75
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
<TABLE>
<CAPTION>
TOTAL
OTHER EXCLUDING
U.S. ARGENTINA INDONESIA INT'L. TOTAL MONTEREY
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1997:
Future cash inflows .................... $ 1,653.8 $ 431.0 $ 412.9 $ 69.9 $ 2,567.6 $ 2,567.6
Future production costs ................ (657.4) (190.9) (142.3) (38.3) (1,028.9) (1,028.9)
Future development costs ............... (118.1) (75.5) (83.0) (11.3) (287.9) (287.9)
Future income tax expenses ............. (208.2) (24.4) (54.7) (5.6) (292.9) (292.9)
--------- --------- --------- --------- --------- ---------
Net future cash flows ............... 670.1 140.2 132.9 14.7 957.9 957.9
Discount at 10% for timing of cash flows (259.2) (61.0) (55.0) (3.0) (378.2) (378.2)
--------- --------- --------- --------- --------- ---------
Present value of future net cash flows
from proved reserves ................ $ 410.9 $ 79.2 $ 77.9 $ 11.7 $ 579.7 $ 579.7
========= ========= ========= ========= ========= =========
Present value of pretax future net cash
flows from proved reserves .......... $ 538.6 $ 93.1 $ 111.9 $ 16.1 $ 759.7 $ 759.7
========= ========= ========= ========= ========= =========
Average sales prices:
Oil ($/Barrel) ...................... $ 16.30 $ 14.96 $ 16.59 $ 16.00 $ 16.06 $ 16.06
Natural gas ($/Mcf) ................. 2.26 1.21 1.05 -- 2.11 2.11
1996:
Future cash inflows .................... $ 6,393.6 $ 377.7 $ 191.8 $ -- $ 6,963.1 $ 2,793.8
Future production costs ................ (2,792.7) (138.8) (135.2) -- (3,066.7) (888.7)
Future development costs ............... (286.7) (53.0) (22.5) -- (362.2) (191.6)
Future income tax expenses ............. (999.2) (33.4) (11.9) -- (1,044.5) (461.2)
--------- --------- --------- --------- --------- ---------
Net future cash flows ............... 2,315.0 152.5 22.2 -- 2,489.7 1,252.3
Discount at 10% for timing of cash flows (951.2) (54.3) (7.1) -- (1,012.6) (486.5)
--------- --------- --------- --------- --------- ---------
Present value of future net cash flows
from proved reserves ................ $ 1,363.8 $ 98.2 $ 15.1 $ -- $ 1,477.1 $ 765.8
========= ========= ========= ========= ========= =========
Present value of pretax future net cash
flows from proved reserves .......... $ 1,952.3 $ 119.6 $ 23.6 $ -- $ 2,095.5 $ 1,047.7
========= ========= ========= ========= ========= =========
Average sales prices:
Oil ($/Barrel) ...................... $ 20.35 $ 22.62 $ 21.67 $ -- $ 20.51 $ 24.14
Natural gas ($/Mcf) ................. 3.47 1.20 1.05 -- 3.24 3.33
</TABLE>
76
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
The following tables set forth the changes in the present value of estimated
future net cash flows from proved reserves during 1998, 1997 and 1996 (in
millions):
<TABLE>
<CAPTION>
TOTAL
OTHER EXCLUDING
U.S. ARGENTINA INDONESIA INT'L. TOTAL MONTEREY
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1998:
Balance at beginning of year ................... $ 410.9 $ 79.2 $ 77.9 $ 11.7 $ 579.7 $ 579.7
--------- --------- --------- --------- --------- ---------
Increase (decrease) due to:
Sales of oil and gas, net of production
costs of $115.0 million .................. (129.6) (17.6) (25.9) -- (173.1) (173.1)
Net changes in prices and production costs .. (228.7) (86.2) (102.9) (20.8) (438.6) (438.6)
Extensions, discoveries and improved recovery 52.8 10.9 134.9 17.2 215.8 215.8
Purchase of mineral-in-place ................ 43.3 -- 61.2 4.9 109.4 109.4
Sales of minerals-in-place .................. (8.2) -- -- -- (8.2) (8.2)
Development costs incurred .................. 130.1 21.6 68.5 19.1 239.3 239.3
Changes in estimated volumes ................ (0.9) (9.6) (113.8) 1.3 (123.0) (123.0)
Changes in estimated development costs ...... (105.6) 11.7 (22.8) (12.8) (129.5) (129.5)
Interest factor - accretion of discount ..... 44.3 6.0 15.3 1.8 67.4 67.4
Income taxes ................................ 107.7 13.8 20.9 0.4 142.8 142.8
--------- --------- --------- --------- --------- ---------
(94.8) (49.4) 35.4 11.1 (97.7) (97.7)
--------- --------- --------- --------- --------- ---------
Balance at end of year ......................... $ 316.1 $ 29.8 $ 113.3 $ 22.8 $ 482.0 $ 482.0
========= ========= ========= ========= ========= =========
1997:
Balance at beginning of year ................... $ 1,363.8 $ 98.2 $ 15.1 $ -- $ 1,477.1 $ 765.8
--------- --------- --------- --------- --------- ---------
Increase (decrease) due to:
Sales of oil and gas, net of production
costs of $177.1 million .................. (271.4) (26.9) (10.8) -- (309.1) (241.5)
Net changes in prices and production costs .. (444.7) (73.8) 16.0 -- (502.5) (474.6)
Extensions, discoveries and improved recovery 107.0 7.3 64.0 16.1 194.4 195.8
Purchase of mineral-in-place ................ 24.0 32.2 -- -- 56.2 57.0
Spin Off of Monterey Resources .............. (932.2) -- -- -- (932.2) --
Sales of minerals-in-place .................. (36.3) -- -- -- (36.3) (36.3)
Development costs incurred .................. 325.7 54.6 30.7 5.2 416.2 208.0
Changes in estimated volumes ................ 28.4 14.7 11.7 -- 54.8 74.9
Changes in estimated development costs ...... (294.9) (44.9) (25.4) (5.2) (370.4) (163.6)
Interest factor - accretion of discount ..... 80.6 10.2 2.2 -- 93.0 92.6
Income taxes ................................ 460.9 7.6 (25.6) (4.4) 438.5 101.6
--------- --------- --------- --------- --------- ---------
(952.9) (19.0) 62.8 11.7 (897.4) (186.1)
--------- --------- --------- --------- --------- ---------
Balance at end of year ......................... $ 410.9 $ 79.2 $ 77.9 $ 11.7 $ 579.7 $ 579.7
========= ========= ========= ========= ========= =========
1996:
Balance at beginning of year ................... $ 841.9 $ 58.1 $ 30.2 $ -- $ 930.2 $ 462.2
--------- --------- --------- --------- --------- ---------
Increase (decrease) due to:
Sales of oil and gas, net of production
costs of $210.8 million .................. (311.7) (25.6) (13.9) -- (351.2) (236.7)
Net changes in prices and production costs .. 552.1 35.0 (8.3) -- 578.8 312.5
Extensions, discoveries and improved recovery 169.1 16.4 0.8 -- 186.3 122.9
Purchase of mineral-in-place ................ 92.5 19.2 -- -- 111.7 73.4
Sales of minerals-in-place .................. (3.3) -- -- -- (3.3) (2.7)
Development costs incurred .................. 145.4 19.5 12.9 -- 177.8 123.9
Changes in estimated volumes ................ 152.3 6.6 3.1 -- 162.0 43.6
Changes in estimated development costs ...... (100.8) (23.4) (22.8) -- (147.0) (122.9)
Interest factor - accretion of discount ..... 113.7 6.6 3.0 -- 123.3 61.3
Income taxes ................................ (287.4) (14.2) 10.1 -- (291.5) (71.7)
--------- --------- --------- --------- --------- ---------
521.9 40.1 (15.1) -- 546.9 303.6
--------- --------- --------- --------- --------- ---------
Balance at end of year ......................... $ 1,363.8 $ 98.2 $ 15.1 $ -- $ 1,477.1 $ 765.8
========= ========= ========= ========= ========= =========
</TABLE>
77
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Estimated future cash flows represent an estimate of future net cash flows
from the production of proved reserves using estimated sales prices and
estimates of the production costs, ad valorem and production taxes, and future
development costs necessary to produce such reserves. No deduction has been made
for depletion, depreciation or any indirect costs such as general corporate
overhead or interest expense.
The sales prices used in the calculation of estimated future net cash flows
are based on the prices in effect at year end. Such prices have been held
constant except for known and determinable escalation.
Operating costs and ad valorem and production taxes are estimated based on
current costs with respect to producing oil and gas properties. Future
development costs are based on the best estimate of such costs assuming current
economic and operating conditions.
Income tax expense is computed based on applying the appropriate statutory
tax rate to the excess of future cash inflows less future production and
development costs over the current tax basis of the properties involved. While
applicable investment tax credits and other permanent differences are considered
in computing taxes, no recognition is given to tax benefits applicable to future
exploration costs or the activities of the Company that are unrelated to oil and
gas producing activities.
The information presented with respect to estimated future net revenues and
cash flows and the present value thereof is not intended to represent the fair
value of oil and gas reserves. Actual future sales prices and production and
development costs may vary significantly from those in effect at year end and
actual future production may not occur in the periods or amounts projected. This
information is presented to allow a reasonable comparison of reserve values
prepared using standardized measurement criteria and should be used only for
that purpose.
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
The following table includes all costs incurred, whether capitalized or
charged to expense at the time incurred (in millions):
<TABLE>
<CAPTION>
TOTAL
OTHER EXCLUDING
U.S. ARGENTINA INDONESIA INT'L. TOTAL MONTEREY
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1998:
Property acquisition costs:
Unproved .................... $ 13.6 $ 0.9 $ 3.0 $ 0.9 $ 18.4 $ 18.4
Proved ...................... 60.2 -- 42.2 7.9 110.3 110.3
Exploration costs .............. 36.3 2.1 3.7 49.2 91.3 91.3
Development costs .............. 73.6 26.8 27.7 18.2 146.3 146.3
--------- --------- --------- --------- --------- ---------
Total .......................... $ 183.7 $ 29.8 $ 76.6 $ 76.2 $ 366.3 $ 366.3
========= ========= ========= ========= ========= =========
1997:
Property acquisition costs:
Unproved .................... $ 14.9 $ -- $ 0.2 $ 2.1 $ 17.2 $ 17.1
Proved ...................... 185.2 37.4 -- 0.2 222.8 84.3
Exploration costs .............. 48.5 2.1 6.0 9.0 65.6 64.5
Development costs .............. 115.6 17.2 30.7 5.2 168.7 128.3
--------- --------- --------- --------- --------- ---------
Total .......................... $ 364.2 $ 56.7 $ 36.9 $ 16.5 $ 474.3 $ 294.2
========= ========= ========= ========= ========= =========
</TABLE>
TABLE CONTINUED ON NEXT PAGE
78
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
<TABLE>
<CAPTION>
TOTAL
OTHER EXCLUDING
U.S. ARGENTINA INDONESIA INT'L. TOTAL MONTEREY
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1996:
Property acquisition costs:
Unproved .................... $ 31.6 $ -- $ -- $ 1.8 $ 33.4 $ 33.3
Proved ...................... 30.2 7.4 -- 0.2 37.8 34.4
Exploration costs .............. 29.5 0.1 2.4 11.4 43.4 41.7
Development costs .............. 115.2 12.1 12.9 3.9 144.1 97.1
--------- --------- --------- --------- --------- ---------
Total .......................... $ 206.5 $ 19.6 $ 15.3 $ 17.3 $ 258.7 $ 206.5
========= ========= ========= ========= ========= =========
</TABLE>
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth information concerning capitalized costs at
December 31, 1998 and 1997 related to the Company's oil and gas operations (in
millions):
<TABLE>
<CAPTION>
TOTAL
OTHER EXCLUDING
U.S. ARGENTINA INDONESIA INT'L. TOTAL MONTEREY
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1998:
Oil and gas properties:
Unproved ........................................ $ 75.3 $ 9.8 $ 15.0 $ 4.9 $ 105.0 $ 105.0
Proved .......................................... 1,427.1 164.3 216.8 41.1 1,849.3 1,849.3
Other ........................................... 2.2 -- -- -- 2.2 2.2
Accumulated amortization of unproved properties .... (41.5) (2.3) (5.4) (3.7) (52.9) (52.9)
Accumulated depletion, depreciation and
impairment of proved properties ................. (1,050.5) (45.1) (89.4) (5.8) (1,190.8) (1,190.8)
Accumulated depreciation of other
oil and gas properties .......................... (0.7) -- -- -- (0.7) (0.7)
--------- --------- --------- --------- --------- ---------
Total .............................................. $ 411.9 $ 126.7 $ 137.0 $ 36.5 $ 712.1 $ 712.1
========= ========= ========= ========= ========= =========
1997:
Oil and gas properties:
Unproved ........................................ $ 65.2 $ 4.9 $ 11.9 $ 4.0 $ 86.0 $ 86.0
Proved .......................................... 1,290.6 143.5 145.5 14.9 1,594.5 1,594.5
Other ........................................... 1.9 -- -- -- 1.9 1.9
Accumulated amortization of unproved properties .... (18.5) (2.1) (4.8) (2.8) (28.2) (28.2)
Accumulated depletion, depreciation and
impairment of proved properties ................. (903.9) (32.4) (70.2) (3.7) (1,010.2) (1,010.2)
Accumulated depreciation of other
oil and gas properties .......................... (0.7) -- -- -- (0.7) (0.7)
--------- --------- --------- --------- --------- ---------
Total .............................................. $ 434.6 $ 113.9 $ 82.4 $ 12.4 $ 643.3 $ 643.3
========= ========= ========= ========= ========= =========
</TABLE>
79
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the Company's results of operations from oil
and gas producing activities for the years ended December 31, 1998, 1997 and
1996 (in millions):
<TABLE>
<CAPTION>
TOTAL
OTHER EXCLUDING
U.S. ARGENTINA INDONESIA INT'L. TOTAL MONTEREY
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1998:
Revenues ................................. $ 196.2 $ 33.6 $ 53.5 $ 7.7 $ 291.0 $ 291.0
Production costs:
Production and operating costs ........ (61.0) (15.5) (27.6) (8.4) (112.5) (112.5)
Taxes other than income ............... (12.4) (0.3) -- -- (12.7) (12.7)
Exploration, including dry hole costs .... (21.6) (2.5) (0.5) (46.5) (71.1) (71.1)
Depletion, depreciation,
amortization and impairments .......... (184.2) (12.9) (19.7) (3.1) (219.9) (219.9)
Gain (loss) on disposal of properties .... (1.5) -- -- -- (1.5) (1.5)
--------- --------- --------- --------- --------- ---------
(84.5) 2.4 5.7 (50.3) (126.7) (126.7)
Income tax (expense) benefit ............. 29.6 (0.8) (3.0) 18.3 44.1 44.1
--------- --------- --------- --------- --------- ---------
$ (54.9) $ 1.6 $ 2.7 $ (32.0) $ (82.6) $ (82.6)
========= ========= ========= ========= ========= =========
1997:
Revenues ................................. $ 446.3 $ 40.6 $ 27.8 $ -- $ 514.7 $ 333.5
Production costs:
Production and operating costs ........ (128.1) (13.3) (16.7) (0.8) (158.9) (87.6)
Taxes other than income ............... (17.8) (0.4) -- -- (18.2) (12.5)
Cost of crude oil produced ............... (22.0) -- -- -- (22.0) --
Exploration, including dry hole costs .... (37.9) (2.2) (4.6) (4.4) (49.1) (48.2)
Depletion, depreciation,
amortization and impairments .......... (108.6) (8.4) (6.9) (0.6) (124.5) (102.5)
Gain (loss) on disposal of properties .... 3.6 -- -- -- 3.6 3.6
--------- --------- --------- --------- --------- ---------
135.5 16.3 (0.4) (5.8) 145.6 86.3
Income tax (expense) benefit ............. (48.8) (4.9) 0.1 2.2 (51.4) (30.0)
--------- --------- --------- --------- --------- ---------
$ 86.7 $ 11.4 $ (0.3) $ (3.6) $ 94.2 $ 56.3
========= ========= ========= ========= ========= =========
1996:
Revenues ................................. $ 517.9 $ 35.8 $ 29.6 $ -- $ 583.3 $ 290.4
Production costs:
Production and operating costs ........ (162.4) (10.0) (15.7) (0.3) (188.4) (80.6)
Taxes other than income ............... (22.2) (0.2) -- -- (22.4) (14.2)
Cost of crude oil produced ............... (20.8) -- -- -- (20.8) --
Exploration, including dry hole costs .... (21.9) (0.1) (0.6) (11.9) (34.5) (32.8)
Depletion, depreciation,
amortization and impairments .......... (164.9) (7.9) (24.6) (5.0) (202.4) (166.3)
Gain (loss) on disposal of properties .... 0.3 -- -- (0.2) 0.1 0.1
--------- --------- --------- --------- --------- ---------
126.0 17.6 (11.3) (17.4) 114.9 (3.4)
Income tax (expense) benefit ............. (49.6) (5.3) 2.9 3.5 (48.5) (0.1)
--------- --------- --------- --------- --------- ---------
$ 76.4 $ 12.3 $ (8.4) $ (13.9) $ 66.4 $ (3.5)
========= ========= ========= ========= ========= =========
</TABLE>
Income taxes are computed by applying the appropriate statutory rate to the
results of operations before income taxes. Applicable tax credits and allowances
related to oil and gas producing activities have been taken into account in
computing income tax expenses. No deduction has been made for indirect cost such
as corporate overhead or interest expense.
80
<PAGE>
SANTA FE ENERGY RESOURCES, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(In Millions)
================================================================================
1998 1997 1996
------- ------- -------
Accounts receivable:
Balance at beginning of period .............. $ 2.7 $ 2.5 $ 2.0
Charge to income ......................... -- 0.5 0.5
Net amounts written off .................. (1.1) (0.3) --
------- ------- -------
Balance at end of period .................... $ 1.6 $ 2.7 $ 2.5
======= ======= =======
81
<PAGE>
INDEX OF EXHIBITS
2(a) -- Agreement and Plan of Merger, dated as of January 13, 1999 between
Snyder Oil Corporation and Santa Fe Energy Resources, Inc. ("SFER,
Inc.") (incorporated by reference to Exhibit 2.1 of the Form S-4
Registration Statement of SFER, Inc., Commission File No. 333-71595).
3(a) -- Restated Certificate of Incorporation (incorporated by reference to
Exhibit 3.1 of the Form S-2 Registration Statement of SFER, Inc.,
Commission File No. 33-32831).
3(b) -- Bylaws, as amended September 1, 1998 (incorporated by reference to
Exhibit 3(a) to SFER, Inc.'s Quarterly Report on form 10-Q for the
quarter ended September 30, 1998).
4(a) -- Rights Agreement dated as of March 3, 1997, between SFER, Inc. and
First Chicago Trust Company of New York, as Rights Agent
(incorporated by reference to Exhibit 1 to SFER, Inc.'s Form 8-A
filed February 28, 1997).
4(b) -- Form of Amended Certificate of Designation of Series A Junior
Participation Preferred Stock of SFER, Inc. (incorporated by
reference to Exhibit 1 to SFER, Inc.'s Form 8-A filed February 28,
1997).
4(c) -- Form of Indenture dated as of May 25, 1994 and Form of Debenture
relating to SFER, Inc.'s 11% Senior Subordinated Debentures due 2004
(incorporated by reference to Exhibit 4.1 of the Form S-3
Registration Statement of SFER, Inc., Commission file No. 33-52849).
4(d) -- First Supplemental Indenture, dated as of October 21, 1996, between
SFER, Inc. and State Street Bank and Trust Company, as Trustee,
relating to SFER, Inc.'s 11% Senior Subordinated Debentures due 2004
(incorporated by reference to Exhibit 10.1 to SFER, Inc.'s Quarterly
Report on Form 10-Q for the quarter ended September 30, 1996).
*10(a) -- SFER, Inc. Incentive Compensation Plan, as amended.
10(b)-- SFER, Inc. 1990 Incentive Stock Compensation Plan, Third Amendment
and Restatement (incorporated by reference to Exhibit 10(a) to SFER,
Inc.'s Quarterly Report on form 10-Q for the quarter ended March
31,1996).
10(c) -- Examples of Employment Agreements entered into with executive
officers of SFER, Inc. (incorporated by reference to Exhibit 10(d) to
SFER, Inc.'s Annual Report on Form 10-K for the year ended December
31, 1996).
10(d) -- Example of Indemnification Agreements with SFER Inc.'s directors and
officers (incorporated by reference to Exhibit 10(b) to SFER, Inc.'s
Annual Report on Form 10-K for the year ended December 31, 1995).
10(e) -- Santa Fe Energy Resources Supplemental Retirement Plan effective as
of December 4, 1990 (incorporated by reference to Exhibit 10(h) to
SFER, Inc.'s Annual Report on Form 10-K for the year ended December
31, 1996).
10(f) -- SFER, Inc. Deferred Compensation Plan, effective as of January 1,
1991 as amended and restated, effective February 1, 1994
(incorporated by reference to Exhibit 10(p) to SFER, Inc.'s Annual
Report on Form 10-K for the year ended December 31, 1993).
82
<PAGE>
10(g) -- Credit Agreement dated as of November 13, 1996 among SFER, Inc., the
banks signatory thereto, and The Chase Manhattan Bank, as
Administrative Agent and ABN AMRO Bank, N.V., as Co-Agent
(incorporated by reference to Exhibit 10(k) to SFER, Inc.'s Annual
Report on Form 10-K for the year ended December 31, 1996).
10(h) -- Agreement for the Allocation of Consolidated Federal Income Tax
Liability and State and Local Taxes among the members of the SFER,
Inc. Affiliated Group dated November 19, 1996 (incorporated by
reference to Exhibit 10.2 to Monterey Resources, Inc.'s (Commission
File No. 1-12311) Annual Report on Form 10-K for the year ended
December 31, 1996).
10(i) -- Agreement Concerning Taxes and Tax Indemnifications upon Spin Off,
dated November 19, 1996, between Monterey Resources, Inc. and SFER,
Inc. (incorporated by reference to Exhibit 10.3 to Monterey
Resources, Inc.'s (Commission File No. 1-12311) Annual Report on Form
10-K for the year ended December 31, 1996).
10(j) -- Agreement Regarding Shelf Registration Statement dated March 24,
1995, between SFER, Inc. and HC Associates, GKH Partners, L.P., GKH
Investments, L.P., Ernest H. Cockrell Texas Testamentary Trust and
Carol Cockrell Jennings Texas Testamentary Trust (incorporated by
reference to Exhibit 10(o) to SFER, Inc.'s Annual Report on Form 10-K
for the year ended December 31, 1995).
10(k) -- Conveyance and Contribution Agreement dated as of November 1, 1996,
between Monterey Resources, Inc. and SFER, Inc. (incorporated by
reference to Monterey Resources, Inc.'s (Commission File No. 1-12311)
Annual Report on Form 10-K for the year ended December 31, 1996).
10(l) -- Agreement and Restated Credit Agreement dated as of May 15, 1998
among SFER, Inc., the banks signatory thereto, and The Chase
Manhattan Bank of Texas, N.A., as Administrative Agent and ABN AMRO
Bank, N.V., Bank of America National Trust and Savings Association,
NationsBank, N.A. and Wells Fargo Bank (Texas) as Co-Agents
(incorporated by reference to Exhibit 10(a) to SFER, Inc.'s Quarterly
Report on Form 10-Q for the quarter ended June 30, 1998).
10(m) -- Agreement and Restated Credit Agreement dated as of October 19, 1998
among SFER, Inc., the banks signatory thereto, and The Chase
Manhattan Bank of Texas, N.A., as Administrative Agent and ABN AMRO
Bank, N.V., Bank of America National Trust and Savings Association,
NationsBank, N.A., Wells Fargo Bank (Texas) and First National Bank
of Chicago as Co-Agents (incorporated by reference to Exhibit 10(a)
to SFER, Inc.'s Quarterly Report on Form 10-Q for the quarter ended
September 30, 1998).
*10(n) -- Agreement and Restated Credit Agreement dated as of December 23, 1998
among SFER, Inc., the banks signatory thereto, and The Chase
Manhattan Bank of Texas, N.A., as Administrative Agent and ABN AMRO
Bank, N.V., Bank of America National Trust and Savings Association,
NationsBank, N.A., Wells Fargo Bank (Texas) and First National Bank
of Chicago as Co-Agents.
*21 -- Subsidiaries of the registrant.
*23(a) -- Consent of PricewaterhouseCoopers LLP
*23(b) -- Consent of Ryder Scott Company
83
<PAGE>
*24 -- Powers of Attorney
* 27 -- Financial Data Schedule
- ------------
* Filed herewith
84
Exhibit 10(a)
SANTA FE ENERGY RESOURCES, INC.
INCENTIVE COMPENSATION PLAN
(AS AMENDED AND RESTATED EFFECTIVE JANUARY 1, 1999)
I. OBJECTIVES
The objectives of the Incentive Compensation Plan (the "Plan") are:
-- To communicate and focus management's attention on significant
business goals.
-- To identify and reward superior performance.
-- To provide a competitive compensation package to attract and
retain high quality key employees.
The Plan is intended to encourage key management to achieve and surpass
Company, group and individual objectives through establishing annual
objectives, reviewing performance and awarding cash bonuses based on the
achievement of such objectives.
The purposes of the Plan are to achieve strong business performance,
equitable compensation and a staff of high quality, motivated key
employees.
II. ADMINISTRATION
The Plan shall be under the direction of the Compensation and Benefits
Committee ("Committee") of the Board of Directors of Santa Fe Energy
Resources, Inc. (the "Company").
However, the responsibility for ensuring that administrative procedures
are established for Plan operation, that the Plan is managed in a timely
and effective manner, and that periodic analyses of the Plan's
effectiveness are undertaken, shall be the duty of a Plan Administrator
appointed by the Committee, who need not be a member of the Committee. The
Plan Administrator shall report his findings, conclusions and
recommendations regarding the Plan's operation and effectiveness to the
Committee from time to time.
The Committee shall have such discretionary authority to administer the
Plan, to construe and interpret the Plan, to decide all questions of
eligibility, to determine the amount, manner and time of payment of any
benefits hereunder and to make all other determinations deemed necessary
or advisable for the administration of the Plan. The attached
Administrative Guidelines have been adopted by the Committee and may be
changed at any time by the Committee in its discretion.
III. ELIGIBILITY
Eligible employees under the Plan are those key employees of the Company
and its subsidiaries who may, have a substantial impact on the operating
performance of the Company and its subsidiaries.
<PAGE>
Employment positions eligible for participation in the Plan each Plan
Year, and the assigned levels of participation for such positions, shall
be determined by the Committee based upon the recommendation of the Plan
Administrator. However, the Committee may modify such recommendations in
any manner it deems appropriate.
IV. INCENTIVE OPPORTUNITIES
The incentive award opportunity with respect to an eligible employment
position shall be designed to reflect the overall impact of the position
on Company performance and to provide a total cash compensation package
for such position that is in line with key competitors of the Company.
V. BASIS FOR DETERMINING THE INCENTIVE AWARD
The incentive award may be based upon a combination of Company, operating
unit and/or individual results, in the Committee's discretion.
The combination of factors, and the respective weights, used in
determining the maximum award for an eligible position will be established
by the Committee on an annual basis. The maximum award with respect to an
eligible position shall be expressed as a percentage (which shall not be
less than 20% nor more than 100%) of the participant's base salary at the
beginning of the Plan year. The percentage applicable to an eligible
position shall be determined by the Committee. A participant's basis of
participation in the Plan will be communicated to him in writing as early
as possible in the Plan year. However, incentive awards may be increased
by up to 25% at the discretion of the Committee or reduced or eliminated
in certain instances pursuant to Article VII and/or VIII.
VI. PERFORMANCE OBJECTIVES
Performance objectives are intended to support the strategic mission of
the Company and shall be: -- Specific and based upon measurable results --
Challenging, but attainable, and -- Tailored to each position.
The basis and amount of the incentive award to be provided for different
levels of performance will be established at the beginning of the Plan
Year for each participating position. A performance schedule for each
specific objective shall be established by the Committee to indicate the
award payable at varying levels of performance. Performance objectives may
be revised at any time by the Committee in light of unanticipated or
extraordinary events.
Specific objectives will be based primarily on the Company's business
plans and competitive levels of performance. For any specific performance
objective, the award payable (as a percent of the maximum) for a given
level of performance will be consistent throughout the Plan.
The Committee will assign objectives, based upon the recommendation of the
Plan Administrator, which are appropriate to the managerial impact of each
participant's position. As appropriate, the individual objectives may
include divisional, district or combined operating unit performance
objectives.
<PAGE>
Performance objectives may include, among others:
-- Pre-tax Income and Cash Flow,
-- Operating Expenses Control,
-- Capital Spending Control,
-- Reserve Additions,
-- "Dry Hole Control",
-- Reservoir Management,
-- Prospect Development, and
-- Land Management.
VII. PERFORMANCE
Performance will be reviewed at appropriate intervals as financial and
operating results are available. At the end of each Plan Year, the
determination of the achievement of the objectives for such Plan Year and
the payment or awards earned will occur as soon as practicable after the
compilation of the year-end financial and operating results. All financial
and operating results will be reviewed by the Controller of the Company
and the achievement of all individual objectives shall be approved by the
President of the Company prior to the recommendation to the Committee of
the payment of awards by the Plan Administrator. The Committee has the
authority to approve all awards recommended for payment.
At the discretion of the Committee, incentive awards, either individually
or collectively, may be increased, decreased, or completely eliminated at
any time during a Plan Year or after the end of the Plan Year but before
payment on the basis of the following considerations:
-- Company performance relative to its competitors,
-- Balancing of long-term versus short-term considerations,
-- Handling of unforeseen opportunities and obstacles, or
-- Individual professional conduct.
VIII. AWARD PAYMENTS
Payment of earned awards will be made as soon as possible after the close
of each Plan Year upon the approval of the Committee. Payments will be
subject to all applicable tax withholding requirements.
If a participant's employment terminates during a Plan Year whether
voluntarily or involuntarily, the participant shall forfeit all rights to
any incentive award for the Plan Year, unless the Committee, in its
discretion, elects to pay all or a portion of the award. If a participant
voluntarily resigns after the Plan Year-end, but before award payout, the
participant shall be entitled to the incentive award payment, if any, he
would be eligible to receive pursuant to Article VII.
In the discretion of the Committee and the election of the participant -
made irrevocably prior to the beginning of the applicable Plan Year - all
or a portion of an incentive award for a Plan Year may be deferred until
termination of employment or immediately prior to termination of
employment. The methods of deferment and subsequent payment shall be
determined by the Committee.
<PAGE>
IX. COMMUNICATIONS
The effectiveness of the Plan depends upon participants fully
understanding the purpose of the Plan, the performance objectives and the
administration of the Plan. It shall be the responsibility of the Plan
Administrator to ensure that all aspects of the Plan are presented to and
understood by the participants
X. CHANGE IN CONTROL
A "Change in Control" shall be deemed to have occurred if:
(i) any "person" (as such term is used in Section 13 (d) and 14 (d) of the
Securities Exchange Act of 1934, as amended (the "Exchange Act")), other
than a trustee or other fiduciary holding securities under an employee
benefit plan of the Company or any affiliate, or any corporation owned,
directly or indirectly, by the stockholders of the Company in
substantially the same proportions as their ownership of stock of the
Company, is or becomes the "beneficial owner" (as defined in Rule 13d-3
under the Exchange Act), directly or indirectly of securities of the
Company representing 25% or more of the combined voting power of the
Company's then outstanding securities;
(ii) during any period of two consecutive years (not including any period
prior to the effective date of the amended and restated Plan),
individuals who at the beginning of such period constitute the Board of
Directors of the Company, and any new director (other than a director
designated by a person who has entered into an agreement with the Company
to effect a transaction described in clause (i), (iii) or (iv) of this
Section) whose election by the Board of Directors of the Company or
nomination for election by the Company's stockholders was approved by a
vote of at least two-thirds of the directors then still in office who
either were directors at the beginning of the period or whose election or
nomination for election was previously so approved (hereinafter referred
to as "Continuing Directors"), cease for any reason to constitute at
least a majority thereof;
(iii) the stockholders of the Company approve a merger or consolidation of
the Company with any other corporation, other than a merger or
consolidation which would result in the voting securities of the Company
outstanding immediately prior thereto continuing to represent (either by
remaining outstanding or by being converted into voting securities of the
surviving entity) more than 65% of the combined voting power of the voting
securities of the Company (or such surviving entity) outstanding
immediately after such merger or consolidation; or
(iv) the stockholders of the Company approve a plan of complete
liquidation of the Company or an agreement for the sale or disposition by
the Company of all or substantially all of the Company's assets. For
purposes of this clause (iv), the term "the sale or disposition by the
Company of all or substantially all of the Company's assets" shall mean a
sale or other disposition transaction or series of related transactions
involving assets of the Company or of any direct or indirect subsidiary of
the Company (including the stock of any direct or indirect subsidiary of
the Company) in which the value of the assets or stock being sold or
otherwise disposed of (as measured by the purchase price being paid
therefor or by such other method as the Board of Directors of the Company
determines is appropriate in a case where there is no readily
ascertainable purchase price) constitutes more than two-thirds of the
"fair market value of the Company" (as hereinafter defined). For purposes
of the
<PAGE>
preceding sentence, the "fair market value of the Company" shall be the
aggregate market value of the Company's outstanding common stock (on a
fully diluted basis) plus the aggregate market value of the Company's
other outstanding equity securities. The aggregate market value of the
Company's common stock shall be determined by multiplying the number of
shares of the Company's common stock (on a fully diluted basis)
outstanding on the date of the execution and delivery of a definitive
agreement with respect to the transaction or series of related
transactions (the "Transaction Date") by the average closing price for the
Company's common stock for the ten trading days immediately preceding the
Transaction Date. The aggregate market value of any other equity
securities of the Company shall be determined in a manner similar to that
prescribed in the immediately preceding sentence for determining the
aggregate market value of the Company's common stock or by such other
method as the Board of Directors of the Company shall determine is
appropriate. However, notwithstanding anything in this clause (iv) to the
contrary, a spinoff or distribution of the stock of a subsidiary of the
Company to those persons who were stockholders of the Company immediately
prior to such spinoff or distribution in substantially the same proportion
as their ownership of Company stock immediately prior to such spinoff or
distribution shall not constitute a "sale or disposition by the Company of
all or substantially all of the Company's assets."
In the event that a Change in Control occurs, the performance objectives
established pursuant to Section V hereof for the year during which the
Change in Control occurred shall be deemed to have been met in full at the
maximum performance level so established, and each participant shall be
entitled to receive a bonus in respect of the year in which such Change in
Control occurs, provided, however, that if a participant's employment is
terminated prior to December 31 of such year, such participant shall be
entitled to a prorated bonus, the amount of which shall be determined by
multiplying the bonus which he would have been entitled had he remained
employed until December 31 by a fraction, the numerator of which is the
number of days in such year through the date of the participant's
termination of employment, and the denominator of which is 365.
XI. TERMINATIONS OR AMENDMENT
The Plan may be terminated or amended at any time by Board of Directors of
the Company.
XII. EFFECTIVE DATE
This Plan was originally effective as of January 1, 1990, and is now
amended and restated as of January 1, 1999.
<PAGE>
ATTACHMENT A
ADMINISTRATIVE GUIDELINES
1. An employees participation in the Plan will be based upon the calendar
months in which the employee held a position eligible for participation
during a Plan Year.
2. The employee must be in an eligible position on the 1st day of the month in
order to participate in the Plan for that month.
3. Except as provided for in the Plan, an employee must be on the active
payroll on the last day of the Plan Year in order to participate for any
portion of that year.
4. If a participant transfers between eligible positions under the Plan during
the Plan Year his/her participation will be based on full months of
participation in each position at the participation levels established for
each position.
5. New hires or employees who first assume an eligible position on October 1st
or later in a given Plan Year are not eligible for participation in that
Plan Year.
6. Nothing contained in these Administrative Guidelines will take precedence
over specific decisions rendered by the Committee concerning eligibility,
participation, or other Plan administration policies and practices.
Exhibit 10(n)
AGREEMENT AND FOURTH AMENDMENT
TO CREDIT AGREEMENT
(December 23, 1998)
THIS AGREEMENT AND FOURTH AMENDMENT TO CREDIT AGREEMENT (this
"Agreement"), dated as of December 23, 1998, is made and entered into by and
among SANTA FE ENERGY RESOURCES, INC. (the "COMPANY"), a Delaware corporation;
the financial institutions listed on the signature pages hereto (collectively,
the "BANKS"); and CHASE BANK OF TEXAS, NATIONAL ASSOCIATION ("CHASE TEXAS"),
acting in its capacity as agent for the Banks (in such capacity, the "AGENT").
The Company, the Banks and the Agent are herein sometimes called the "PARTIES".
RECITALS:
1. The Company, the Agent then acting, and certain of the Parties entered
into a Credit Agreement dated as of November 13, 1996, an Agreement and First
Amendment to Credit Agreement dated as of December 19, 1996, an Agreement and
Second Amendment to Credit Agreement dated as of May 15, 1998, and an Agreement
and Third Amendment to Credit Agreement dated as of October 19, 1998. Such
Credit Agreement, as so amended, is herein called the "CREDIT AGREEMENT".
2. The Parties desire to amend the Credit Agreement to define a new term,
"EBITDAX", to substitute "EBITDAX" for the terms "EBITDA" and "Adjusted EBITDA"
in the financial covenants contained in SECTIONS 9.10 and 9.11 of the Credit
Agreement (but not elsewhere), and to ratify, confirm and continue the Credit
Agreement as so amended.
AGREEMENTS:
NOW, THEREFORE, in consideration of the premises and for other good and
valuable consideration, the receipt and sufficiency of which are acknowledged by
the Parties, the Parties agree as follows:
1. ADDITIONAL DEFINITIONS. There is hereby added to SECTION
1.1 of the Credit Agreement the following definitions:
""EBITDAX"" shall mean for any period Consolidated Net Earnings for
such period (calculated, for purposes of this definition only, without
taking into account extraordinary items under GAAP or capital gains or
capital losses), plus the aggregate amounts deducted in determining
Consolidated Net Earnings in respect of (a) all provisions for any
federal, state or other income taxes made by the Company and the
Restricted Subsidiaries during such period; (b) Fixed Charges of the
Company and the Restricted Subsidiaries during such period; (c)
depreciation, depletion and amortization charges of the Company and the
Restricted Subsidiaries for such period; (d) exploration expenses of the
Company and the
<PAGE>
Restricted Subsidiaries for such period, and (e) all other non-cash
charges of the Company and the Restricted Subsidiaries for such period,
all determined in accordance with GAAP."
2. AMENDMENT OF SECTION 9.10. SECTION 9.10 of the Credit Agreement is
hereby amended to provide in its entirety as follows:
"9.10. INTEREST COVERAGE. The Company will not permit the ratio of
(a) EBITDAX for the four fiscal quarters then most recently ended to (b)
Fixed Charges on Total Debt of the Combined Group for that period to be
less than 3.00 to 1.00."
3. AMENDMENT OF SECTION 9.11. SECTION 9.11 of the Credit Agreement is
hereby amended to provide in its entirety as follows:
"9.11. SENIOR TOTAL DEBT; SPECIAL DEBT. The Company will not at any
time create, incur, assume or suffer to exist any Total Debt of the
Combined Group PARI PASSU with the Obligations other than such Total Debt
of the Combined Group which does not at any time exceed the product of (a)
3.00 times (b) EBITDAX for the four consecutive fiscal quarters then most
recently ended. The Company will not at any time create, incur, assume or
suffer to exist any Special Debt that would cause the aggregate principal
amount of Special Debt to exceed 15% of Consolidated Net Worth."
4. CONDITIONS PRECEDENT. This Agreement shall become effective on the date
(the "EFFECTIVE DATE") that each of the following conditions shall have been
satisfied or waived in the discretion of the Agent:
(a) INCUMBENCY. The Company shall have delivered to the Agent a
certificate in respect of the name and signature of each officer who (i)
is authorized to sign on its behalf this Agreement and (ii) will, until
replaced by another officer or officers duly authorized for that purpose,
act as its representative for the purposes of signing documents and giving
notices and other communications in connection with this Agreement. The
Agent and each Bank may conclusively rely on such certificates until they
receive notice in writing from the Company to the contrary.
(b) CREDIT DOCUMENTS; EXPENSES. The Company shall have duly executed
and delivered this Agreement, which shall be in substantially the form
furnished to the Banks prior to their execution of this Agreement,
together with such changes therein as the Agent may approve in its
discretion. The Company shall have paid to the Agent all fees and expenses
in the amounts previously agreed upon in writing among the Company and the
Agent and all amounts due under SECTION 8.
<PAGE>
(c) COUNTERPARTS. The Agent shall have received counterparts of
this Agreement duly executed and delivered by or on behalf of each of the
parties thereto (or, in the case of any Bank as to which the Agent shall
not have received such a counterpart, the Agent shall have received
evidence satisfactory to it of the execution and delivery by such Bank of
a counterpart hereof).
(d) CONSENTS. The Agent shall have received evidence satisfactory to
it in its discretion that all consents of each Governmental Authority and
of each other Person, if any, required in connection with the execution,
delivery and performance of this Agreement have been received and remain
in full force and effect.
(e) OTHER DOCUMENTS. The Agent shall have received such other
documents consistent with the terms of this Agreement and relating to the
transactions contemplated hereby as the Agent may reasonably request.
(f) NO DEFAULT. No Default shall have occurred and be continuing.
(g) NO LEGAL BAR. Such effectiveness shall not violate any Legal
Requirement applicable to the Agent or any Bank.
PROVIDED, HOWEVER, that this Agreement shall not become effective or be binding
on any Party unless all of the foregoing conditions are satisfied not later than
December 31, 1998. The Agent shall promptly notify the Company and the Banks of
the Effective Date, and such notice shall be conclusive and binding on all
Parties. All provisions and payments required by this SECTION 4 are subject to
the provisions of SECTION 12.8 of the Credit Agreement.
5. REPRESENTATIONS TRUE; NO DEFAULT. The Company represents and warrants
to the Agent and each Bank that (a) the representations and warranties contained
in the Credit Agreement are true and correct on and as of the date hereof as
though made on and as of such date (except to the extent such representations
and warranties are expressly stated to be made solely as of an earlier date) and
(b) no event has occurred and is continuing which constitutes a Default under
the Credit Agreement or which upon the giving of notice or the lapse of time or
both would constitute such a Default.
6. RATIFICATION. Except as expressly amended hereby, the Credit Agreement,
as hereby amended, is in all respects ratified, confirmed and continued as the
agreement of the Parties and is, and shall continue to be, in full force and
effect and binding upon the Parties. The Company hereby agrees and acknowledges
that all of its liabilities and obligations under the Credit Agreement, as
hereby amended, remain in full force and effect and binding upon it as of the
date of this Agreement.
7. DEFINITIONS AND REFERENCES. Unless otherwise defined herein, terms used
herein which are defined in the Credit Agreement shall have the meanings therein
ascribed to them. The term "Agreement" as used in the Credit Agreement and the
term "Credit Agreement" as used in this Agreement or in any other instrument,
document or writing furnished to the Agent or any Bank by or on behalf of the
Company shall mean the Credit Agreement as hereby amended.
<PAGE>
8. EXPENSES; ADDITIONAL INFORMATION. The Company shall pay to the Agent on
demand (i) all out-of-pocket expenses (including fees and disbursements of
special counsel to the Agent and expenses of syndication) in connection with the
preparation and administration of this Agreement, any waiver or consent
hereunder and any amendment hereof, and (ii) if an Event of Default occurs, all
out-of-pocket expenses incurred by the Agent and each Bank, including fees and
disbursements of counsel, in connection with such Event of Default and
collection, bankruptcy, insolvency and other enforcement proceedings resulting
therefrom.
9. SEVERABILITY. If any term or provision of this Agreement or the
application thereof to any person or circumstances shall, to any extent, be
deemed invalid or unenforceable, the remainder of this Agreement, or the
application of such term or provision to persons or circumstances other than
those as to which it is held invalid or unenforceable, shall not be affected
thereby and this Agreement shall be valid and enforced to the fullest extent
permitted by applicable law. Any provision of this Agreement which is prohibited
or unenforceable in any jurisdiction shall, as to such jurisdiction, be
ineffective to the extent of such prohibition or unenforceability without
invalidating the remaining portions thereof or affecting the validity or
enforceability of such provision in any other jurisdiction and, to this end, the
provisions of this Agreement are severable.
10. MISCELLANEOUS. This Agreement (a) shall be binding upon and inure to
the benefit of the Company, the Agent and the Banks and their respective
successors and assigns (however, the Company may not assign its rights hereunder
without the express prior written consent of all Banks); (b) may be modified or
amended only in the manner prescribed for amendments to the Credit Agreement in
SECTION 12.5 of the Credit Agreement; (c) SHALL BE GOVERNED BY AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS (TO THE EXTENT PERMITTED BY LAW,
OTHER THAN ITS CONFLICT OF LAW RULES) AND OF THE UNITED STATES OF AMERICA; (d)
may be executed in several counterparts, and by the Parties on separate
counterparts, and each counterpart, when so executed and delivered, shall
constitute an original agreement, and all such separate counterparts shall
constitute but one and the same agreement, and (e) embodies the entire agreement
and understanding among the Parties with respect to the subject matter hereof
and supersedes all prior agreements, consents and understandings relating to
such subject matter. The headings herein shall be accorded no significance in
interpreting this Agreement.
11. THIS AGREEMENT REPRESENTS THE FINAL AGREEMENT AMONG THE PARTIES AS TO
THE SUBJECT MATTER HEREOF AND THEREOF AND MAY NOT BE CONTRADICTED BY EVIDENCE OF
PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE
NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.
<PAGE>
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed
by their respective duly authorized officers effective as of the date provided
herein.
SANTA FE ENERGY RESOURCES, INC.
By:______________________________
Janet F. Clark
Senior Vice President-Finance
Chief Financial Officer and Treasurer
<PAGE>
CHASE BANK OF TEXAS, NATIONAL
ASSOCIATION, individually and as
Administrative Agent
By:__________________________________
Name:________________________________
Title:_______________________________
<PAGE>
ABN AMRO BANK N.V.,
Individually and as a Co-Agent
By:__________________________________
Name:________________________________
Title:_______________________________
By:__________________________________
Name:________________________________
Title:_______________________________
<PAGE>
BANK OF AMERICA NATIONAL TRUST AND
SAVINGS ASSOCIATION,
Individually and as a Co-Agent
By:__________________________________
Name:________________________________
Title:_______________________________
<PAGE>
THE FIRST NATIONAL BANK OF CHICAGO,
Individually and as a Co-Agent
By:__________________________________
Name:________________________________
Title:_______________________________
<PAGE>
NATIONSBANK, N.A.(successor by merger to
NationsBank of Texas, N.A.), Individually
and as a Co-Agent
By:__________________________________
Name:________________________________
Title:_______________________________
<PAGE>
WELLS FARGO BANK (TEXAS), N.A.,
Individually and as a Co-Agent
By:__________________________________
Name:________________________________
Title:_______________________________
<PAGE>
BANK OF MONTREAL
By:__________________________________
Name:________________________________
Title:_______________________________
<PAGE>
PNC BANK, NATIONAL ASSOCIATION
By:__________________________________
Name:________________________________
Title:_______________________________
<PAGE>
COMERICA BANK - TEXAS
By:__________________________________
Name:________________________________
Title:_______________________________
Exhibit 21
SUBSIDIARIES OF THE REGISTRANT
Santa Fe Energy Resources, Inc. ("SFER") has 33 wholly-owned active
subsidiaries, which are involved in the exploration for and development and
production of crude oil and natural gas. Six subsidiaries conduct operations in
the United States and 27 subsidiaries conduct operations in foreign areas.
Exhibit 23(a)
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-8 (Nos. 33-37175, 33-44541, 33-44542, 33-58613, 33-59253,
33-59255, 333-07949, 333-34135, 333-34161, 333-34165, 333-47847 and 333-63711)
and Form S-4 (No. 333-71595) of Santa Fe Energy Resources, Inc. of our report
dated March 1, 1999 appearing on page 51 of this Form 10-K.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 5, 1999
Exhibit 23(b)
CONSENT OF EXPERTS
As petroleum engineers, we hereby consent to the incorporation by
reference in the Registration Statements on Form S-8 (Nos. 33-37175, 33-44541,
33-44542, 33-58613, 33-59253, 33-59255, 333-07949, 333-34135, 333-34161,
333-34165, 333-47847 and 333-63711) and Form S-4 (No. 333-71595) of our oil and
gas reserve reports as of December 31, 1994, December 31, 1995, December 31,
1996, December 31, 1997 and December 31, 1998 included in the Santa Fe Energy
Resources, Inc. Form 10-K for the year ended December 31, 1998.
Ryder Scott Company
Petroleum Engineers
March 3, 1999
Exhibit 24
POWER OF ATTORNEY
Know all men by these presents that W. E. GREEHEY constitutes and appoints
J. L. PAYNE, JANET F. CLARK and DAVID L. HICKS and each or any of them, as his
true and lawful attorneys-in-fact and agents, with full power of substitution,
for him and in his name, place and stead, in any and all capacities to sign in
his name to the Annual Report on Form 10-K of SANTA FE ENERGY RESOURCES, INC.
for the fiscal year ended December 31, 1998 and to file the same, and with all
exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorneys-in-fact and
agents full power and authority to do and perform each and every act and thing
requisite and necessary to be done in and about the premises, as fully to all
intents and purposes as he might or could do in person, hereby ratifying and
confirming all that said attorneys-in-fact and agents, or any of them or their
substitutes may lawfully do or cause to be done by virtue hereof.
Dated March 1, 1999
________________________________
W. E. Greehey
<PAGE>
POWER OF ATTORNEY
Know all men by these presents that M. N. KLEIN constitutes and appoints
J. L. PAYNE, JANET F. CLARK and DAVID L. HICKS and each or any of them, as his
true and lawful attorneys-in-fact and agents, with full power of substitution,
for him and in his name, place and stead, in any and all capacities to sign in
his name to the Annual Report on Form 10-K of SANTA FE ENERGY RESOURCES, INC.
for the fiscal year ended December 31, 1998 and to file the same, and with all
exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorneys-in-fact and
agents full power and authority to do and perform each and every act and thing
requisite and necessary to be done in and about the premises, as fully to all
intents and purposes as he might or could do in person, hereby ratifying and
confirming all that said attorneys-in-fact and agents, or any of them or their
substitutes may lawfully do or cause to be done by virtue hereof.
Dated March 1, 1999
________________________________
M. N. Klein
<PAGE>
POWER OF ATTORNEY
Know all men by these presents that A. V. MARTINI constitutes and appoints
J. L. PAYNE, JANET F. CLARK and DAVID L. HICKS and each or any of them, as his
true and lawful attorneys-in-fact and agents, with full power of substitution,
for him and in his name, place and stead, in any and all capacities to sign in
his name to the Annual Report on Form 10-K of SANTA FE ENERGY RESOURCES, INC.
for the fiscal year ended December 31, 1998 and to file the same, and with all
exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorneys-in-fact and
agents full power and authority to do and perform each and every act and thing
requisite and necessary to be done in and about the premises, as fully to all
intents and purposes as he might or could do in person, hereby ratifying and
confirming all that said attorneys-in-fact and agents, or any of them or their
substitutes may lawfully do or cause to be done by virtue hereof.
Dated March 1, 1999
________________________________
A. V. Martini
<PAGE>
POWER OF ATTORNEY
Know all men by these presents that R. F. RICHARDS constitutes and
appoints J. L. PAYNE, JANET F. CLARK and DAVID L. HICKS and each or any of them,
as his true and lawful attorneys-in-fact and agents, with full power of
substitution, for him and in his name, place and stead, in any and all
capacities to sign in his name to the Annual Report on Form 10-K of SANTA FE
ENERGY RESOURCES, INC. for the fiscal year ended December 31, 1998 and to file
the same, and with all exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents full power and authority to do and perform each and
every act and thing requisite and necessary to be done in and about the
premises, as fully to all intents and purposes as he might or could do in
person, hereby ratifying and confirming all that said attorneys-in-fact and
agents, or any of them or their substitutes may lawfully do or cause to be done
by virtue hereof.
Dated March 1, 1999
________________________________
R. F. Richards
<PAGE>
POWER OF ATTORNEY
Know all men by these presents that K. D. WRISTON constitutes and appoints
J. L. PAYNE, JANET F. CLARK and DAVID L. HICKS and each or any of them, as his
true and lawful attorneys-in-fact and agents, with full power of substitution,
for him and in his name, place and stead, in any and all capacities to sign in
his name to the Annual Report on Form 10-K of SANTA FE ENERGY RESOURCES, INC.
for the fiscal year ended December 31, 1998 and to file the same, and with all
exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorneys-in-fact and
agents full power and authority to do and perform each and every act and thing
requisite and necessary to be done in and about the premises, as fully to all
intents and purposes as he might or could do in person, hereby ratifying and
confirming all that said attorneys-in-fact and agents, or any of them or their
substitutes may lawfully do or cause to be done by virtue hereof.
Dated March 1, 1999
________________________________
K. D. Wriston
<PAGE>
POWER OF ATTORNEY
Know all men by these presents that J. L. PAYNE constitutes and appoints
JANET F. CLARK and DAVID L. HICKS and each or any of them, as his true and
lawful attorneys-in-fact and agents, with full power of substitution, for him
and in his name, place and stead, in any and all capacities to sign in his name
to the Annual Report on Form 10-K of SANTA FE ENERGY RESOURCES, INC. for the
fiscal year ended December 31, 1998 and to file the same, and with all exhibits
thereto and other documents in connection therewith, with the Securities and
Exchange Commission, granting unto said attorneys-in-fact and agents full power
and authority to do and perform each and every act and thing requisite and
necessary to be done in and about the premises, as fully to all intents and
purposes as he might or could do in person, hereby ratifying and confirming all
that said attorneys-in-fact and agents, or any of them or their substitutes may
lawfully do or cause to be done by virtue hereof.
Dated March 1, 1999
________________________________
J. L. Payne
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