SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1993
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from to
Commission file number 1-8876
Enserch Exploration Partners, Ltd.
Texas 75-2017566
(State or other jurisdiction of ( I.R.S. Identification No.)
incorporation or organization)
1817 Wood Street, Dallas, Texas 75201
(Address of principal executive office)
Registrant's Telephone Number, Including Area Code - (214) 748-1110
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of Each Exchange
Title of Each Class on which Registered
--------------------------------------- ----------------------------
Depositary Units Evidenced by New York Stock Exchange
Depositary Receipts
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
None
Indicate by check mark whether 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 twelve 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
---- ----
Aggregate market value of the Depositary Units evidenced by Depositary Receipts
of the Registrant held by nonaffiliates as of March 9, 1994 - $5,641,398.
Number of Depositary Units evidenced by Depositary Receipts of the Registrant
outstanding as of March 9, 1994: 805,914.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. (X)
DOCUMENTS INCORPORATED BY REFERENCE: NONE
FORM 10-K
ANNUAL REPORT
For the Fiscal Year Ended December 31, 1993
TABLE OF CONTENTS
Page
PART I
ITEM 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 1
Competition. . . . . . . . . . . . . . . . . . . . . . . . . .. 3
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . .. 3
ITEM 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . .. 4
ITEM 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . .. 8
ITEM 4. Submission of Matters to a Vote of Security Holders. . . . . . .. 8
PART II
ITEM 5. Market for the Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . .. 8
ITEM 6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . .. 8
ITEM 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. . . . . . . . . . . . . .. 8
ITEM 8. Financial Statements and Supplementary Data. . . . . . . . . . .. 8
ITEM 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure. . . . . . . . . . . . . .. 8
PART III
ITEM 10. Directors and Executive Officers of the Registrant . . . . . . .. 9
ITEM 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . .. 11
ITEM 12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . . . .. 11
ITEM 13. Certain Relationships and Related Transactions . . . . . . . . .. 11
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . .. 12
APPENDIX A Financial Information . . . . . . . . . . . . . . . . . . . . A-1
APPENDIX B Financial Statement Schedules . . . . . . . . . . . . . . . . B-1
PART I
ITEM 1. Business
Enserch Exploration Partners, Ltd. ("EP"), a Texas limited partnership,
was formed in 1985 to succeed to substantially all of the domestic gas and oil
exploration and production business of ENSERCH Corporation ("ENSERCH").
ENSERCH and an affiliate own more than 99% of the outstanding limited
partnership units and the remaining units of slightly more than 800,000, are
publicly held.
EP operates through EP Operating Limited Partnership ("EPO"), a Texas
limited partnership, in which EP holds a 99% limited partner's interest and
the general partners own a 1% interest. Enserch Exploration, Inc. ("EEI") is
the managing general partner and ENSERCH is the special general partner of EP
and EPO.
EP is engaged in the exploration for and the development, production and
marketing of natural gas and crude oil throughout Texas, offshore in the Gulf
of Mexico, onshore in the Gulf Coast and Rocky Mountain areas and in various
other areas in the United States. Activities include geological and
geophysical studies; acquisition of gas and oil leases; drilling of exploratory
wells; development and operation of producing properties; acquisition of
interests in developed or partially developed properties; and the marketing of
natural gas, crude oil and condensate. Production offices are maintained in
Dallas, Houston, Athens, Bridgeport, Longview and Midland, Texas.
EP has no officers, directors or employees. Instead, officers, directors
and employees of EEI perform all management and operating functions for EP.
At December 31, 1993, EEI employed 382 persons, including 36 geologists, 21
geophysicists and 19 land representatives who investigate prospective areas,
generate drilling prospects, review submitted prospects and acquire leasehold
acreage in prospective areas. In addition, EEI maintains a staff of 56
engineers and 46 technologists who plan and supervise the drilling and
completion of wells, evaluate prospective gas and oil reservoirs, plan the
development and management of fields, and manage the daily production of gas
and oil.
Spot-market sales, which include monthly and short-term industrial sales,
covered about 70% of 1993 gas sales, compared with 80% in 1992 and 75% in 1991.
During 1994, the percentage of gas sold in the spot market is expected to be
in the range of 75% to 85%. Approximately 70% of EP's natural-gas sales
volumes (75% of gas revenues) for the year ended December 31, 1993 was sold to
affiliated customers. In 1993, affiliated revenues include gas sales under new
contracts effective March 1, 1993 with Enserch Gas Company covering essentially
all gas production not committed under existing contracts. Affiliated
purchasers do not have a preferential right to purchase natural gas produced
by EP other than under existing contracts.
Sales data are set forth under "Selected Financial and Operating Data" in
Appendix A to this report.
Following is a summary of EP's exploration and development activity during
1993:
1
Gulf of Mexico. Offshore exploration provides EP the opportunity to
improve its ratio of production to reserve base by the addition of gas wells
with relatively higher production rates. This is coupled with ongoing deep-
water development projects, which are expected to provide long-term reserves.
State-of-the-art technology, including three-dimensional ("3-D") seismic,
specialized seismic processing, and innovative well completion and production
techniques, are being used to help accomplish these objectives.
Mississippi Canyon Block 441, the first development project in the Gulf
of Mexico that EP has operated, is indicative of this approach. A 3-D seismic
program, prior to field development, confirmed that the majority of the
reservoir lies beneath a shipping fairway. A production program was developed
that involved drilling highly deviated wells under the shipping fairway, subsea
completing the deep-water wells, and tying the wells back to a conventional
shallow-water production platform using bundled flowlines. The high-angle
wells required special gravel-pack completion techniques. After a year of
production, the field has been essentially maintenance free, producing some 70
million cubic feet ("MMcf") of natural gas and more than 500 barrels ("Bbls")
of condensate per day from six wells.
The 3-D seismic on Mississippi Canyon Block 441 is being reprocessed,
using depth migration and other state-of-the-art techniques to aid in the
identification of deeper exploratory targets, which, if successfully drilled,
could add to the field reserves. EP has a 37.5% working interest in this
project.
The Garden Banks Block 388 oil development project remains on schedule,
with initial production anticipated by mid-1995. Installation of the offshore
facilities, which consist of a subsea template, gathering and sales pipelines,
and shallow-water production facilities, will begin by mid-1994. After the rig
and all facilities are in place, the three existing wells will be connected,
with initial production from the first well expected to be approximately 5
thousand barrels ("MBbls") of oil and 5 MMcf of gas per day. Peak daily
production from the project is anticipated to be 40 MBbls of oil and 60 MMcf
of gas. EP is 100% owner and operator of the Garden Banks Block 388 project.
Another prospect delineated by seismic amplitude anomalies lies
approximately four miles to the west of Garden Banks Block 388 on Garden Banks
Blocks 386/387. If successfully drilled, this prospect could add production
to the Block 388 development by incorporating some of the production technology
that was utilized on Mississippi Canyon Block 441.
In 1994, an offset well to EP's discovery on Green Canyon Block 254 is
scheduled to be drilled. The exploratory well, which was drilled in 1991,
encountered 11 sands with a combined thickness of more than 360 feet of oil
pay. EP has a 25% working interest in this block and a similar working
interest in three adjacent blocks believed to be part of the same project.
Onshore. EP participated in 78 development wells (62 net) in 1993, with
the majority completed as gas producers in East Texas. Thirty-six wells were
in progress at yearend. In East Texas, EP is positioned in a prolific gas-
prone area which, despite its maturity, provides growth opportunities. EP is
one of the oldest and most active operators in this basin in East Texas, which
includes Opelika, Tri-Cities, Whelan, Willow Springs, North Lansing and
Freestone fields.
2
In early 1993, EP initiated a 26-well program in East Texas to accelerate
the development of natural-gas reserves from the Travis Peak formation in the
Opelika field. The program was targeted to test new techniques for shortening
the average life of its reserve base. The project was completed in seven
months yielding initial daily per well production rates of up to 1.8 MMcf of
gas and 48 Bbls of oil. EP has a 100% working interest in these wells.
EP performed additional development drilling in the Freestone field,
where seven well completions flowed at daily rates ranging from 1.0 MMcf to
2.3 MMcf of gas per well. EP has 50% to 100% working interests in these wells.
In the Bralley field in West Texas, the combined daily oil production
rate from six wells increased to 800 Bbls from 500 Bbls following production
optimization work. EP owns a 50% working interest in each of these wells.
In South Texas, seven wells drilled and completed in the Fashing field
flowed at daily rates of 1.2 MMcf to 2.6 MMcf of gas and 14 Bbls to 30 Bbls of
oil per well. Twelve wells drilled and completed in the Boonsville field in
north central Texas resulted in daily production of .4 MMcf to 1.5 MMcf of gas
per well.
Onshore development activity planned for 1994 includes drilling
approximately 35 wells outside East Texas. Some of the larger projects include
wells in the Fashing, Rancho Viejo and Boonsville fields.
In the Fashing field, results of three wells and a field study indicate
development potential for new wells, as well as recompletions that could result
in reserve additions.
Competition
Competition in the natural gas and oil exploration and production business
is intense and is present from a large number of firms of varying sizes and
financial resources, some of which are much larger than EP. Competition
involves all aspects of marketing products (including terms, prices, volumes
and length of contracts), terms relating to lease bonus and royalty
arrangements, and the schedule of future development activity.
Regulation
Environmental Protection Agency ("EPA") rules, regulations and orders
affect the operations of EP. EPA regulations promulgated under the Superfund
Amendments and Reauthorization Act of 1986 require EP to report on locations
and estimates of quantities of hazardous chemicals used in EP's operations.
The EPA has determined that most gas and oil exploration and production wastes
are exempt from the hazardous waste management requirements of the Resource
Conservation Recovery Act. However, the EPA determined that certain
exploration and production wastes resulting from the maintenance of production
equipment and transportation are not exempt, and these wastes must be managed
and disposed of as hazardous waste. Also, regulations issued by the EPA under
the Clean Water Act require a permit for "contaminated" stormwater discharges
from exploration and production facilities.
3
Many states have issued new regulations under authority of the Clean Air
Act Amendments of 1990, and such regulations are in the process of being
implemented. These regulations may require certain gas and oil related
installations to obtain federally enforceable operating permits and may require
the monitoring of emissions; however, the impact of these regulations on EP is
expected to be minor.
Several states have adopted regulations on the handling, transportation,
storage, and disposal of naturally occurring radioactive materials that are
found in gas and oil operations. Although applicable to certain EP facilities,
it is not believed that such regulations will materially impact current or
future operations.
In the aggregate, compliance with federal and state environmental rules
and regulations is not expected to have a material effect on EP's operations.
The Railroad Commission of Texas ("RRC") regulates the production of
natural gas and oil by EP in Texas. Similar regulations are in effect in all
states in which EP explores for and produces natural gas and oil. These
regulations generally require permits for the drilling of gas and oil wells and
regulate the spacing of the wells, the prevention of waste, the rate of
production, and the prevention and cleanup of pollution and other materials.
ITEM 2. Properties
The following table sets forth a summary of certain information relating
to EP's gas and oil properties:
At December 31
---------------------------------------------
1993 1992 1991 1990 1989
------- ------- ------- ------- ------
Total Proved Developed and
Undeveloped Reserves:
Gas (Bcf)(1). . . . . . . . . . . . . . . . . . . . . . . 1,085.5 1,100.4 1,167.3 1,223.2 1,221.3
Oil (MMBbl)(1)(2) . . . . . . . . . . . . . . . . . . . . 38.2 37.9 38.0 28.7 23.1
Estimated Future Net Cash Flows
from Proved Reserves
(in millions) . . . . . . . . . . . . . . . . . . . . . . $1,988.8 $2,017.1 $2,061.1 $2,606.8 $2,299.9
Present Value of Future Net Cash
Flows from Proved Reserves
(before income taxes and
discounted at 10% per annum)
(in millions) . . . . . . . . . . . . . . . . . . . . . . $1,102.4 $1,108.4 $1,060.4 $1,229.3 $1,089.3
- -------------
<FN>
Note: Billion cubic feet ("Bcf"), million barrels ("MMBbl").
(1) Estimated by DeGolyer and MacNaughton, independent petroleum consultants.
(2) Includes oil, condensate and natural gas liquids attributable to leasehold
interests.
The 1994 capital spending budget has been set at $114 million, about the
same as 1993 actual capital expenditures. More than half of the 1994 capital
expenditures is earmarked for domestic onshore drilling. The exploration
program includes a balanced mix of projects with regard to reserve potential
4
and risk, focusing on as many core area opportunities as possible. See
"Financial Review - Capital Resources and Liquidity" included in Appendix A
to this report.
During 1993, Enserch Exploration filed Form EIA-23 with the Department of
Energy reflecting reserve estimates for the year 1992. Such reserve estimates
were not materially different from the 1992 reserve estimates reported in Note
7 of the Notes to Consolidated Financial Statements included in Appendix A to
this report.
A summary of EP's average sales prices, average production costs and
amortization are set forth under "Selected Financial and Operating Data"
included in Appendix A to this report.
EP owned leasehold interests or licenses in 17 states and offshore Texas
and Louisiana, as of December 31, 1993, as follows:
Gross Acres Net Acres (1)
------------------------------ ------------------------------
Developed Undeveloped Total Developed Undeveloped Total
--------- ----------- ----- --------- ----------- -------
Alabama . . . . . . . . . . . 2,797 1,536 4,333 1,952 1,642 3,594
Arkansas. . . . . . . . . . . 16 10,550 10,566 16 5,783 5,799
Colorado. . . . . . . . . . . 11,812 23,746 35,558 4,127 15,133 19,260
Idaho . . . . . . . . . . . . - 14,730 14,730 - 14,730 14,730
Kansas. . . . . . . . . . . . 560 14,950 15,510 360 8,267 8,627
Louisiana . . . . . . . . . . 4,025 29,510 33,535 1,218 18,254 19,472
Mississippi . . . . . . . . . 6,245 42,436 48,681 3,099 14,317 17,416
Montana . . . . . . . . . . . 6,135 49,825 55,960 3,237 34,168 37,405
Nebraska. . . . . . . . . . . 160 480 640 160 480 640
Nevada. . . . . . . . . . . . - 38,633 38,633 - 27,916 27,916
New Mexico. . . . . . . . . . 2,680 5,907 8,587 1,902 4,276 6,178
North Dakota. . . . . . . . . 1,560 10,421 11,981 1,246 6,233 7,479
Ohio. . . . . . . . . . . . . 102 14,950 15,052 - - -
Oklahoma. . . . . . . . . . . 37,022 23,915 60,937 20,323 9,615 29,938
Texas . . . . . . . . . . . . 281,955 453,221 735,176 211,768 163,651 375,419
Utah. . . . . . . . . . . . . 3,719 109,742 113,461 533 54,081 54,614
Wyoming . . . . . . . . . . . 4,079 49,947 54,026 1,846 43,358 45,204
U. S. Offshore. . . . . . . . 51,927 320,689 372,616 8,459 114,674 123,133
------- --------- --------- ------- ------- -------
Total . . . . . . . . . . . 414,794 1,215,188 1,629,982 260,246 536,578 796,824
======= ========= ========= ======= ======= =======
- ------------
<FN>
(1) Represents the proportionate interest of EP in the gross acres under
lease.
EP purchased about 220,000 net acres of leasehold interests in 1993,
26,000 of which were in the Gulf of Mexico. EP's Gulf of Mexico holdings
totaled some 123,000 net acres, with an average working interest of 36% in 64
leases covering 65 blocks and an overriding royalty interest in six other
leases. EP operates 23 leases covering 24 offshore blocks. EP also canceled,
or allowed to expire, eight Gulf of Mexico leases during the year. These leases
had been condemned following drilling on or near them or after geophysical and
geological findings.
5
EP plans further drilling on undeveloped acreage but at this time cannot
specify the extent of the drilling or predict how successful it will be in
establishing commercial reserves sufficient to justify retention of the
acreage. The primary terms under which the undeveloped acreage can be retained
by the payment of delay rentals without the establishment of gas and oil
reserves expire 30% in 1994, 17% in 1995, 25% in 1996, 13% in 1997, 4% in 1998,
1% in 1999 and 10% thereafter. A portion of the undeveloped acreage may be
allowed to expire prior to the expiration of primary terms specified in this
schedule by nonpayment of delay rentals. Aside from Texas and the Gulf of
Mexico, EP has no material concentration of undeveloped acreage in single areas
at this time.
EP participated in 109 wells (79 net) during 1993. Of these wells, 83 (64
net) were successfully completed, resulting in a net success rate of 81%. Of
the successful wells, 7 wells (4 net) were exploratory and 76 wells (60 net)
were development. At December 31, 1993, EP was participating in 36 wells
(20 net), which were either being drilled or in some stage of completion.
In the 1993 drilling program, 16 wells (4.9 net) were offshore. Of these
wells, 9 (2.6 net) gas wells and 1 (.1 net) oil well were successfully
completed. During 1992, 4 (1.6 net) offshore wells were drilled of which 2
(.8 net) gas wells were successfully completed.
At December 31, 1993, EP owned working interests in 1,303 (980 net) gas
wells and 1,121 (277 net) oil wells. Of these, 173 (141 net) gas wells and 37
(32 net) oil wells were dual completions in single boreholes.
6
Drilling activity for each of the years 1993, 1992 and 1991 is set forth
below:
Exploratory Development
Drilling Drilling
----------- -----------
Productive Wells
----------------
1993:
Gross Wells. . . . . . . . . . 7.0 76.0
Net Wells. . . . . . . . . . . 3.8 60.1
1992:
Gross Wells. . . . . . . . . . 3.0 12.0
Net Wells. . . . . . . . . . . 2.2 6.3
1991:
Gross Wells. . . . . . . . . . 11.0 54.0
Net Wells. . . . . . . . . . . 5.9 46.2
Nonproductive Wells
-------------------
1993:
Gross Wells. . . . . . . . . . 24.0 2.0
Net Wells. . . . . . . . . . . 13.0 1.8
1992:
Gross Wells. . . . . . . . . . 13.0 5.0
Net Wells. . . . . . . . . . . 8.1 2.6
1991:
Gross Wells. . . . . . . . . . 15.0 10.0
Net Wells. . . . . . . . . . . 7.8 6.1
- -------------------
<FN>
Note: Productive wells are either producing wells or wells capable of commercial
production, although currently shut-in. The term "Gross" refers to the
wells in which a working interest is owned, and the term "Net" refers to
gross wells multiplied by the percentage of EP's working interest owned
therein.
The number of wells drilled is not a significant measure or indicator of
the relative success or value of a drilling program because the significance of
the reserves and economic potential may vary widely for each project. It is
also important to recognize that reported completions may not necessarily track
capital expenditures, since Securities and Exchange Commission guidelines do
not allow a well to be reported as complete until it is ready for production.
In the case of offshore wells, this may be several years following initial
drilling because of construction of platforms, pipelines and other necessary
facilities.
Additional information relating to the gas and oil activities of EP is
set forth in Note 7 of the Notes to Financial Statements appearing in
Appendix A to this report.
7
ITEM 3. Legal Proceedings
The information required hereunder is set forth in Note 5 of the Notes to
Financial Statements in Appendix A to this report.
ITEM 4. Submission of Matters to a Vote of Security Holders
Not applicable.
PART II
ITEM 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
The information required hereunder is set forth under "Depositary Unit
Market Prices and Distribution Information" set forth in Appendix A to this
report.
ITEM 6. Selected Financial Data
The information required hereunder is set forth under "Selected
Financial and Operating Data" set forth in Appendix A to this report.
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The information required hereunder is set forth under "Financial Review"
included in Appendix A to this report.
ITEM 8. Financial Statements and Supplementary Data
The information required hereunder is set forth under "Independent
Auditors' Report," "Management Report on Responsibility for Financial
Reporting," "Statements of Operations," "Statements of Cash Flows," "Balance
Sheets," "Statements of Changes in Partners' Capital" and "Notes to Financial
Statements" included in Appendix A to this report.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
8
PART III
ITEM 10. Directors and Executive Officers of the Registrant
Set forth below is information concerning the directors and executive
officers of EEI and directors of ENSERCH who are involved with the conduct of
operations of EP. Presently, all directors of EEI and ENSERCH are elected
annually.
Name Age EEI Office and Business Experience
-------- ------ -----------------------------------
D. W. Biegler 47 Chairman since January 1992 and a Director since
September 1991. (For additional information see
"Directors of ENSERCH" below.)
Gary J. Junco 44 President, Chief Operating Officer since January 1991
and Director since 1985. Senior Vice President, Land
and Marketing Division, from July 1985 to December
1990.
R. L. Kincheloe 63 Senior Vice President, Offshore and International since
January 1992. Senior Vice President, Drilling and
Production Operations, from April 1985 to January 1992.
W. T. Satterwhite 60 Director since April 1985. Senior Vice President and
General Counsel, Chief Legal Officer of ENSERCH since
1972.
S. R. Singer 63 Director since April 1985. Senior Vice President,
Finance and Corporate Development, Chief Financial
Officer of ENSERCH since 1968.
R. B. Williams 61 Director since January 1993, Vice President,
Administration of ENSERCH since May 1989.
Directors of ENSERCH
D. W. Beigler, age 47, is Chairman and President, Chief Executive Officer
of ENSERCH. Prior to his election to his present position in 1993, he served
Lone Star Gas Company, the utility division of the Corporation, as President
from 1985 and as Chairman from 1989 and was elected President and Chief
Operating Officer of the Corporation in 1991. Mr. Biegler is a Director of
ENSERCH, Texas Commerce Bancshares, Inc. and Trinity Industries, Inc. He has
been a Director of ENSERCH since 1991.
W. C. McCord, age 65, is retired Chairman and Chief Executive Officer of
ENSERCH. Mr. McCord is a Director of Lone Star Technologies, Inc., and Pool
Energy Services Co. He has been a Director of ENSERCH since 1970.
Preston M. Geren, Jr., age 70, is an investor active in real estate, oil
and gas, and banking. He was formerly the owner of Geren Associates,
Architects, Engineers & Planners. Mr. Geren has been a Director of ENSERCH
9
since 1973 and serves as Chairman of the Audit Committee and is a member of
the Policy and Conflicts of Interest Committee. He is a Director of Overton
Bancshares, Inc., Overton Bank & Trust Co., Pool Energy Services Co., and
Cassco Development Corporation.
W. Ray Wallace, age 71, is Chairman, President and Chief Executive
Officer, and Director, Trinity Industries, Inc., a fabricated steel products
company. Mr. Wallace has been a Director of ENSERCH since 1978 and serves as
Chairman of the Compensation Committee and is a member of the Audit Committee.
He is a Director of Lomas Financial Corporation.
William B. Boyd, age 70, is retired Chairman of the Board, President and
Chief Executive Officer, American Standard Inc., a manufacturer of air
conditioning, building, and transportation products. Mr. Boyd has been a
Director of ENSERCH since 1984 and serves as Chairman of the Nominating
Committee and is a member of the Compensation Committee. Mr. Boyd is a
Director of Armco Inc. and FMC Corporation.
B. A. Bridgewater, Jr., age 60, is Chairman, President and Chief
Executive Officer, and Director, Brown Group, Inc., a consumer products
company with operations in footwear and specialty retailing. Mr. Bridgewater
has been a Director of ENSERCH since 1987 and serves as Chairman of the Policy
and Conflicts of Interest Committee and is a member of the Audit Committee.
He is a Director of Boatmen's Bancshares, Inc., FMC Corporation, and McDonnell
Douglas Corporation.
J. M. Haggar, Jr., age 69, is retired Chairman of the Board, and Director,
Haggar Apparel Company, a manufacturer of apparel for men. Mr. Haggar has been
a Director of ENSERCH since 1988 and is a member of the Directors' Nominating
Committee and the Policy and Conflicts of Interest Committee. He is a Director
of Brinker International, Inc.
Dr. L. E. Fouraker, age 70, is retired from the position of Dean of the
Harvard Business School. Dr. Fouraker has been a Director of ENSERCH since
1990 and is member of the Compensation Committee and the Directors' Nominating
Committee. He is a Director of Alcan Aluminum Limited, Citicorp, General
Electric Company, Gillette Company, Ionics, Inc., and The New England.
M. J. Girouard, age 54, is President and Chief Operating Officer, and
Director, Pier 1 Imports, Inc. Mr. Girouard has been a Director of ENSERCH
since 1992 and is a member of the Compensation Committee and the Directors'
Nominating Committee.
Dr. Diana S. Natalicio, age 54, is President, University of Texas at El
Paso. Dr. Natalicio has been in her present position since 1988. She is a
Director of Lomas Financial Corporation and Sandia Corporation.
The Policy and Conflicts of Interest Committee of ENSERCH reviews areas
of potential conflict between EP and ENSERCH, its subsidiaries and affiliates
("ENSERCH" companies) and takes such action as it deems appropriate in order
to provide reasonable assurances of fair dealings between such entities. The
Committee meets at least annually, and more frequently if necessary.
10
ITEM 11. Executive Compensation
The total amount of compensation paid by EEI to all its executive
officers for the year ended December 31, 1993, which was charged to EP, was
$500,129 (2 persons). The amounts paid include base salary, bonus and other
miscellaneous earnings categories. The directors of EEI are not compensated
in their capacities as directors.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management
As of March 9, 1994:
Name and Address of
Beneficial Owner Amount and Nature Percent
of Depositary Units of Beneficial Ownership of Class
- -------------------- ----------------------- ----------
ENSERCH Corporation 101,694,162 Indirect 99.2(1)
300 South St. Paul Street
Dallas, Texas 75201
- ------------
(1) Includes 98,581,800 units representing limited partnership interests held
by an affiliate, Enserch Processing Partners, Ltd., which may be exchanged
at any time for Depositary Units of EP. No Directors or Officers of
ENSERCH or EEI own any units.
ITEM 13. Certain Relationships and Related Transactions
EP commenced operations in 1985 following the transfer to it of
substantially all of the domestic gas and oil exploration and production
business of ENSERCH. For a description of the transactions and properties
involved in the transfer, see "Business", "Properties" and Notes to Financial
Statements in Appendix A to this report.
For information concerning related party transactions between EP and
ENSERCH (including its affiliates), see "Directors and Executive Officers of
Registrant-Directors of ENSERCH" and the Notes to Financial Statements in
Appendix A to this report.
11
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)-1 Financial Statements
The following items appear in the Financial Information section included
as Appendix A to this report:
Item Page
----- ----
Selected Financial and Operating Data. . . . . . . . . . . . . . . A-2
Financial Review . . . . . . . . . . . . . . . . . . . . . . . . . A-3
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . A-7
Management Report on Responsibility for Financial Reporting. . . . A-8
Financial Statements:
Statements of Operations . . . . . . . . . . . . . . . . . . . A-10
Statements of Cash Flows . . . . . . . . . . . . . . . . . . . A-11
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . A-12
Statements of Changes in Partners' Capital . . . . . . . . . . A-13
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . A-14
Depositary Unit Market Prices and Distribution Information . . . . A-25
(a)-2 Financial Statement Schedules
The following items are included in Appendix B to this report:
Item Page
---- ----
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . B-2
Financial Statement Schedules for the Three Years
Ended December 31, 1993:
IV -Indebtedness to Related Parties . . . . . . . . . . B-3
V -Property, Plant and Equipment . . . . . . . . . . . B-4
VI -Accumulated Depreciation and Amortization of
Property, Plant and Equipment . . . . . . . . . . . B-5
X -Supplementary Statements of Operations
Information . . . . . . . . . . . . . . . . . . . . B-6
The financial statement schedules, other than those listed above, are
omitted because of the absence of the conditions under which they are required
or because the required information is included in the financial statements or
notes thereto.
12
(a)-3 Exhibits
4.1* - Agreement of Limited Partnership of EP and amendment No. 1
thereto as currently in effect, filed as Exhibit 4.1 to
Registrant's Form 10-K for the fiscal year ended December 31,
1992.
4.2* - Form of Certificate for Limited Partner's Units of EP filed as
Exhibit 3.2 and included as Annex I to Exhibit B to the
Prospectus included in Registration Statement No. 2-96373.
4.3* - Agreement of Limited Partnership of EPO and amendments No. 1
and No. 2 thereto currently in effect, filed as Exhibit 4.3 to
Registrant's Form 10-K for the fiscal year ended December 31,
1992.
4.4* - Depositary Agreement among EP, Harris Trust Company of New York
as the Depositary and the Unitholders, relating to EP Depositary
Units, filed as Exhibit 4.1 to Registration Statement No. 2-
96373.
4.5* - Form of Specimen Depositary Receipt filed as Exhibit 4.2 to
Registration Statement No. 2-96373.
10.1*- Assignment and Conveyance from EP Operating Limited Partnership
"Grantor" to Encogen One Partners, Ltd. "Grantee" dated February
29, 1988, filed as Exhibit 10.1 to Registrant's Form 10-K for
the fiscal year ended December 31, 1987.
23** - Consent of DeGolyer and MacNaughton.
24** - Powers of Attorney
- ------------
* Incorporated and herein by reference made a part hereof.
** Filed herewith
(b) No reports on Form 8-K were filed during the three months ended
December 31, 1993.
13
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:
ENSERCH EXPLORATION PARTNERS, LTD.
(A Texas Limited Partnership):
By: ENSERCH EXPLORATION, INC.
Managing General Partner
March , 1994 By /s/ D. W. Biegler
----------------------
D. W. Biegler, Chairman
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 date indicated.
Signature and Title Date
------------------ ------
D. W. Biegler, Chairman, Chief Executive
Officer and Director; Gary J. Junco,
President, Chief Operating Officer and
Director; R. L. Kincheloe, Senior
Vice President, Offshore and International, March , 1994
and Director; W. T. Satterwhite, Director;
S. R. Singer, Director; and J. W. Pinkerton,
Vice President and Controller
By: /s/ D. W. Biegler
D. W. Biegler
As Attorney-in-Fact
14
APPENDIX A
ENSERCH EXPLORATION PARTNERS, LTD.
INDEX TO FINANCIAL INFORMATION
December 31, 1993
Page
Selected Financial and Operating Data. . . . . . . . . . . . . . . . . . A-2
Financial Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . A-7
Management Report on Responsibility for Financial Reporting. . . . . . . A-8
Financial Statements:
Statements of Operations. . . . . . . . . . . . . . . . . . . . A-10
Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . A-11
Balance Sheets. . . . . . . . . . . . . . . . . . . . . . . . . A-12
Statements of Changes in Partners' Capital. . . . . . . . . . . A-13
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . . . . A-14
Depositary Unit Market Prices and Distribution Information . . . . . . . A-25
A-1
ENSERCH EXPLORATION PARTNERS, LTD.
SELECTED FINANCIAL AND OPERATING DATA
As of or for Year Ended December 31
--------------------------------------------------------------------
1993 1992 1991 1990 1989
---------- ----------- ------------ ----------- ----------
(Financial data in thousands except per unit amounts)
INCOME STATEMENT DATA
Revenues
Natural gas . . . . . . . . . . . . . . . . . . . . .$ 144,889 $ 117,418 $ 122,164 $ 141,287 $ 137,778
Oil and condensate . . . . . . . . . . . . . . . . . . 33,920 41,179 49,344 58,721 47,928
Natural gas liquids .. . . . . . . . . . . . . . . . . 3,790 6,037 1,503 1,695 1,590
Other . . . . . . . . . . . . . . . . . . . . . . . 2,393 1,274 1,479 332 3,778
---------- ----------- ----------- ----------- -----------
Total . . . . . . . . . . . . . . . . . . . .$ 184,992 $ 165,908 $ 174,490 $ 202,035 $ 191,074
========== =========== =========== =========== ===========
Operating Income (Loss). . . . . . . . . . . . . . . . . .$ 26,386 $ (70) $ (30,185) $ 36,457 $ 50,830
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . (3,881) (20,265) (49,644) 25,993 42,720
Net Income (Loss) per Unit(a). . . . . . . . . . . . . . . (0.04) (.20) (.48) .25 .41
Distributions Declared per Unit. . . . . . . . . . . . . . .30 .30 .30 .30 .30
Weighted Average Units Outstanding . . . . . . . . . . . . 102,500 102,500 102,500 102,500 102,500
BALANCE SHEET DATA
Property, Plant and Equipment-Gross. . . . . . . . . . . .$ 1,809,528 $ 1,742,490 $ 1,811,204 $ 1,776,642 $ 1,675,327
Property, Plant and Equipment-Net. . . . . . . . . . . . . 1,030,311 993,038 1,030,653 1,043,673 995,326
Total Assets . . . . . . . . . . . . . . . . . . . . . . . 1,086,303 1,039,185 1,077,619 1,109,203 1,041,266
Capitalization
Long-term debt - affiliated companies. . . . . . . . .$ 298,000 $ 266,000 $ 234,000 $ 202,000 $
Partners' capital. . . . . . . . . . . . . . . . . . . 610,237 645,179 696,505 777,210 782,278
---------- ----------- ----------- ----------- -----------
Total . . . . . . . . . . . . . . . . . . . .$ 908,237 $ 911,179 $ 930,505 $ 979,210 $ 782,278
========== =========== =========== =========== ===========
Book Value per Unit(a) . . . . . . . . . . . . . . . . . .$ 5.89 $ 6.23 $ 6.73 $ 7.51 $ 7.56
OPERATING DATA
Sales Volumes
Natural gas (MMcf) . . . . . . . . . . . . . . . . . 69,318 64,509 69,326 75,983 75,464
Oil and condensate (MBbl) . . . . . . . . . . . . . . 1,972 2,147 2,424 2,635 2,767
Natural gas liquids (MBbl) . . . . . . . . . . . . . . 313 452 80 95 125
Average Sales Price
Natural gas (per Mcf). . . . . . . . . . . . . . . . .$ 2.09 $ 1.82 $ 1.76 $ 1.86 $ 1.83
Oil and condensate (per Bbl) . . . . . . . . . . . . . 17.20 19.18 20.36 22.29 17.32
Natural gas liquids (per Bbl). . . . . . . . . . . . . 12.11 13.36 18.79 17.84 12.72
Net Wells
Drilled . . . . . . . . . . . . . . . . . . . . . . . 79 19 66 53 18
Productive . . . . . . . . . . . . . . . . . . . . . . 64 8 52 42 14
Proved Reserves (at December 31)
Gas (Bcf). . . . . . . . . . . . . . . . . . . . . . . 1,085.5 1,100.4 1,167.3 1,223.2 1,221.3
Oil and condensate (MMBbl) . . . . . . . . . . . . . . 38.2 37.9 38.0 28.7 23.1
Standardized Measure of Discounted
Future Net Cash Flows (in millions). . . . . . . . . .$ 1,102.4 $ 1,108.4 $ 1,060.4 $ 1,229.3 $ 1,089.3
Data in Equivalent Energy Content (MMBtu)(b)
Average Sales Price. . . . . . . . . . . . . . . . . .$ 2.14 $ 2.02 $ 2.00 $ 2.12 $ 1.97
Average Production Costs . . . . . . . . . . . . . . . .54 .53 .56 .50 .48
Amortization . . . . . . . . . . . . . . . . . . . . . .91 .91 .83 .75 .67
- -----------------------------------------
<FN>
(a) Net income (loss) and book value per unit is after deduction of the general partners' 1% interest.
(b) For purposes of providing a common unit of measure, natural gas, oil and natural gas liquids are converted to an
approximate equivalent unit on the basis of relative energy content: one Mcf of natural gas equals 1.05 MMBtu, one barrel
of oil equals 5.6 MMBtu and one barrel of natural gas liquids equals 4.2 MMBtu.
A-2
ENSERCH EXPLORATION PARTNERS, LTD.
FINANCIAL REVIEW
RESULTS OF OPERATIONS
EP had a net loss of $4 million in 1993, compared with a loss of
$20 million in 1992 and a loss of $50 million in 1991. The 1992 loss included
a $16 million write-off of an idle pipeline and shallow-water production
facility from an abandoned offshore project, and 1991 results included a
$51 million noncash charge for a write-down under the "ceiling test" for the
"full cost" method of accounting. Excluding the write-downs, EP's 1993 net
loss was about the same as in 1992 and compares with income of $1.8 million
in 1991.
Excluding the write-downs, operating income for 1993 was $26 million
versus $16 million in 1992 and $21 million in 1991. The improvement resulted
from significantly increased natural-gas prices and higher sales volumes.
Revenues for 1993 of $185 million were 12% higher than 1992 and 6% above 1991.
Natural-gas revenues were $145 million, compared with $117 million for
1992 and $122 million for 1991. The average natural-gas price per thousand
cubic feet (Mcf) in 1993 was $2.09, up 15% from $1.82 in 1992 and 19% from
$1.76 in 1991. Natural-gas sales volumes in 1993 of 69 billion cubic feet
increased 7% from the 1992 level and were virtually the same as in 1991.
The increase in volumes for 1993 was principally due to accelerated natural-gas
development drilling in East Texas and offshore production from Mississippi
Canyon Block 441 in the Gulf of Mexico, which went on stream in the second
quarter of 1993.
Spot-market sales, which include monthly and short-term industrial sales,
covered about 70% of 1993 gas sales, compared with 80% in 1992 and 75% in 1991.
During 1994, the percentage of gas sold in the spot market is expected to be in
the range of 75% to 85%.
Oil revenues were $34 million in 1993, compared with $41 million in 1992
and $49 million in 1991. The average sales price per barrel for 1993 of $17.20
was 10% below 1992 and 16% under 1991. Oil sales volumes for 1993 were
2.0 million barrels (MMBbls), an 8% decline from the 1992 level which was down
11% from the 1991 level. The lower volumes in 1993 were primarily the result
of declining production from several North Texas reservoirs.
Excluding the previously noted write-downs, costs and expenses for 1993
were $159 million, compared with $150 million in 1992 and $153 million in 1991.
The increase in expenses for 1993 reflects provisions totaling $7.1 million for
pending litigation. Also, depreciation and amortization expense for 1993 of
$77 million was $1.6 million higher than 1992, primarily due to increased
production. The overall rate of amortization was $.91 per million British
thermal units (MMBtu) produced for both 1993 and 1992, compared with $.83 in
1991. Costs of additional offshore projects and increased development costs
associated with older East Texas fields largely account for the increase from
1991. Average production cost per MMBtu in 1993 was $.54, compared with $.53
in 1992 and $.56 in 1991.
A-3
Interest expense in 1993 of $30 million was approximately $10 million
higher than both 1992 and 1991. The increase reflects a $6 million provision
for interest due royalty owners. A higher level of debt and less interest
capitalized also contributed to the 1993 increase.
EP's natural-gas reserves at January 1, 1994, were 1.09 trillion cubic
feet (Tcf), compared with 1.10 Tcf the year earlier, as estimated by DeGolyer
and MacNaughton, independent petroleum consultants. Oil and condensate
reserves, including natural gas liquids attributable to leasehold interest,
were 38 MMBbls, virtually the same as the year-ago level.
At January 1, 1994, estimated future net cash flows from EP's owned
proved gas and oil reserves, based on average prices and contracts in effect
in December 1993, were $2.0 billion, about the same as the year earlier. The
net present value of such cash flows, discounted at the Securities and Exchange
Commission (SEC)-prescribed 10%, was $1.1 billion, virtually the same as the
prior year. These discounted cash flow amounts are the basis for the
SEC-prescribed cost- center ceiling under the full-cost accounting method. The
margin between the cost-center ceiling and the unamortized capitalized costs of
U.S. gas and oil properties was approximately $150 million at December 31,
1993. Product prices are subject to seasonal and other fluctuations. A
significant decline in prices from yearend 1993 or other factors, without
mitigating circumstances, could cause a future write-down of capitalized costs
and a noncash charge against earnings.
CAPITAL RESOURCES AND LIQUIDITY
Net cash flows from operating activities in 1993 were $76 million,
$12 million lower than 1992 primarily due to less cash provided by changes in
net current operating assets and liabilities, and were virtually the same as in
1991. Investing activities required net cash flows of $124 million, compared
with $69 million in 1992 and $105 million in 1991. The increase in 1993 is
primarily due to a higher level of capital spending for natural-gas and oil
exploration and development programs.
In 1993, $48 million was required for investing activities after cash
provided by operations, and cash of $31 million was required for the payment of
distributions to unitholders. The total requirement of $79 million was
provided by an increase in borrowings from affiliated companies and advances
under leasing arrangements that temporarily exceeded disbursements for the
facilities under construction.
EP has budgeted $114 million for additions to property, plant and
equipment in 1994, compared with expenditures of $113 million in 1993. In
1992, EP's capital spending was sharply curtailed to $63 million in response
to poor prices for both natural gas and oil. If the early 1994 weakness in oil
prices persists throughout 1994, appropriate cutbacks in spending may be
undertaken. More than half of EP's 1994 capital expenditures is earmarked for
domestic onshore drilling.
In 1992, EP entered into operating lease arrangements to provide financing
for its portion of the offshore platforms and related facilities for the
Mississippi Canyon Block 441 (37.5% owned) and Garden Banks Block 388 (100%
owned) projects. A total of $34 million was required for the Mississippi Canyon
Block 441 project, which was completed in early 1993. The lease arrangement to
A-4
fund the construction costs for the Garden Banks facility is estimated to total
$235 million when completed in 1995. (See Note 5)
On January 3, 1994, EP paid a quarterly distribution of $.075 per unit.
In February 1994, EP announced that the quarterly distributions to unitholders
had been indefinitely suspended.
Even though inflation has abated considerably from the levels of the early
1980s, and was only about 2.5% in 1993, it continues to have some influence on
EP's operations. Most notable is that allowances for depreciation and
amortization based on the historical cost of fixed assets may be insufficient
to cover the replacement of some long-lived fixed assets.
The impact of the Clean Air Act Amendments of 1990 (Act) on EP cannot be
fully ascertained until the regulations that implement that Act have been
approved and adopted. Management currently believes that operating costs that
will be incurred under the new permit fee structure, any capital expenditures
associated with equipment modifications, and any other miscellaneous permitting
costs required under the Act will not have a material adverse effect on EP's
results of operations. Management expects the provisions of the Act will
increase the attractiveness of natural gas as compared with certain alternative
fuels; however, it is impossible to quantify any increase in demand for natural
gas, if any, that may be created by the Act.
FOURTH-QUARTER RESULTS
EP had a net loss of $6.5 million for the fourth quarter of 1993, compared
with a loss of $16 million for the 1992 fourth quarter, which included the
$16 million write-off of the abandoned offshore facilities. Excluding the
write- off, operating income for the fourth quarter was $4.8 million versus
$6.2 million for the same period of 1992. Revenues in 1993 of $50 million were
14% greater than 1992 primarily due higher natural-gas revenues resulting from
a 24% increase in sales volumes. The average natural-gas sales price for the
fourth quarter of $2.22 per Mcf was about the same as the prior year. Operating
expenses and interest expense were both higher than in the prior year due to the
previously noted provisions for pending litigation and interest due royalty
owners.
DRILLING PROGRAM
Drilling activity during the first half of 1993 increased to levels last
experienced in 1987, primarily because of development work in East Texas. EP
participated in 109 wells (79 net) in 1993, with the majority completed as gas
producers in East Texas. Thirty-six wells were in progress at yearend.
Recompletions and production optimization measures had a major role in the 1993
production enhancement program.
Results for 1994 will include a full year of production from the
Mississippi Canyon Block 441 deep-water project in the Gulf of Mexico, which
began production in early 1993. The field is producing some 70 million cubic
feet (MMcf) of natural gas and more than 500 barrels of condensate per day from
six wells. EP is the operator, with a 37.5% working interest in the project.
A-5
The Garden Banks Block 388 oil development project, also in the
Gulf, remains on schedule and on budget, with initial production anticipated by
mid- 1995. The final major contract for the conversion of a semi-submersible
drilling rig to a floating production facility was finalized in early 1994.
Installation of the offshore facilities, consisting of the subsea template,
gathering and sales pipelines and shallow-water operations, will begin by
mid-year. Three previously drilled oil wells will be connected to the subsea
template in 1995. Initial daily production from three predrilled wells is
expected to total 15 thousand barrels (MBbls) of oil and 12 to 15 MMcf of gas
by late 1995, with peak daily production from the Garden Banks project
anticipated in late 1996 at 40 MBbls of oil and 60 MMcf of gas. Gross proven
reserves are presently estimated to be equivalent to 28 MMBbls of oil by
DeGolyer and MacNaughton. EP is 100% interest owner and operator of the Garden
Banks project.
NEW ACCOUNTING STANDARDS
SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other
than Pensions," which mandates the accounting for medical and life insurance
and other nonpension benefits provided to retired employees, was adopted by EP
effective January 1, 1993. (See Note 2)
SFAS No. 112, "Employer's Accounting for Postemployment Benefits," will
become effective for EP in 1994. This standard covers the accounting for
estimated costs of benefits provided to former or inactive employees before
their retirement. EP receives an allocation of these benefits from ENSERCH
which currently accrues costs of benefits to former or inactive employees by
varying methods. The new standard is not expected to have a significant effect
on results of operations or financial condition.
A-6
INDEPENDENT AUDITORS' REPORT
To the Partners of Enserch Exploration Partners, Ltd.:
We have audited the accompanying balance sheets of Enserch Exploration
Partners, Ltd. as of December 31, 1993 and 1992, and the related statements of
operations, cash flows and changes in partners' capital for each of the three
years in the period ended December 31, 1993. These financial statements are
the responsibility of the Partnership's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of the Partnership at December 31, 1993 and
1992, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1993, in conformity with generally
accepted accounting principles.
DELOITTE & TOUCHE
Dallas, Texas
February 7, 1994
A-7
MANAGEMENT REPORT ON RESPONSIBILITY
FOR FINANCIAL REPORTING
The management of Enserch Exploration, Inc. (a wholly owned subsidiary of
ENSERCH), as Managing General Partner of Enserch Exploration Partners, Ltd., is
responsible for the preparation, presentation and integrity of the financial
statements. These statements have been prepared in conformity with accounting
principles generally accepted in the United States and include amounts that
represent management's best estimates and judgments. Management has
established practices and procedures designed to support the reliability of the
estimates and minimize the possibility of a material misstatement. Management
also is responsible for the accuracy of the other information presented in the
annual report on Form 10-K and for its consistency with the financial
statements.
Management has established and maintains internal accounting controls
that provide reasonable assurance as to the integrity and reliability of the
financial statements, the protection of assets from unauthorized use or
disposition, and the prevention and detection of fraudulent financial
reporting. The system of internal control provides for appropriate division
of responsibility and is documented by written policies and procedures that
are communicated to employees with significant roles in the financial reporting
process and updated as necessary. Management continually monitors compliance
with the system of internal accounting controls. ENSERCH maintains a strong
internal audit function that evaluates the adequacy of the system of internal
accounting controls. As part of the annual audit of the financial statements,
Deloitte & Touche also performs a study and evaluation of the system of
internal accounting controls as necessary to determine the nature, timing and
extent of their auditing procedures. The Board of Directors of ENSERCH
maintains an Audit Committee composed of Directors who are not employees. The
Audit Committee meets periodically with management, the independent auditors
and the internal auditors to discuss significant accounting, auditing, internal
accounting control and financial reporting matters. A procedure exists whereby
either the independent auditors or the internal auditors through the
independent auditors may request, directly to the Audit Committee, a meeting
with the Committee.
Management has given proper consideration to the independent and internal
auditors' recommendations concerning the system of internal accounting controls
and has taken corrective action believed appropriate in the circumstances.
Management further believes that, as of December 31, 1993, the overall system
of internal accounting controls is sufficient to accomplish the objectives
discussed herein.
A-8
Management recognizes its responsibility for establishing and maintaining
a strong ethical climate so that the Partnership's affairs are conducted
according to the highest standards as defined in ENSERCH's Statement of
Policies. The Statement of Policies is publicized throughout ENSERCH and
addresses, among other issues, open communication within ENSERCH; the
disclosure of potential conflicts of interest; compliance with the laws,
including those relating to financial disclosures; and the confidentiality of
proprietary information.
Enserch Exploration, Inc.
Managing General Partner of
Enserch Exploration Partners, Ltd.
/s/ Gary J. Junco
- ------------------
Gary J. Junco
President, Chief
Operating Officer
/s/J. W. Pinkerton
- ------------------
J. W. Pinkerton
Vice President and
Controller
A-9
ENSERCH EXPLORATION PARTNERS, LTD.
STATEMENTS OF OPERATIONS
Year Ended December 31
----------------------------------
1993 1992 1991
-------- -------- --------
(In thousands except
per unit amounts)
Revenues:
Natural gas (Notes 2 and 4). . . . . . . . . . . . . . $144,889 $117,418 $122,164
Oil and condensate (Note 2). . . . . . . . . . . . . . 33,920 41,179 49,344
Natural gas liquids . . . . . . . . . . . . . . . . . 3,790 6,037 1,503
Other. . . . . . . . . . . . . . . . . . . . . . . . . 2,393 1,274 1,479
-------- -------- --------
Total 184,992 165,908 174,490
-------- -------- --------
Costs and Expenses:
Operating expenses . . . . . . . . . . . . . . . . . 37,022 37,062 42,171
Revenue related taxes. . . . . . . . . . . . . . . . 9,613 9,131 10,113
Depreciation and amortization (Note 2) . . . . . . . 76,700 75,066 72,183
Write-down of gas and
oil properties (Note 2). . . . . . . . . . . . . . 16,335 51,480
General, administrative and other . . . . . . . . . 35,271 28,384 28,728
-------- -------- --------
Total 158,606 165,978 204,675
-------- -------- --------
Operating Income (Loss). . . . . . . . . . . . . . . . . . 26,386 (70) (30,185)
Other Income (Expense) - Net . . . . . . . . . . . . . . (3) 2
Interest Expense (Notes 4 and 6) . . . . . . . . . . . . 30,267 20,192 19,461
-------- -------- --------
Net Loss . . . . . . . . . . . . . . . . . . . . . . . (3,881) (20,265) (49,644)
Less 1% General Partners' Interest . . . . . . . . . . . (39) (203) (496)
-------- -------- --------
Loss Applicable to
Limited Partners'Interest. . . . . . . . . . . . . . $ (3,842) $(20,062) $(49,148)
======== ======== ========
Net Loss Per Unit. . . . . . . . . . . . . . . . . . . . $ (0.04) $ (.20) $ (.48)
======== ======== ========
Weighted Average Units Outstanding . . . . . . . . . . . 102,500 102,500 102,500
======== ======== ========
Distributions Declared Per Unit. . . . . . . . . . . . . $ .30 $ .30 $ .30
======== ======== ========
<FN>
See Notes to Financial Statements.
A-10
ENSERCH EXPLORATION PARTNERS, LTD.
STATEMENTS OF CASH FLOWS
Year Ended December 31
----------------------------------
1993 1992 1991
--------- -------- --------
(In thousands)
OPERATING ACTIVITIES
Net loss . . . . . . . . . . . . . . . . . . . . . . . . $ (3,881) $(20,265) $(49,644)
Adjustments to reconcile net loss to
net cash flows:
Depreciation and amortization (Note 2). . . . . . . . 76,700 75,066 72,183
Write-down of gas and oil properties (Note 2) . . . . 16,335 51,480
Cash effect of changes in current operating
assets and liabilities (Note 6) . . . . . . . . . . . 3,545 17,365 1,683
-------- -------- -------
Net cash flows from operating activities . . . . . 76,364 88,501 75,702
-------- -------- -------
INVESTING ACTIVITIES
Property, plant and equipment additions. . . . . . . . (113,380) (63,223) (115,131)
Other. . . . . . . . . . . . . . . . . . . . . . . . . (10,760) ( 5,643) 9,956
-------- ------- --------
Net cash flows used for
investing activities. . . . . . . . . . . . . . (124,140) (68,866) (105,175)
-------- ------- --------
Net cash flow (required for) from
operating and investing activities . . . . . . (47,776) 19,635 (29,473)
-------- ------- --------
FINANCING ACTIVITIES
Change in temporary advances with
affiliated companies. . . . . . . . . . . . . . . . . 32,756 (37,201) 28,497
Proceeds from long-term notes payable to an
affiliated company. . . . . . . . . . . . . . . . . . 32,000 32,000 32,000
Advances under leasing arrangements (Note 5) . . . . . 13,453 17,475
Cash distributions paid. . . . . . . . . . . . . . . . (31,061) (31,061) (31,061)
-------- ------- -------
Net cash flows from (used for)
financing activities. . . . . . . . . . . . . . 47,148 (18,787) 29,436
-------- ------- -------
Net (Decrease) Increase in Cash. . . . . . . . . . . . . . (628) 848 (37)
Cash at Beginning of Year. . . . . . . . . . . . . . . . . 937 89 126
-------- ------- -------
Cash at End of Year. . . . . . . . . . . . . . . . . . . . $ 309 $ 937 $ 89
======== ======= =======
Interest Paid (Net of Amounts Capitalized) . . . . . . . . $ 24,791 $ 20,192 $ 17,047
======== ======== ========
<FN>
See Notes to Financial Statements.
A-11
ENSERCH EXPLORATION PARTNERS, LTD.
BALANCE SHEETS
December 31
---------------------------
1993 1992
---------- -----------
(In thousands)
ASSETS
Current Assets:
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 309 $ 937
Accounts receivable - trade (net of allowance
for possible losses of $699 and $953). . . . . . . . . . . . . . . . . . . . 17,120 21,679
Accounts receivable - affiliated companies (Note 4). . . . . . . . . . . . . . 13,952 7,011
Temporary advances - affiliated companies (net)
(Notes 3 and 4). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,540
Materials and supplies, at average cost. . . . . . . . . . . . . . . . . . . . 1,749 3,431
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 272 335
---------- -----------
Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . 33,402 38,933
---------- -----------
Property, Plant and Equipment (at cost) (Notes 2 and 7):
Gas and oil properties (full - cost method)
($82,236 and $86,005 excluded from amortization base). . . . . . . . . . . . 1,803,581 1,737,708
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,947 4,782
---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,809,528 1,742,490
Less accumulated depreciation and amortization . . . . . . . . . . . . . . . . . 779,217 749,452
---------- ----------
Net property, plant and equipment . . . . . . . . . . . . . . . . . . . . 1,030,311 993,038
---------- ----------
Other Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,590 7,214
---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,086,303 $1,039,185
========== ==========
LIABILITIES
Current Liabilities:
Accounts payable - trade . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 67,693 $ 58,865
Accounts payable - affiliated companies (Note 4) . . . . . . . . . . . . . . . 3,531 7,455
Temporary advances - affiliated companies (net)
(Notes 3 and 4). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27,216
Distributions payable to unitholders . . . . . . . . . . . . . . . . . . . . . 7,765 7,765
Advances under leasing arrangements (Note 5) . . . . . . . . . . . . . . . . . 30,928 17,475
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,690 5,826
---------- ----------
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . 139,823 97,386
---------- ----------
Long-term Debt - Affiliated Companies (Note 3) . . . . . . . . . . . . . . . . . 298,000 266,000
Deferred Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,554 26,150
Other Liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,689 4,470
Commitments and Contingent Liabilities (Note 5). . . . . . . . . . . . . . . . .
Partners' Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 610,237 645,179
---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,086,303 $1,039,185
========== ==========
<FN>
See Notes to Financial Statements.
A-12
ENSERCH EXPLORATION PARTNERS, LTD.
STATEMENTS OF CHANGES IN PARTNERS' CAPITAL
General Limited
Partners Partners Total
--------- ---------- ----------
(In thousands)
Balance, December 31, 1990 . . . . . . . $ 16,203 $ 761,007 $ 777,210
Net Loss . . . . . . . . . . . . . . . . (496) (49,148) (49,644)
Distributions Declared . . . . . . . . . (311) (30,750) (31,061)
-------- --------- ---------
Balance, December 31, 1991 . . . . . . . 15,396 681,109 696,505
Net Loss . . . . . . . . . . . . . . . . (203) (20,062) (20,265)
Distributions Declared . . . . . . . . . (311) (30,750) (31,061)
-------- --------- ---------
Balance, December 31, 1992 . . . . . . . 14,882 630,297 645,179
Net Loss . . . . . . . . . . . . . . . . (39) (3,842) (3,881)
Distributions Declared . . . . . . . . . (311) (30,750) (31,061)
-------- --------- ---------
Balance, December 31, 1993 . . . . . . . $ 14,532 $ 595,705 $ 610,237
========= ========= =========
<FN>
See Notes to Financial Statements.
A-13
ENSERCH EXPLORATION PARTNERS, LTD.
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND CONTROL
Enserch Exploration Partners, Ltd. ("EP"), a Texas limited partnership,
was formed in 1985 to succeed to substantially all of the domestic gas and oil
exploration and production business of ENSERCH Corporation ("ENSERCH"). At
December 31, 1993, ENSERCH and Enserch Processing Partners, Ltd. ("Processing")
owned 3,112,362 (3.0%) and 98,581,800 (96.2%), respectively, of EP's limited
partnership units outstanding. The balance of 805,914 (.8%) of EP's units
outstanding is held by the public. For administrative convenience, EP operates
through EP Operating Limited Partnership ("EPO"), formerly EP Operating
Company, a Texas limited partnership, in which EP holds a 99% limited partner's
interest and the general partners own a 1% interest. Enserch Exploration, Inc.
("EEI") is the managing general partner and ENSERCH is the special general
partner of EP and EPO.
EP has no officers, directors or employees. Instead, officers, directors
and employees of EEI perform all management and operating functions for EP.
Neither ENSERCH nor EEI, as general partners of EP, receives any carried
interests, promotions, back-ins or other compensation.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation - The financial statements of EP have been prepared
in conformity with generally accepted accounting principles but will not be the
basis for reporting taxable income to unitholders. The proportional
consolidation method is used whereby the financial statements reflect EP's 99%
interest in EPO's assets, liabilities and operations. All dollar amounts
except per unit amounts in the notes to financial statements are stated in
thousands unless otherwise indicated.
Natural Gas and Oil Hedging Contracts - Gains and losses from transactions
to hedge against volatile product prices are included in revenues in the
statements of operations.
Gas and Oil Properties - The full-cost method, as prescribed by the
Securities and Exchange Commission (SEC), is used whereby the costs of proved
and unproved gas and oil properties, together with successful and unsuccessful
exploration and development costs, are capitalized. The carrying value is
limited to the present value of estimated future net revenues of proved
reserves, the cost of excluded properties and the lower of cost or market value
of unproved properties being amortized ("full-cost ceiling"). The full-cost
ceiling is calculated quarterly under current SEC rules. In March 1991, EP
recorded a $51 million noncash write-down of the carrying value of its gas and
oil properties due to the full-cost center ceiling limitation test.
Dry-hole costs resulting from exploration activities are classified as
evaluated costs and are included in the amortization base. Costs directly
associated with the acquisition and evaluation of unproved properties are
excluded from the amortization base until the related properties are
evaluated. Such unproved properties are assessed periodically and a provision
for impairment is made to the full-cost amortization base when appropriate.
Sales of gas and oil properties are credited to capitalized costs unless the
sale would have a significant impact on the amortization rate.
A-14
In December 1992, EP recorded a $16 million noncash write-off of an idle
pipeline and shallow-water production facility from an abandoned offshore
project.
Depreciation and Amortization - Amortization of evaluated gas and oil
properties is computed on the unit-of-production method using estimated proved
gas and oil reserves quantified on the basis of their equivalent energy
content. Depreciation of other property, plant and equipment is provided
principally by the straight-line method over the estimated service lives of the
related assets.
Income Taxes - EP is a partnership and, as a result, the income or loss
of the partnership, which reflects differences in the timing of the deduction
of certain gas and oil drilling and development costs for federal income tax
purposes, is includable in the tax returns of the individual partners.
Accordingly, no recognition has been given to income taxes in the financial
statements of EP. The assets and liabilities reported in the financial
statements of EP exceeded the federal income-tax bases by approximately
$704 million and $720 million at December 31, 1993 and 1992, respectively.
Retirement Plan - Substantially all personnel who are associated with EP
are covered by an ENSERCH retirement plan and are eligible for certain health
care and life insurance benefits upon retirement. Total pension costs
allocated to EP were $867, $1,054, and $929 in 1993, 1992 and 1991,
respectively. Post-retirement health care and life insurance benefit costs
allocated to EP were $821, $550, and $577 in 1993, 1992 and 1991, respectively.
Postretirement benefits in 1993 reflect the impact of SFAS No. 106 "Employer's
Accounting for Postretirement Benefits Other Than Pensions", effective in
January 1993. This new standard requires the accrual of these benefits over
the working life of the employee rather than charging to expense on a cash
basis.
Fair Value of Financial Instruments - The fair value of financial
instruments has been estimated using valuation methodologies in accordance with
SFAS No. 107, "Disclosures About Fair Value of Financial Instruments".
Determinations of fair value are based on subjective data and significant
judgment relating to timing of payments and collections and the amounts to be
realized. Accordingly, the estimates presented are not necessarily indicative
of the amounts that EP could realize in a current market exchange.
Management believes that the fair value of financial instruments, other
than long-term debt, is not materially different than the related carrying
value. The estimated fair value for long-term debt is presented in Note 3.
A-15
3. LINE OF CREDIT AND BORROWINGS
Short-term Borrowing Arrangements - Both EP and EPO maintain separate
short-term borrowing arrangements with ENSERCH to meet operating needs. Under
these arrangements, ENSERCH may advance funds to EP or EPO, and EP or EPO may
advance funds to ENSERCH. EPO further maintains a short-term borrowing
arrangement with EEI by which EEI may advance funds to EPO and EPO may advance
funds to EEI. Under all these arrangements, the aggregate amount of short-term
loans available between the parties is at the respective lender's sole
discretion, and any amounts advanced under the arrangements mature within 12
months from the date the advance is made. The interest rate is the 30-day
commercial paper rate available for similar amounts on commercial paper
borrowings by ENSERCH. Interest is payable monthly. These arrangements are
renewed annually. At December 31, 1993, there were $27,216 of net short-term
borrowings outstanding under these arrangements at an interest rate of 3.28%.
Long-term Notes Payable - Long-term notes payable to Processing are
summarized below:
1993 1992
-------- --------
9.2% Notes due 2000 . . . . . . . . . $ 16,000 $ 16,000
9.95% Notes due 2000 . . . . . . . . 16,000 16,000
9.9% Note due 2000 . . . . . . . . . 170,000 170,000
9.9% Note due 2001 . . . . . . . . . 8,000 8,000
9.8% Notes due 2001 . . . . . . . . . 16,000 16,000
9.0% Note due 2001 . . . . . . . . . 8,000 8,000
8.5% Notes due 2002. . . . . . . . . 16,000 16,000
9.05% Notes due 2002. . . . . . . . . 8,000 8,000
8.75% Notes due 2002. . . . . . . . . 8,000 8,000
8.35% Notes due 2003. . . . . . . . . 8,000
6.35% Notes due 1998. . . . . . . . . 8,000
6.30% Notes due 1998. . . . . . . . . 8,000
5.30% Notes due 1998. . . . . . . . . 8,000
-------- --------
Total . . . . . . . . . . . . $298,000 $266,000
======== ========
Interest on the above notes is payable semiannually on June 30
and December 31. The estimated fair value of these notes was $352 million at
December 31, 1993 and $300 million at December 31, 1992. The calculation was
made using a discounted cash flow approach based on the interest rates
currently available to ENSERCH for debt with similar terms and remaining
maturities.
4. RELATED PARTY TRANSACTIONS
In the ordinary course of business, EP engages in various transactions
with ENSERCH and its affiliates. All such transactions are subject to review
by the Policy and Conflicts of Interest Committee of ENSERCH, a committee
composed solely of outside directors. The Committee has found no unfair
dealings between and among such parties. EP is charged for direct costs
incurred by ENSERCH and EEI that are associated with managing EP's business
and operations. Additionally, indirect costs (principally general and
A-16
administrative costs) applicable to EP are allocated to EP by ENSERCH. Such
charges amounted to $2,026, $1,927 and $1,798 in 1993, 1992 and 1991,
respectively.
EP had sales to affiliated companies (Enserch Gas Company, Lone Star Gas
Company and Processing) of $108,916, $32,508 and $32,710 in 1993, 1992 and
1991, respectively. In 1993, affiliated revenues include gas sales of $91,000
under new contracts effective March 1, 1993 with Enserch Gas Company covering
essentially all gas production not committed under existing contracts.
Net interest costs incurred on affiliated borrowings were $27,120,
$25,336, and $22,872 in 1993, 1992 and 1991, respectively.
5. COMMITMENTS AND CONTINGENT LIABILITIES
Advances Under Leasing Arrangements - In May 1992, EP entered into an
operating leasing arrangement to provide financing for its portion of the
offshore platform and related facilities for the 37 1/2% owned Mississippi
Canyon Block 441 project. A total of $34 million was required for the project,
which was completed in early 1993. EP leased the facilities for an initial
period through May 20, 1994, with an option to renew the lease, with the
consent of the lessor, for up to 10 successive six-month periods. The lease
has been renewed through November 20, 1994 and EP expects to renew the lease
for all renewal periods. EP has the option to purchase the facilities
throughout the lease periods and as of December 31, 1993, has guaranteed an
estimated residual value for the facilities of approximately $27 million should
the lease not be renewed. Expenses incurred under the lease in 1993 was
$2.1 million. The estimated future minimum net rentals for the Mississippi
Canyon operating lease is $6.3 million for 1994.
In September 1992, EP entered into an operating lease arrangement to
provide financing for the offshore platform and related facilities of its 100%
owned Garden Banks Block 388 project. The lessor will fund the construction
cost of the facilities quarterly, up to a maximum of $235 million. As of
December 31, 1993, a total of $60 million had been advanced to EP under the
lease as agent for the lessor, $31 million of which was unexpended and
reflected as a current liability. EP will lease the facilities for an initial
period through March 31, 1997, with the option to renew the lease, with the
consent of the lessor, for up to three successive two-year periods. EP, as
agent for the lessors, will acquire, construct and operate the units of leased
property and has guaranteed completion of construction of the facilities. EP
has the option to purchase the facilities throughout the lease periods and has
guaranteed an estimated residual value for the facilities of approximately $188
million, assuming the full lease amounts are advanced and expended, should the
lease not be renewed. The estimated future minimum net rentals for the Garden
Banks operating lease are as follows: $4.8 million for 1994; $9.1 million for
1995; $9.1 million for 1996; and $2.3 million for 1997. Lease payments are
being deferred during the construction period and will be amortized when
production begins.
A-17
At December 31, 1993, EEI had several noncancelable operating leases,
principally for buildings and office space, that expire at various dates
through 1998. EP bears an allocated share of rental expenses incurred by EEI
under noncancelable operating leases. EP's allocated share of rental expenses
(99% of EEI's rental expenses) totaled $4,985, $3,547 and $2,938 in 1993, 1992
and 1991, respectively. Future minimum rentals under such leases, of which EP
would bear its proportionate share, are as follows: $1.3 million for 1994;
$1.3 million for 1995; $1.4 million for 1996; $1.5 million for 1997; and $1.4
million for 1998.
Legal Proceedings - A lawsuit was filed against EEI, ENSERCH, its utility
division and EPO in the 348th Judicial District Court of Tarrant County in May
1989. Plaintiffs seek unspecified actual damages and punitive damages in the
amount of $5 million. Plaintiffs allege royalties were not fully paid, certain
expenses were improperly charged against the amount of royalties due,
negligence in the venting of gas and liquid hydrocarbons into the air, and
breach of duty of good faith and fair dealing by wrongfully concealing certain
material facts concerning sales of gas from the subject leases to the utility
division.
A lawsuit was filed on February 24, 1987, in the 112th Judicial District
of Sutton County, Texas, against subsidiaries and affiliates of ENSERCH, as
well as its utility division. The plaintiffs have claimed that defendants
failed to make certain production and minimum purchase payments under a gas-
purchase contract. In this connection, the plaintiffs have alleged a
conspiracy to violate purchase obligations, improper accounting of amounts due,
fraud, misrepresentation, duress, failure to properly market gas and failure
to act in good faith. In this case, plaintiffs seek actual damages in excess
of $5 million and punitive damages in an amount equal to 0.5% of the
consolidated gross revenues of ENSERCH for the years 1982 through 1986
(approximately $85 million), interest, costs and attorneys' fees.
On December 26, 1989, a lawsuit was filed against EEI and EPO in the 130th
Judicial District Court of Matagorda County, Texas. The plaintiff claims that
the defendants breached an alledged contract to sell a working interest and net
revenue interest in two leases located in Matagorda County. Trial of the case
resulted in a jury verdict in favor of the plaintiff. Judgment was entered by
the trial court on October 8, 1992, ordering EEI and EPO to convey the leases
to the plaintiff and to pay damages of $3.1 million, which includes principal,
prejudgment interest, attorneys' fees and costs. This judgment was appealed
to the Corpus Christi Court of Appeals on September 2, 1992. Counsel has
advised that there is a reasonable basis to believe that the decision of the
trial court will be reversed.
On October 25, 1991, a lawsuit was filed against EEI, EPO and ENSERCH in
the 111th District Court of Webb County Texas. Other parties have intervened.
The plaintiffs and intervenors claim that the defendants' failure to reassign
A-18
part of an gas and oil lease covering approximately 33,000 net mineral acres
in breach of defendants' contractual reassignment obligations entitles them to
recover the fair market value of the lost leasehold estate and lost overriding
royalty interests. Plaintiffs and intervenors claim actual damages of
approximately $3.1 million for the lost leasehold estate, and approximately
$2.2 million for the lost overriding royalty interests. They also seek pre-
judgment interest, attorney's fees and costs.
Management believes that the named defendants have meritorious defenses to
the claims made in these and other actions. In the opinion of management, EP
will incur no liability from these and all other pending claims and suits that
would be considered material for financial reporting purposes.
6. SUPPLEMENTAL FINANCIAL INFORMATION
Quarterly Results (Unaudited) - The results of operations by quarters are
summarized below. In the opinion of EP's management, all adjustments
(consisting only of normal recurring accruals) necessary for a fair
presentation have been made.
Quarter Ended
--------------------------------------------------
March 31 June 30 September 30 December 31
--------- -------- ------------ ----------
1993:
Revenues . . . . . . . . . . . . . . . . . . . . $39,755 $47,709 $47,638 $ 49,890
Operating Income . . . . . . . . . . . . . . . . 5,118 9,160 7,267 4,841
Net Income (Loss) . . . . . . . . . . . . . . . . (640) 2,743 548 (6,532)
Net Income (Loss) Per Unit. . . . . . . . . . . . (.01) .03 .01 (.06)
1992:
Revenues. . . . . . . . . . . . . . . . . . . . . $41,333 $39,454 $41,224 $ 43,897
Operating Income (Loss) . . . . . . . . . . . . . 4,228 1,538 4,346 (10,182)(a)
Net Loss. . . . . . . . . . . . . . . . . . . . . (610) (3,267) (862) (15,526)
Net Loss Per Unit . . . . . . . . . . . . . . . . (.01) (.03) (.01) (.15)
<FN>
(a) Includes a $16,335 noncash write-off of an idle pipeline and shallow-water
production facility from an abandoned offshore project.
Decrease (Increase) in Current Operating Assets and Liabilities by
Components - is summarized below:
1993 1992 1991
------- ------- --------
Accounts Receivable . . . . . . . . . . . . $(2,382) $10,737 $ 16,580
Materials and Supplies. . . . . . . . . . . 1,682 833 (187)
Other Current Assets. . . . . . . . . . . . 63 891 (1,105)
Accounts Payable. . . . . . . . . . . . . . 7,318 5,437 (14,654)
Other Current Liabilities . . . . . . . . . (3,136) (533) 1,049
-------- ------- --------
Total. . . . . . . . . . . . . . . $ 3,545 $17,365 $ 1,683
======== ======= ========
A-19
Interest Costs - are summarized below:
1993 1992 1991
------- ------- -------
Interest Capitalized. . . . . . . . . . . . . . $ 4,214 $ 5,262 $ 6,871
Interest Charged to Expense . . . . . . . . . . 30,267(a) 20,192 19,461
------- ------- -------
Interest Costs Incurred. . . . . . . $34,481 $25,454 $26,332
======= ======= =======
<FN>
(a) Includes $6 million provision for interest due royalty owners.
7. SUPPLEMENTAL GAS AND OIL INFORMATION
Gas and Oil Producing Activities - The following tables set forth
information relating to gas and oil producing activities. Reserve data for
natural gas liquids attributable to leasehold interests owned by EP are
included in oil and condensate.
December 31
-------------------------
1993 1992
---------- ----------
Capitalized Costs:
Proved gas and oil properties . . . . . . . . . . . $1,721,345 $1,651,703
Unproved gas and oil properties . . . . . . . . . . 82,236 86,005
---------- ----------
Total. . . . . . . . . . . . . . . . . . . . . $1,803,581 $1,737,708
========== ==========
Accumulated depreciation and amortization . . . . . . $ 775,570 $ 746,657
========== ==========
Year Ended December 31
--------------------------------
1993 1992 1991
-------- ------- --------
Costs Incurred:
Property acquisition costs:
Proved. . . . . . . . . . . . . . . . . . . $ 8,179 $ 886 $ 659
Unproved. . . . . . . . . . . . . . . . . . 12,429 8,969 9,527
Exploration costs . . . . . . . . . . . . . . 36,397 35,030 46,901
Development costs . . . . . . . . . . . . . . 62,401 16,355 62,586
-------- ------- --------
Total . . . . . . . . . . . . . . . . . . $119,406 $61,240 $119,673
======== ======= ========
Amortization (per MMBtu)(a) . . . . . . . . . . $ .91 $ .91 $ .83
======== ======= ========
<FN>
(a) Amortization expense per unit of production converted to a common unit of
measure, millions of British thermal units (MMBtu).
A-20
Excluded Costs - The following table sets forth the composition of
capitalized costs excluded from the amortizable base as of December 31, 1993:
Amounts Incurred In
---------------------------------- Total as of
Prior December 31,
1993 1992 1991 Years 1993
------- ------- ------- ------- ------------
Property Acquisition Costs. . . $12,311 $ 5,260 $ 3,792 $18,539 $39,902
Exploration Costs . . . . . . . 5,498 10,864 9,337 3,148 28,847
Interest Capitalized. . . . . . 3,990 4,367 2,895 2,235 13,487
------- ------- ------- ------- --------
Total. . . . . . . . $21,799 $20,491 $16,024 $23,922 $82,236
======= ======= ======= ======= ========
At December 31, 1993, approximately 43% of excluded costs relates to
offshore activities in the Gulf of Mexico and the remainder relates to domestic
onshore exploration activities. The anticipated timing of the inclusion of
these costs in the amortization computation will be determined by the rate at
which exploratory and development activities continue, which is expected to be
accomplished within ten years.
Gas and Oil Reserves (Unaudited) - The following table of estimated
proved and proved developed reserves of gas and oil has been prepared utilizing
estimates of yearend reserve quantities provided by DeGolyer and MacNaughton,
independent petroleum consultants. Reserve estimates are inherently imprecise
and estimates of new discoveries are more imprecise than those of producing gas
and oil properties. Accordingly, the reserve estimates are expected to change
as additional performance data becomes available. Oil reserves (which include
condensate and natural gas liquids attributable to leasehold interests) are
stated in thousands of barrels (MBbl). Gas reserves are stated in million
cubic feet (MMcf). All reserves are located in the United States.
A-21
Oil Gas
MBbl MMcf
------ ---------
Proved Reserves:
Balance, January 1, 1991. . . . . . . . . . . .. . . . 28,725 1,223,180
Revisions of previous estimates . . . . . . . .. . . . (117) (54,709)
Extensions, discoveries and additions . . . . .. . . . 1,478 57,081
Purchase of minerals in place . . . . . . . . .. . . . 10,516 12,307
Sale of minerals in place . . . . . . . . . . .. . . . (36) (549)
Production. . . . . . . . . . . . . . . . . . .. . . . (2,529) (70,026)
------ ---------
Balance, December 31, 1991. . . . . . . . . . . . . . . 38,037 1,167,284
Revisions of previous estimates . . . . . . . . . . . . 1,023 (7,054)
Extensions, discoveries and additions . . . . . . . . . 1,444 20,817
Purchase of minerals in place . . . . . . . . . . . . . 102 198
Sale of minerals in place . . . . . . . . . . . . . . . (42) (15,665)
Production. . . . . . . . . . . . . . . . . . . . . . . (2,625) (65,161)
------- ---------
Balance, December 31, 1992. . . . . . . . . . . . . . . 37,939 1,100,419
Revisions of previous estimates . . . . . . . . . . . . 1,331 20,179
Extensions, discoveries and additions . . . . . . . . . 1,292 34,549
Purchase of minerals in place . . . . . . . . . . . . . 3 4,379
Sale of minerals in place . . . . . . . . . . . . . . . (40) (4,042)
Production. . . . . . . . . . . . . . . . . . . . . . . (2,307) (70,018)
------- ---------
Balance, December 31, 1993. . . . . . . . . . . . . . . 38,218 1,085,466
Less 1% general partners' interest in EPO . . . . . . . 382 10,855
------- ---------
Net. . . . . . . . . . . . . . . . . . . . . 37,836 1,074,611
======= =========
Proved Developed Reserves:
January 1, 1991 . . . . . . . . . . . . . . . . . . . . 19,245 1,035,898
December 31, 1991 . . . . . . . . . . . . . . . . . . . 17,763 974,031
December 31, 1992 . . . . . . . . . . . . . . . . . . . 13,552 675,844
December 31, 1993 . . . . . . . . . . . . . . . . . . . 14,249 734,077
Less 1% general partners' interest in EPO . . . . . . . 142 7,341
------- ----------
Net. . . . . . . . . . . . . . . . . . . . . 14,107 726,736
======= ==========
Included in oil reserve estimates are natural gas liquids for leaseold
interest of 931 MBbl for 1993; 789 MBbl for 1992; and 743 MBbl for 1991.
A-22
Results of Operations for Producing Activities (excluding corporate
overhead and interest costs) - are as follows:
1993 1992 1991
-------- -------- ---------
Revenues . . . . . . . . . . . . . . . . . . $186,224 $164,634 $173,011
Production Costs. . . . . . . . . . . . . . . 45,684 43,132 48,374
Exploration Costs (1) . . . . . . . . . . . . 6,276 8,128 9,752
Depreciation and Amortization . . . . . . . . 75,917 74,378 71,599
Write-down of Gas and Oil Properties (2). . . 51,480
-------- -------- --------
Net . . . . . . . . . . . . . . . . . . . $ 58,347 $ 38,996 $ (8,194)
======== ======== ========
- ----------
<FN>
(1) Includes internal costs that cannot be directly identified with acquisition,
exploration or development activities.
(2) Excludes a $16,335 noncash write-off in 1992 of an idle pipeline and shallow-
water production facility from an abandoned offshore project.
Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Gas and Oil Reserve Quantities (Unaudited) - has been prepared by EP
using estimated future production rates and associated production and
development costs. Continuation of economic conditions existing at the balance
sheet date was assumed. Accordingly, estimated future net cash flows were
computed by: applying prices in contracts in effect in December to estimated
future production of proved gas and oil reserves; estimating future expend-
itures to develop proved reserves; and estimating costs to produce the proved
reserves based on average costs for the year. Average prices used in the
computations were:
1993 1992 1991
------ ------ ------
Natural Gas (per Mcf). . . . . . . . $ 2.38 $ 2.18 $ 2.03
Oil (per Bbl). . . . . . . . . . . . 11.68 18.16 18.35
Because of the imprecise nature of reserve estimates and the unpredictable
nature of other variables used, the standardized measure should be interpreted
as indicative of the order of magnitude only and not as precise amounts.
A-23
1993 1992 1991
------- -------- --------
(In millions)
Future Cash Inflows . . . . . . . . . . . . . . . $3,031.6 $3,056.4 $3,041.7
Future Production and Development Costs . . . . . 1,042.8 1,039.3 980.6
-------- -------- --------
Future Net Cash Flows . . . . . . . . . . . . . . 1,988.8 2,017.1 2,061.1
Less 10% Annual Discount. . . . . . . . . . . . . 886.4 908.7 1,000.7
-------- -------- --------
Standardized Measure of Discounted Future
Net Cash Flows. . . . . . . . . . . . . . . . . 1,102.4 1,108.4 1,060.4
Less 1% General Partners' Interest in EPO . . . . 11.0 11.1 10.6
-------- -------- --------
Net . . . . . . . . . . . . . . . . . . . . . . $1,091.4 $1,097.3 $1,049.8
======== ======== ========
The following table sets forth an analysis of changes in the standardized
measure of discounted future net cash flows from proved gas and oil reserves:
1993 1992 1991
------- ------- -------
(In millions)
Sales and Transfers of Gas and Oil Produced,
Net of Production Costs . . . . . . . . . . . . . $(135.6) $(114.5) $(116.0)
Changes in Prices, Net of Production and
Future Development Costs. . . . . . . . . . . . . 3.6 20.7 (252.4)
Extensions, Discoveries, and Improved
Recovery, Less Related Costs. . . . . . . . . . . 41.4 22.3 47.4
Purchase of Minerals in Place . . . . . . . . . . . 9.4 .9 84.8
Revisions of Previous Quantity Estimates. . . . . . (29.6) 16.4 (38.3)
Sale of Minerals in Place . . . . . . . . . . . . . (4.9) (.7)
Accretion of Discount . . . . . . . . . . . . . . . 105.1 102.4 110.3
Other . . . . . . . . . . . . . . . . . . . . (.3) 4.7 (4.0)
Less 1% General Partners' Interest in EPO . . . . . (.1) .5 1.7
------- ------- -------
Net. . . . . . . . . . . . . . . . . . . $ (5.9) $ 47.5 $ 167.2
======= ======= =======
A-24
ENSERCH EXPLORATION PARTNERS, LTD.
DEPOSITARY UNIT MARKET PRICES AND DISTRIBUTION INFORMATION
Market Prices
EP's Depositary Units evidenced by Depositary Receipts are traded on the
New York Stock Exchange. The following table shows the high and low sales
prices per unit reported in the New York Stock Exchange - Composite Transactions
report for the periods shown, as quoted in The Wall Street Journal.
1993 1992 1991
--------------- ---------------- -----------------
High Low High Low High Low
------- ------ -------- ------ ------ --------
First Quarter . . . . . . $ 9 1/4 $ 7 3/8 $ 7 1/4 $ 6 1/4 $ 8 3/4 $ 7 3/4
Second Quarter. . . . . . 9 3/4 8 1/2 7 5/8 7 10 8 1/8
Third Quarter . . . . . . 10 3/8 8 1/8 7 3/4 6 5/8 10 8
Fourth Quarter. . . . . . 12 1/4 10 1/8 8 1/4 7 1/4 10 6 1/2
Depositary Unit Data
1993 1992 1991
------- -------- -------
Unitholders of Record at Yearend. . . . . 1,224 1,339 1,517
Units Outstanding at Yearend. . . . . . . 805,914 805,914 805,914
<FN>
(Excludes 101,694,162 limited partnership units held by ENSERCH and an ENSERCH
affiliate).
Distributions Per Unit
In February 1994, the Board of Directors of EEI, managing general
partner of EP, announced that the quarterly cash distributions to unitholders
had been indefinitely suspended. Reinstatement of a cash distribution will
depend on a number of considerations, including future cash flows and capital
spending requirements. The following table shows the distributions per limited
partnership unit paid by EP during 1993, 1992 and 1991.
1993 1992 1991
----- ----- -----
First Quarter . . . . . . . . . . . . . . . . . $.075 $.075 $.075
Second Quarter. . . . . . . . . . . . . . . . . .075 .075 .075
Third Quarter . . . . . . . . . . . . . . . . . .075 .075 .075
Fourth Quarter. . . . . . . . . . . . . . . . . .075 .075 .075
----- ----- -----
Total. . . . . . . . . . . . . . . . . . . $.300 $.300 $.300
===== ===== =====
A-25
APPENDIX B
ENSERCH EXPLORATION PARTNERS, LTD.
INDEX TO FINANCIAL STATEMENT SCHEDULES
December 31, 1993
Page
Independent Auditors' Report . . . . . . . . . . B-2
Financial Statement Schedules for Each of the Three
Years in the Period Ended December 31, 1993:
IV - Indebtedness to Related Parties. . . . B-3
V - Property, Plant and Equipment. . . . . B-4
VI - Accumulated Depreciation and
Amortization of Property,
Plant and Equipment. . . . . . . . . . B-5
X - Supplementary Statements of Operations
Information. . . . . . . . . . . . . . B-6
B-1
INDEPENDENT AUDITORS' REPORT
To the Partners of Enserch Exploration Partners, Ltd.:
We have audited the financial statements of Enserch Exploration Partners,
Ltd. as of December 31, 1993 and 1992, and for each of the three years in the
period ended December 31, 1993, and have issued our report thereon dated
February 7, 1994; such report is included elsewhere in this Form 10-K. Our
audits also included the financial statement schedules of Enserch Exploration
Partners, Ltd. listed in Item 14. These financial statement schedules are the
responsibility of the Partnership's management. Our responsibility is to
express an opinion based on our audits. In our opinion, such financial
statement schedules, when considered in relation to the basic financial
statements taken as a whole, present fairly in all material respects the
information set forth therein.
DELOITTE & TOUCHE
Dallas, Texas
February 7, 1994
B-2
ENSERCH EXPLORATION PARTNERS, LTD.
SCHEDULE IV - INDEBTEDNESS TO RELATED PARTIES
For the Years Ended December 31
Balance at Balance
Beginning at End
Name of Person of Year Additions Deductions of Year (1)
- -------------- ---------- --------- ---------- --------
(In thousands)
1993:
Enserch Processing
Partners, Ltd. $266,000 $ 32,000 $ $298,000
======== ======== ========= ========
1992:
Enserch Processing
Partners, Ltd. $234,000 $ 32,000 $ $266,000
======== ======== ========= ========
1991:
Enserch Processing
Partners, Ltd. $202,000 $ 32,000 $ $234,000
======== ======== ========= ========
- -----------------
<FN>
(1) See Note 3 of the Notes to Financial Statements appearing in Appendix A
for additional details of this indebtedness.
B-3
ENSERCH EXPLORATION PARTNERS, LTD.
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
For the Years Ended December 31
Balance at Balance
Beginning Additions at End
Classification of Year at Cost Retirements of Year
-------------- ---------- --------- ----------- --------
(In thousands)
1993:
Gas and Oil Properties . . . . . . . $1,737,708 $112,235 $ 46,362 $1,803,581
Other. . . . . . . . . . . . . . . . 4,782 1,145 (20) 5,947
---------- -------- -------- ----------
Total . . . . . . . . . . . . . $1,742,490 $113,380 $ 46,342 $1,809,528
========== ======== ======== ==========
1992:
Gas and Oil Properties . . . . . . . $1,807,140 $ 62,488 $131,920 $1,737,708
Other. . . . . . . . . . . . . . . . 4,064 735 17 4,782
---------- -------- -------- ----------
Total . . . . . . . . . . . . . $1,811,204 $ 63,223 $131,937 $1,742,490
========== ======== ======== ==========
1991:
Gas and Oil Properties . . . . . . . $1,773,175 $114,411 $ 80,446(1) $1,807,140
Other. . . . . . . . . . . . . . . . 3,467 720 123 4,064
---------- -------- -------- ----------
Total . . . . . . . . . . . . . $1,776,642 $115,131 $ 80,569 $1,811,204
========== ======== ======== ==========
- ---------------
<FN>
(1) Includes a $51,480 full-cost ceiling write-down charged to expense. See Note 2 of the
Notes to Financial Statements and the Financial Review appearing in Appendix A for
additional details.
B-4
ENSERCH EXPLORATION PARTNERS, LTD.
SCHEDULE VI - ACCUMULATED DEPRECIATION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
For the Years Ended December 31
Additions
Balance at Charged to Balance
Beginning Costs and Retire- at End
Classification of Year Expenses ments of Year
-------------- --------- ---------- ------- -------
(In thousands)
1993:
Gas and Oil Properties . . . . . . . . . $746,657 $75,917 $ 47,004 $775,570
Other. . . . . . . . . . . . . . . . . . 2,795 783 (69) 3,647
-------- ------- -------- --------
Total . . . . . . . . . . . . . . . $749,452 $76,700 $ 46,935 $779,217
======== ======= ======== ========
1992:
Gas and Oil Properties . . . . . . . . . $778,483 $90,712 $122,538 $746,657
Other. . . . . . . . . . . . . . . . . . 2,068 689 (38) 2,795
-------- ------- -------- --------
Total . . . . . . . . . . . . . . . $780,551 $91,401 $122,500 $749,452
======== ======= ======== ========
1991:
Gas and Oil Properties . . . . . . . . . $731,415 $71,599 $ 24,531 $778,483
Other. . . . . . . . . . . . . . . . . . 1,554 584 70 2,068
-------- ------- -------- --------
Total . . . . . . . . . . . . . . . $732,969 $72,183 $ 24,601 $780,551
======== ======= ======== ========
B-5
ENSERCH EXPLORATION PARTNERS, LTD.
SCHEDULE X - SUPPLEMENTARY STATEMENTS OF OPERATIONS INFORMATION
For the Years Ended December 31
Item 1993 1992 1991
------ ------ ------ -------
(In thousands)
Maintenance and Repairs. . . . . . . . . . . . . . . . . $ 4,233 $ 3,784 $ 4,070
======== ======= =======
Taxes, Other than Payroll:
Production and severance . . . . . . . . . . . . . . . $ 9,613 $ 9,131 $10,113
Ad valorem . . . . . . . . . . . . . . . . . . . . . . 4,874 5,157 5,137
Miscellaneous. . . . . . . . . . . . . . . . . . . . . (94) (284) 16
-------- ------- -------
Total . . . . . . . . . . . . . . . . . . . . . . $ 14,393 $14,004 $15,266
======== ======= =======
B-6