<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K/A
(NO. 1)
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported):
JULY 31, 1996
NOBLE AFFILIATES, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 0-7062 73-0785597
(State or other (Commission (IRS Employer
jurisdiction of File Number) Identification No.)
incorporation)
110 WEST BROADWAY
ARDMORE, OKLAHOMA 73401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(405) 223-4110
<PAGE> 2
NOBLE AFFILIATES, INC. FORM 8-K/A (NO.1)
On July 31, 1996, Samedan Oil Corporation ("Samedan"), a wholly owned
subsidiary of the Registrant, purchased all of the outstanding common stock of
Energy Development Corporation, a wholly owned indirect subsidiary of Public
Service Enterprise Group Incorporated (the "EDC Acquisition"). The EDC
Acquisition was reported by the Registrant in its Form 8-K (Date of Event: July
31, 1996) dated August 13, 1996, in accordance with the rules and regulations
of the Securities and Exchange Commission (the "Commission"). Pursuant to
Items 7(a)(4) and 7(b)(2) of Form 8-K, this Form 8-K/A (No. 1) is being filed
to amend the Registrant's Form 8-K to include the financial statements and pro
forma financial information required by Item 7 of Form 8-K. In addition, the
Registrant has included certain information as of July 31, 1996, the date of
the EDC Acquisition, unless otherwise specified, describing the principal
business and properties of EDC. As used herein, the "Company" refers to Noble
Affiliates, Inc. and its subsidiaries (including EDC), and "EDC" refers to
Energy Development Corporation and its subsidiaries.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Form 8-K/A (No. 1) includes "forward-looking statements" within
the meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of
historical facts included in this Form 8-K/A (No. 1), including without
limitation, statements regarding the Registrant's estimates of oil and gas
reserves and future net cash flows attributable thereto, anticipated capital
expenditures, business strategy, plans and objectives of management of the
Registrant for future operations and industry conditions, are forward-looking
statements. Although the Registrant believes that the expectations reflected
in such forward-looking statements are reasonable, it can give no assurance
that such expectations will prove to have been correct. Important factors that
could cause actual results to differ materially from the Registrant's
expectations ("Cautionary Statements") include, without limitation, future
production levels, future prices and demand for oil and gas, results of future
exploration and development activities, future operating and development costs,
the effect of existing and future laws and governmental regulations (including
those pertaining to the environment), and the political and economic climate of
the United States and the foreign countries in which the Registrant operates
from time to time, as discussed elsewhere in this Form 8-K/A (No. 1) and the
other documents of the Registrant filed with the Securities and Exchange
Commission. All subsequent written and oral forward-looking statements
attributable to the Registrant or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.
2
<PAGE> 3
Item 2. Acquisitions or Dispositions.
ENERGY DEVELOPMENT CORPORATION
EDC is an independent energy company which has been principally
engaged in the exploration for and production of crude oil and natural gas
since 1972. EDC's properties are located throughout the major oil and gas
producing basins of the United States, principally in the Gulf of Mexico and
onshore gulf coast of Louisiana and Texas, and internationally in Argentina and
the United Kingdom sector of the North Sea.
Quantities of oil, condensate and natural gas liquids are expressed in
this Report in barrels ("bbls"), thousands of barrels ("Mbbls") or millions of
barrels ("MMbbls"), and quantities of natural gas are expressed in thousands of
cubic feet ("Mcf"), millions of cubic feet ("MMcf") or billions of cubic feet
("Bcf"). As used herein, "Mcfe" means thousands of cubic feet of gas
equivalent, "MMcfe" means millions of cubic feet of gas equivalent and "Bcfe"
means billions of cubic feet of gas equivalent; and MMBTU's means millions of
British Thermal Units. Oil, condensate and natural gas liquids are converted
to gas equivalents using the ratio of six Mcf of natural gas to one barrel of
oil, condensate or natural gas liquids.
OIL AND GAS RESERVES
The following table sets forth information as to the estimated net
proved and proved developed reserves for EDC as of July 31, 1996, as prepared
by Samedan.
TOTAL PROVED AND PROVED DEVELOPED
RESERVES AS OF JULY 31, 1996
<TABLE>
<CAPTION>
GAS (BCF) OIL (MMBBLS)
------------------------- --------------------
<S> <C> <C>
Total Proved Reserves:
Domestic:
Offshore Gulf of Mexico . . . . . . . . . . 221.5 12.0
Onshore . . . . . . . . . . . . . . . . . . 150.5 4.0
---------- ----------
372.0 16.0
International . . . . . . . . . . . . . . . . . . 45.3 19.7
---------- ---------
417.3 35.7
========== =========
Total Proved Developed Reserves . . . . . . . . . . . . 363.4 27.5
========== =========
</TABLE>
In connection with the EDC Acquisition, Samedan's in-house engineers
prepared the reserve estimates set forth above. Prior to the closing of the
EDC Acquisition, Miller and Lents, Ltd., independent petroleum consultants
("Miller and Lents"), estimated EDC's proved reserves as of July 1, 1996. The
Miller and Lents reserve estimates are summarized below under "--Miller and
Lents Reserve Report."
After taking into account adjustments for EDC's production and
exploration and development activities during July 1996, there are no material
differences in the aggregate between such estimate of proved reserves prepared
by Miller and Lents and the estimate of proved reserves prepared by Samedan as
summarized above. With respect to the domestic offshore Gulf of Mexico proved
reserves, Samedan's estimate is higher than that of Miller and Lents due
principally to Samedan's consideration of recent discoveries reflected in its
estimate as of July 31, 1996 (as compared to Miller and Lents' estimate as of
July 1, 1996) and of information available to Samedan as the operator of certain
properties in which it acquired additional interests in the EDC Acquisition.
With respect to the domestic onshore proved reserves, Samedan's estimate is
lower than that of Miller and Lents due principally to Samedan's estimation of
higher abandonment costs associated primarily with the South Lake Arthur (South
Louisiana) properties and its consideration of recent operating performance
reflected in its estimate as of July 31, 1996 (as compared to Miller and Lents'
estimate as of July 1, 1996).
Because of the direct relationship between quantities of proved
undeveloped reserves and development plans, Samedan has assigned to undeveloped
locations only those reserves that will definitely be drilled, and only those
reserves assigned to the undeveloped portions of secondary or tertiary projects
that will definitely be developed have been included in proved reserves as
proved undeveloped reserves. EDC has interests in certain tracts that may have
additional hydrocarbon quantities that were not classified at the time of the
estimate as proved reserves because Samedan did not have definitive plans at
such time to drill or develop these tracts, but which tracts may be
reclassified as proved reserves in the future as a result of EDC's exploration
and development programs. Under
3
<PAGE> 4
the regulations of the Commission, a company may classify reserves as proved
undeveloped reserves, assuming they otherwise meet the Commission's criteria
for proved reserves, without regard to whether such company has definitive
plans to drill or develop such reserves.
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves. Oil and gas reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
precisely measured, and estimates of other engineers might differ materially
from the estimates set forth herein. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing and production
subsequent to the date of the estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered. In addition, estimates of EDC's proved
reserves are based on oil and gas prices and production and development costs
prevailing at the date of the estimate. Any significant variance in future
prices or costs could materially affect the estimated quantities of reserves
set forth in this Report.
MILLER AND LENTS RESERVE REPORT
The following table sets forth information as to estimated net proved
and proved developed reserves for EDC as of July 1, 1996, as prepared by Miller
and Lents.
TOTAL PROVED AND PROVED DEVELOPED
RESERVES AS OF JULY 1, 1996
<TABLE>
<CAPTION>
GAS (BCF) OIL (MMBBLS)
------------------------- ---------------------
<S> <C> <C>
Total Proved Reserves:
Domestic:
Offshore Gulf of Mexico . . . . . . . . . . 182.1 8.2
Onshore . . . . . . . . . . . . . . . . . . 201.3 7.3
---------- -----------
383.4 15.5
International . . . . . . . . . . . . . . . . . . 40.6 24.9
---------- ----------
424.0 40.5
========== ==========
Total Proved Developed Reserves . . . . . . . . . . . . 347.6 28.8
========== ==========
</TABLE>
In the Miller and Lents reserve report, proved undeveloped reserves were
assigned to the undrilled locations that satisfied the following conditions:
(i) the location was a direct offset to wells that have indicated commercial
production in the objective formation, (ii) it is reasonably certain that the
location was within the known proved productive limits of the objective
formation, (iii) the location conformed to existing well spacing regulations,
if any, and (iv) it was reasonably certain that the location would be
developed. Reserves for other undrilled locations were classified as proved
undeveloped only in those cases where interpretations of data from wells
indicated that the objective formation is laterally continuous and contains
commercially recoverable hydrocarbons at locations beyond direct offset
locations.
Miller and Lents has delivered to EDC a summary reserve report describing
Miller and Lents' review process and conclusions, a copy of which has been
filed as an exhibit to this Form 8-K/A (No. 1).
PRIMARY OPERATING AREAS
Offshore Gulf of Mexico. EDC owns economic interests in leases
covering 189 blocks in federal and state waters offshore Texas and Louisiana.
The majority of these interests lie in the shallower waters of the Gulf of
Mexico. Gulf of Mexico fields typically exhibit high initial production rates.
EDC's proved reserves in this region are estimated by Samedan, as of July 31,
1996, to be 294 Bcfe, or approximately 46 percent of EDC's total proved
reserves. EDC owns an interest in 121 platforms in these waters, 26 of which
are operated by EDC and six of which are operated by Samedan. Significant
producing properties in the Gulf of Mexico include Burrwood (South
4
<PAGE> 5
Pass), Vermilion block 370, Ship Shoal block 113, Eugene Island block 57,
Mississippi Canyon block 661/705 and Vermilion block 100. EDC owns working
interests ranging from 19 to 100 percent in the aforementioned properties and
operates Vermilion block 100. The acquisition of EDC's 21 percent interest in
Vermilion block 370, which is operated by Samedan, increases the Company's
working interest to 58 percent. Net daily production attributable to EDC's
producing platforms averaged 97 MMcf of gas and 4,300 bbls of oil for the first
six months of 1996, or approximately 44 percent of EDC's total average daily
production for such period.
Domestic Onshore. EDC owns 410 properties, including 140 producing
fields, in the coastal regions of Texas and Louisiana, the Permian Basin of
West Texas and other areas in Texas and Louisiana. EDC's proved reserves in
this region are estimated by Samedan, as of July 31, 1996, to be 125 Bcfe, or
approximately 20 percent of EDC's total proved reserves. Approximately 43
percent of the proved reserves in this region are attributable to seven
properties: South Lake Arthur (South Louisiana), Loma Vieja (West Texas),
Caspiana (Northwest Louisiana), Maurice (South Louisiana), Maurice North (South
Louisiana), McAllen Ranch (South Texas) and Gomez (West Texas). EDC owns
working interests in such properties ranging from 10 to 100 percent and acts as
operator for five of these properties.
EDC owns 305 properties, including 14 producing fields, in Kansas and
Oklahoma. These fields typically have long lived reserves. EDC's proved
reserves in this region are estimated by Samedan, as of July 31, 1996, to be 50
Bcfe, or approximately eight percent of EDC's total proved reserves.
Approximately 98 percent of the proved reserves in this region are attributable
to two properties, Guymon-Hugoton and Panoma. EDC has an average 35 percent
working interest in 146 wells in the Guymon-Hugoton field, which is located in
the largest gas field in North America. The Panoma Gas Area is operated by
EDC, with a working interest of 52 percent.
Net daily production attributable to the domestic onshore producing
properties averaged 100 MMcf of gas and 2,900 bbls of oil for the first six
months of 1996, or approximately 42 percent of EDC's total average daily
production for such period.
International. EDC's international reserves are located in Argentina
and the United Kingdom. EDC's international proved reserves are estimated by
Samedan, as of July 31, 1996, to be 163 Bcfe, or approximately 26 percent of
EDC's total proved reserves. In Argentina, the Company owns a 14 percent
working interest in the El Tordillo field, located in the San Jorge Basin of the
Chubut Province, approximately 1,000 miles south of Buenos Aires. The Company
holds an interest in 11 offshore production platforms in the United Kingdom
sector of the North Sea and four producing fields onshore in southern England.
The Company does not operate any of its United Kingdom or Argentinean
properties. Net daily production attributable to Argentina and the United
Kingdom averaged 9 MMcf of gas and 4,600 bbls of oil for the first six months
of 1996, or approximately 14 percent of EDC's total average daily production
for such period.
5
<PAGE> 6
ACREAGE DATA
The following table sets forth developed and undeveloped leasehold
acreage (including both leases and concessions) held by EDC as of December 31,
1995.
DEVELOPED AND UNDEVELOPED LEASEHOLD
ACREAGE AS OF DECEMBER 31, 1995
<TABLE>
<CAPTION>
DEVELOPED ACRES(1) UNDEVELOPED ACRES(2)
------------------------------------- -----------------------------
LOCATION GROSS(3) NET(4) GROSS(3) NET(4)
-------- ----------------- ----------------- ----------------- ----------
<S> <C> <C> <C> <C>
Domestic:
Offshore Gulf of Mexico . . . 335,488 111,338 222,890 125,245
Onshore . . . . . . . . . . . 392,314 136,301 710,544 358,099
----------- ----------- ----------- -----------
727,802 247,639 933,434 483,344
International . . . . . . . . . . 162,820 10,826 7,325,956(5) 4,824,247(5)
----------- ------------ ----------- -----------
890,622 258,465 8,259,390(5) 5,307,591(5)
=========== =========== =========== ===========
</TABLE>
- -----------------
(1) Developed acreage is acreage spaced or assignable to productive wells.
(2) Undeveloped acreage is considered to be those lease acres on which
wells have not been drilled or completed to a point that would permit
the production of commercial quantities of oil and gas regardless of
whether or not such acreage contains proved reserves. Included within
undeveloped acreage are those lease acres (held by production under
the terms of a lease) that are not within the spacing unit containing,
or acreage assigned to, the productive well so holding such lease.
(3) A gross acre is an acre in which working interest is owned.
(4) A net acre is deemed to exist when the sum of fractional ownership
working interests in gross acres equals one. The number of net acres
is the sum of the fractional working interests owned in gross acres
expressed as whole numbers and fractions thereof.
(5) Includes a significant number of acres which to date have not been
thoroughly evaluated by Samedan subsequent to the EDC Acquisition.
The Company anticipates that the reported acreage may be subject to
reduction upon the conclusion of its evaluations.
As of December 31, 1995, EDC held royalty, overriding royalty and
other mineral interests in 37,663 net acres in addition to the developed and
undeveloped leasehold acreage indicated above.
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following table sets forth the number of gross and net exploratory
and development wells drilled by or on behalf of EDC for the periods indicated.
An exploratory well is a well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
A development well, for purposes of the following table and as defined in the
rules and regulations of the Commission, is a well drilled within the proved
area of an oil or gas reservoir to the depth of a stratigraphic horizon known
to be productive. The number of wells drilled refers to the number of wells
completed at any time during the respective year, regardless of when drilling
was initiated; and "completion" refers to the installation of permanent
equipment for the production of oil or gas, or, in the case of a dry hole, to
the reporting of abandonment to the appropriate agency.
6
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<TABLE>
<CAPTION>
EXPLORATORY WELLS
-------------------------------------------------------------------------------
PRODUCTIVE(1) DRY(2)
--------------------------------------- --------------------------------------
DOMESTIC INTERNATIONAL DOMESTIC INTERNATIONAL
YEAR ENDED ------------------ ------------------ ------------------ ------------------
DECEMBER 31, GROSS NET GROSS NET GROSS NET GROSS NET
----------- -------- -------- ------- -------- -------- -------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1993 . . . . . . . . . . . . . 5 2.41 -- -- 7 3.51 -- --
1994 . . . . . . . . . . . . . 6 3.84 -- -- 12 4.99 2 .62
1995 . . . . . . . . . . . . . 11 4.27 -- -- 9 6.29 2 .13
</TABLE>
<TABLE>
<CAPTION>
DEVELOPMENT WELLS
-------------------------------------------------------------------------------
PRODUCTIVE(1) DRY(2)
--------------------------------------- --------------------------------------
DOMESTIC INTERNATIONAL DOMESTIC INTERNATIONAL
YEAR ENDED ------------------ ------------------ ------------------ ------------------
DECEMBER 31, GROSS NET GROSS NET GROSS NET GROSS NET
----------- -------- -------- ------- -------- -------- -------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1993 . . . . . . . . . . . . . 35 9.68 5 .34 4 2.25 -- --
1994 . . . . . . . . . . . . . 46 11.41 13 1.04 5 1.93 1 .11
1995 . . . . . . . . . . . . . 34 10.37 14 1.69 4 1.69 -- --
</TABLE>
- -----------------
(1) A productive well is an exploratory or a development well that is not
a dry hole.
(2) A dry hole is an exploratory or a development well found to be
incapable of producing either oil or gas in sufficient quantities to
justify completion as an oil or gas well.
EDC does not own any drilling rigs and all of its drilling activities
are conducted by independent contractors under standard drilling contracts.
PRODUCTIVE WELLS
The following table sets forth the number of productive oil and gas
wells in which EDC had interests as of December 31, 1995.
<TABLE>
<CAPTION>
PRODUCTIVE WELLS(1)(2)
------------------------------------------------------------------
OIL GAS
---------------------------------- ------------------------------
LOCATION GROSS(3) NET(4) GROSS(3) NET(4)
-------- ---------------- ---------------- ---------------- -----------
<S> <C> <C> <C> <C>
Domestic:
Offshore Gulf of Mexico . . . . . . 148 86 482 150
Onshore . . . . . . . . . . . . . . 3,469 184 570 222
------- -------- --------- ---------
3,617 270 1,052 372
International . . . . . . . . . . . . . 502 45 30 2
-------- --------- --------- ----------
4,119 315 1,082 374
======== ========= ======== =========
</TABLE>
- -----------------
(1) Productive wells are producing wells and wells capable of production.
(2) One or more completions in the same bore hole is counted as one well.
Included in the table and counted as one gross well each are 12 gross
oil wells (5 net) and 52 gross gas wells (22 net) that are multiple
completions. Also included in the table are 1,464 gross oil wells
(126 net) and 392 gross gas wells (125 net) that were not producing at
December 31, 1995 because such wells were awaiting additional action
or pipeline connections.
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<PAGE> 8
(3) A gross well is a well in which a working interest is owned.
The number of gross wells is the total number of wells in
which a working interest is owned.
(4) A net well is deemed to exist when the sum of fractional
ownership working interests in gross wells equals one. The
number of net wells is the sum of the fractional working
interests owned in gross wells expressed as whole numbers and
fractions thereof.
VOLUME, PRICES AND PRODUCTION COSTS
The following table sets forth for the periods indicated certain
information regarding EDC's average daily production volumes, average sales
prices (including transfers) per unit produced and average production (lifting)
cost per unit of production.
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED
-------------------------------------------- JUNE 30,
1993 1994 1995 1996
-------------- ------------- ------------ --------------
<S> <C> <C> <C> <C>
Average daily production:
Natural gas (MMcf) . . . . . . . . . . . 262 228 205 205
Oil and condensate (Mbbls) . . . . . . . 10 11 11 12
Gas equivalent (MMcfe) . . . . . . . . . 325 295 271 276
Average sales price:
Natural gas (per Mcf)(1) . . . . . . . . $ 2.20 $ 1.98 $ 1.78 $ 2.19
Oil and condensate (per bbl)(2) . . . . $ 16.23 $ 15.03 $ 16.61 $ 16.06
Average production (lifting) cost per unit
of oil and natural gas production,
excluding depreciation (per Mcfe) . . $ .44 $ .50 $ .49 $ .50
</TABLE>
- -----------------
(1) Includes the effect of hedging transactions. The amounts shown reflect
an increase of $.05 per Mcf for 1993, an increase of $.05 per Mcf for
1995 and a decrease of $.36 per Mcf for the six months ended June 30,
1996, due to hedging transactions.
(2) Includes the effect of hedging transactions. The amounts shown reflect
an increase of $.04 per bbl for 1994, an increase of $.28 per bbl for
1995 and a decrease of $2.52 per bbl for the six months ended June 30,
1996, due to hedging transactions.
HEDGING ARRANGEMENTS
EDC had natural gas futures contracts which were sold and closed at
July 31, 1996 that hedged, at an average price of $1.89 per MMBTU, 513 million
MMBTU of gas for the period August 1996 through December 1996, or approximately
16 percent of EDC's expected gas production for such period. The net realized
deferred loss on these contracts at July 31, 1996 amounted to approximately
$1.45 million. EDC had crude oil futures contracts open and outstanding at
July 31, 1996 that hedged, at an average price of $19.45 per bbl, 1,775,000
bbls of oil for the period August 1996 through December 1996, or approximately
97 percent of EDC's expected oil production for such period. The net
unrealized deferred loss on these contracts at July 31, 1996 amounted to
approximately $1.59 million. The losses on these contracts actually realized,
if any, are expected to be offset by the higher cash proceeds received from the
hedged item when produced and sold. All future contracts outstanding at July
31, 1996 were New York Mercantile Exchange trade contracts. EDC also has crude
oil collar hedges for the period August 1996 through December 1996 for a total
of 1,355,000 bbls of oil with a floor price of $18.00 and a ceiling price of
$20.015 per bbl.
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<PAGE> 9
SEISMIC DATA
At July 31, 1996, EDC owned or held licenses covering 8,100 square
miles of 3-D seismic data and 252,000 linear miles of 2-D seismic data.
Certain of such licenses contain "change of control" provisions that will
require additional payments by the Company for the continued use of such
seismic data as a result of the EDC Acquisition. EDC owns a proprietary
interest in and will retain ownership of its rights to use approximately 10
percent of the 3-D seismic data and one percent of the 2-D seismic data.
OTHER ACTIVITIES
Ecuador Agreement. In July 1996, EDC entered into an agreement with
Petroecuador which grants EDC the exploration, production and commercial rights
with respect to approximately 864,000 gross acres in Block 3 offshore Ecuador.
Under this agreement, EDC is obligated to complete an exploration program by
July 2000, consisting of a 3-D seismic program and the drilling of four wells,
at an estimated aggregate cost of $45 million. The Company may seek to reduce
its interest under this agreement by obtaining one or more partners for this
prospect.
MANAGEMENT AND EMPLOYEES
Upon the closing of the EDC Acquisition, the directors and officers of
Samedan assumed similar positions as directors and officers of EDC.
At June 30, 1996, EDC had approximately 220 employees, 62 of whom were
terminated upon the closing of the EDC Acquisition. The remaining employees of
EDC will be terminated on October 31, 1996. Samedan expects to hire
approximately 90 additional employees as a result of the EDC Acquisition,
including certain former employees of EDC.
OTHER MATTERS
EDC is subject to the various competitive conditions, regulatory
requirements (including regulations pertaining to the environment) and
operating risks and hazards experienced by other independent energy companies.
Reference is made to the Company's Form 10-K for the year ended December 31,
1995 for a discussion of such matters.
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Item 7. Financial Statements and Exhibits.
(a) Financial Statements of Business Acquired.
Audited Consolidated Financial Statements of Energy Development
Corporation filed as part of this report:
- Report of Deloitte & Touche LLP, Independent Auditors
- Consolidated Statements of Income for the years ended
December 31, 1993, 1994 and 1995
- Consolidated Balance Sheets as of December 31, 1994 and 1995
- Consolidated Statements of Cash Flows for the years ended
December 31, 1993, 1994 and 1995
- Consolidated Statements of Changes in Stockholder's Equity
for the years ended December 31, 1993, 1994 and 1995
- Notes to Consolidated Financial Statements
Unaudited Consolidated Condensed Financial Statements of Energy
Development Corporation filed as part of this report:
- Consolidated Condensed Statements of Income for the six
months ended June 30, 1995 and 1996
- Consolidated Condensed Balance Sheet as of June 30, 1996
- Consolidated Condensed Statements of Cash Flows for the six
months ended June 30, 1995 and 1996
- Notes to Consolidated Condensed Financial Statements
(b) Pro Forma Financial Information.
Unaudited Pro Forma Consolidated Condensed Financial Statements of
Noble Affiliates, Inc. and subsidiaries filed as a part of this
report:
- Pro Forma Consolidated Condensed Statement of Operations for
the six months ended June 30, 1996 and the year ended
December 31, 1995
- Notes to the Pro Forma Consolidated Condensed Statement of
Operations
- Pro Forma Consolidated Condensed Balance Sheet as of June
30, 1996
- Notes to the Pro Forma Consolidated Condensed Balance Sheet
(c) Exhibits.
23.1 - Consent of Miller and Lents, Ltd.
23.2 - Consent of Deloitte & Touche LLP
99.1 - Summary Reserve Report on the estimated reserves of
EDC as of July 1, 1996, prepared by Miller and Lents,
Ltd., independent petroleum consultants
10
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
Date: September 27, 1996 NOBLE AFFILIATES, INC.
By: /s/ WILLIAM D. DICKSON
-------------------------------
William D. Dickson,
Vice President - Finance and Treasurer
11
<PAGE> 12
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
ENERGY DEVELOPMENT CORPORATION:
Consolidated Financial Statements (Audited):
Report of Deloitte & Touche LLP, Independent Auditors . . . . . . . . . . . . . . . F-2
Consolidated Statements of Income for the years ended December 31, 1993, 1994
and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3
Consolidated Balance Sheets as of December 31, 1994 and 1995 . . . . . . . . . . . . F-4
Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1994
and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5
Consolidated Statements of Changes in Stockholder's Equity for the years ended
December 31, 1993, 1994 and 1995 . . . . . . . . . . . . . . . . . . . . . . F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . F-7
Consolidated Condensed Financial Statements (Unaudited):
Consolidated Condensed Statements of Income for the six months ended June 30, 1995
and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-24
Consolidated Condensed Balance Sheet as of June 30, 1996 . . . . . . . . . . . . . . F-25
Consolidated Condensed Statements of Cash Flows for the six months ended
June 30, 1995 and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . F-26
Notes to Consolidated Condensed Financial Statements . . . . . . . . . . . . . . . . F-27
NOBLE AFFILIATES, INC. AND SUBSIDIARIES:
Pro Forma Consolidated Condensed Financial Statements (Unaudited):
Pro Forma Consolidated Condensed Statement of Operations for the six months
ended June 30, 1996 and the year ended December 31, 1995 . . . . . . . . . . F-29
Notes to the Pro Forma Consolidated Condensed Statement of Operations . . . . . . . F-30
Pro Forma Consolidated Condensed Balance Sheet as of June 30, 1996 . . . . . . . . . F-32
Notes to the Pro Forma Consolidated Condensed Balance Sheet . . . . . . . . . . . . F-33
</TABLE>
F-1
<PAGE> 13
INDEPENDENT AUDITORS' REPORT
Board of Directors of Energy Development Corporation:
We have audited the accompanying consolidated balance sheets of Energy
Development Corporation, a wholly owned subsidiary of Enterprise Diversified
Holdings Incorporated, and its subsidiaries ("EDC") as of December 31, 1994 and
1995, and the related consolidated statements of income, cash flows and changes
in stockholder's equity for each of the three years in the period ended
December 31, 1995. These financial statements are the responsibility of EDC'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 consolidated financial statements present fairly,
in all material respects, the financial position of EDC at December 31, 1994
and 1995, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1995 in conformity with generally
accepted accounting principles.
Deloitte & Touche LLP
Houston, Texas
February 16, 1996
(July 2, 1996 as to Notes 1 and 10)
F-2
<PAGE> 14
ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
(Dollars in Thousands)
<TABLE>
<CAPTION>
1993 1994 1995
--------- --------- ---------
<S> <C> <C> <C>
Operating revenues:
Gas and oil production $249,958 $208,544 $204,050
Gas sales to affiliated companies 20,158 11,179 0
Marketing, pipeline transportation and
other 8,354 10,157 8,918
Columbia bankruptcy settlement 0 0 35,034
--------- --------- ---------
Total operating revenues 278,470 229,880 248,002
Operating expenses:
Exploration 36,086 43,283 43,662
Lease operations 50,633 51,470 48,799
General and administrative 10,613 11,582 11,961
Depreciation, depletion and amortization 86,186 78,584 77,274
Other operations 6,384 8,087 8,120
--------- --------- ---------
Total operating expenses 189,902 193,006 189,816
Other income, net 2,596 4,728 22,132
Interest expense:
Interest on debt to affiliated companies 31,731 33,442 31,386
Other interest expense 217 294 469
Capitalized interest (3,124) (3,994) (4,369)
--------- --------- ---------
Total interest expense 28,824 29,742 27,486
--------- --------- ---------
Income before income taxes 62,340 11,860 52,832
Income taxes 19,963 858 18,088
--------- --------- ---------
Income before cumulative effect of
accounting change 42,377 11,002 34,744
Cumulative effect of change in accounting
for income taxes 1,612 0 0
--------- --------- ---------
Net income $ 43,989 $ 11,002 $ 34,744
========= ========= =========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
F-3
<PAGE> 15
ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 1994 AND 1995
(Dollars in Thousands)
<TABLE>
<CAPTION>
1994 1995
--------- ---------
<S> <C> <C>
Assets:
Current assets:
Cash and temporary cash investments $ 2,376 $ 14,269
Accounts receivable - net:
Trade 42,254 52,486
Affiliated companies 7,604 254
Prepaid items 5,127 22,747
Materials and supplies inventory 1,522 1,229
----------- ---------
Total current assets 58,883 90,985
Property, plant and equipment:
Property, plant and equipment, at cost (successful
efforts method) 1,324,867 1,393,471
Accumulated depreciation, depletion and
amortization (748,421) (786,920)
----------- ---------
Net property, plant and equipment 576,446 606,551
Other assets:
Accrued gas underdeliveries 19,353 12,761
Deferred taxes 32,134 0
Long term receivables 36,278 36,657
----------- ---------
Total other assets 87,765 49,418
----------- ---------
Total assets $ 723,094 $ 746,954
=========== =========
Liabilities and stockholder's equity:
Current liabilities:
Accounts payable and accruals:
Trade $ 57,718 $ 61,881
Affiliated companies 2,371 4,818
Notes payable to affiliated companies 365,421 311,821
----------- ---------
Total current liabilities 425,510 378,520
Deferred taxes 0 9,182
Deferred revenue 5,789 4,713
Commitments and contingencies (Note 6)
----------- ---------
Total liabilities 431,299 392,415
Stockholder's equity:
Common stock 920 920
Paid-in capital 399,780 427,780
Accumulated deficit (108,905) (74,161)
----------- ---------
Total stockholder's equity 291,795 354,539
----------- ---------
Total liabilities and stockholder's equity $ 723,094 $ 746,954
=========== =========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
F-4
<PAGE> 16
ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
(Dollars in Thousands)
<TABLE>
<CAPTION>
1993 1994 1995
----------- ---------- ---------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $43,989 $ 11,002 $ 34,744
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 86,186 78,584 77,274
Unproved leasehold impairment/abandonment 4,633 7,059 4,143
Gain on property sales (578) (1,438) (18,171)
Gas balancing 7,165 6,311 5,516
Deferred income taxes 9,427 5,048 41,316
Changes in current assets and current liabilities 19,373 (3,608) (7,410)
----------- ---------- ---------
Total adjustments 126,206 91,956 102,668
----------- ---------- ---------
Net cash provided by operating activities 170,195 102,958 137,412
Cash flows from investing activities:
Additions to property, plant and equipment (92,012) (159,544) (132,109)
Proceeds from property sales 895 6,780 32,569
Additions to/(reductions in) long term receivable 2,187 (4,165) (379)
----------- ---------- ---------
Net cash used by investing activities (88,930) (156,929) (99,919)
Cash flows from financing activities:
Proceeds from/(repayments of) borrowings (97,805) 58,056 (53,600)
Additions to paid-in capital 33,900 4,250 40,000
Dividends paid (15,600) (8,000) (12,000)
----------- ---------- ---------
Net cash provided/(used) by financing activities (79,505) 54,306 (25,600)
Net increase in cash and temporary cash investments 1,760 335 11,893
Cash and temporary cash investments - beginning of year 281 2,041 2,376
----------- ---------- ---------
Cash and temporary cash investments - end of year $ 2,041 $ 2,376 $ 14,269
=========== ========== =========
Changes in current assets and liabilities:
Accounts receivable $ 9,497 $ 15,500 $ 854
Prepaid items (902) (2,829) (17,620)
Materials and supplies inventories (482) 5 293
Accounts payable (795) (14,919) 2,596
Accrued taxes payable 1,554 (721) 212
Other current liabilities 10,501 (644) 6,255
----------- ---------- ---------
Total $ 19,373 $ (3,608) $ (7,410)
=========== ========== =========
Supplemental disclosure of cash flow information:
Cash paid for interest expense, net of capitalized
interest $ 29,030 $ 32,587 $ 24,754
Cash paid/(received) for income taxes $6,630 $ 10,253 $(30,786)
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
F-5
<PAGE> 17
ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
(Dollars in Thousands)
<TABLE>
<CAPTION>
1993 1994 1995
------------- ------------ --------------
<S> <C> <C> <C>
Common stock:
Common stock, $1,000 stated value;
authorized 7,500 shares, 920 shares
issued and outstanding in each of
1993, 1994 and 1995
Balance at beginning and end of year $ 920 $ 920 $ 920
Paid-in capital:
Balance at beginning of year 361,630 395,530 399,780
Capital contributions from EDHI 33,900 4,250 40,000
Dividends declared 0 0 (12,000)
------------- ------------ --------------
Balance at end of year 395,530 399,780 427,780
Accumulated deficit:
Balance at beginning of year (140,296) (111,907) (108,905)
Net income 43,989 11,002 34,744
Dividends declared (15,600) (8,000) 0
------------- ------------ --------------
Balance at end of year (111,907) (108,905) (74,161)
------------- ------------ --------------
Total stockholder's equity $284,543 $291,795 $354,539
============= ============ ==============
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
F-6
<PAGE> 18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Energy Development Corporation ("EDC") is a wholly owned subsidiary of
Enterprise Diversified Holdings Incorporated ("EDHI"), which is a wholly owned
subsidiary of Public Service Enterprise Group Incorporated ("Enterprise"). EDC
is engaged in the exploration for and the development, production and marketing
of gas and oil reserves, with principal operations both onshore and offshore in
states bordering the Gulf of Mexico and in the United Kingdom and Argentina.
See Note 10 regarding the sale of EDC by EDHI which is expected to be completed
on July 31, 1996.
Consolidated Subsidiaries
EDC has several wholly owned subsidiaries that are primarily involved
in the gathering and transporting of gas and oil by pipeline and in
international exploration and production activities. The consolidated
financial statements of EDC include the accounts of all subsidiaries. All
intercompany accounts and transactions have been eliminated in consolidation.
Property, Plant and Equipment
EDC uses the successful efforts method of accounting for its
investment in gas and oil operations. Under the successful efforts method,
unproved leasehold costs are capitalized and are not amortized pending an
evaluation of the exploration results. Unproved leasehold costs are assessed
quarterly to determine whether an impairment of the costs of significant
individual properties has occurred. The decision to impair and the amount
recorded is determined based upon both geological interpretations of EDC
employees and drilling activity on or near the leasehold interest. The cost of
an impairment is charged to expense in the period in which it occurs.
Exploratory dry holes, exploratory geological and geophysical and delay rental
costs are charged to expense as incurred. Proved leasehold costs are
capitalized and amortized over the proved developed and undeveloped reserves on
a unit-of-production basis. Drilling and equipping costs, except exploratory
dry holes, are capitalized and depreciated over the proved developed reserves
on a unit-of-production basis. Estimated future abandonment costs of offshore
properties are depreciated on a unit-of-production basis over the proved
developed reserves. Estimated future abandonment costs of onshore properties
are estimated to be offset by the salvage value of the tangible equipment. EDC
periodically assesses whether the cost of proved properties has been
permanently impaired, with any such impairment being charged to expense in the
period in which it occurs. Impairments of proved property during 1995, 1994
and 1993 were measured by comparing the world-wide undiscounted future net cash
flows to the net book value of the related assets. This test was also
performed at the field level, and impairment recorded, if it was determined
that the net book value could not be recovered from estimated future net cash
flows, and such condition was not temporary. The impairment was measured as
the excess of net book value over estimated future net cash flows. The
consolidated average rate of amortization per Mcfe, exclusive of proved
property impairments, was $0.7504 in 1995, $0.7319 in 1994 and $0.7105 in 1993.
Proved property impairments were $9,000 in 1994 and $1.3 million in 1993.
There were no proved property impairments in 1995.
During 1995, 1994 and 1993, EDC acquired 0.7 Bcfe, 68.1 Bcfe and 38.8
Bcfe, respectively, of proved gas and oil reserves for $0.4 million, $69.1
million and $16.1 million, respectively. The properties acquired were obtained
through several acquisitions and are primarily located in the United Kingdom,
Offshore Texas, and Offshore Louisiana.
F-7
<PAGE> 19
Financial Accounting Standards Board Statement No. 121
The Financial Accounting Standards Board has issued Statement No. 121
("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of." SFAS 121 is effective beginning January
1, 1996 and establishes guidelines for determining and measuring asset
impairment and the required timing of asset impairment evaluations. Management
has addressed the requirements of this statement and believes that it will not
have a significant effect on the financial condition and results of operations
of EDC based upon current economic conditions.
Capitalized Interest
Interest is capitalized in connection with unproved leasehold costs on
prospects. The capitalization rate used is based on the cost of funds
outstanding during the exploration period.
Materials and Supplies Inventory
Inventories are stated at the lower of cost or market. The cost of
inventories is determined using the average cost method.
Federal Income Taxes
EDC files a consolidated federal income tax return with EDHI and
Enterprise. EDC and Enterprise have entered into a tax allocation agreement
which provides that EDC will record its tax liability as though it were filing
a separate return and will record tax benefits to the extent that Enterprise is
able to receive those benefits. Deferred income taxes are provided for
differences between book and taxable income, resulting primarily from
differences in book and tax depletion and depreciation and the current
deduction for income tax purposes of intangible drilling costs.
Statement of Financial Accounting Standards No. 109 ("SFAS 109"),
"Accounting for Income Taxes," was issued by the Financial Accounting Standards
Board in February 1992. SFAS 109 required a change from an income statement
approach to a balance sheet approach of accounting for income taxes. Under the
balance sheet approach, deferred income taxes are recognized for the tax
consequences of "temporary differences" by applying enacted statutory tax rates
applicable to current and future years to differences between the financial
statement carrying amounts and the tax basis of existing assets and
liabilities. Under SFAS 109, the effect on deferred taxes of a change in tax
rates is recognized in income in the period that includes the enactment date.
EDC's adoption of SFAS 109 in 1993 resulted in an increase of the
deferred tax asset by $1.6 million. The total effect on net income was a $1.6
million increase, which is reflected in the results of operations for 1993 as a
cumulative effect of change in accounting principle.
Joint Venture Operations
The terms of drilling agreements with several non-related parties
provide for EDC, as operator, to make expenditures in connection with joint
exploration and development ventures. Expenditures are billed to the partners
as costs are paid by EDC. These billings are included in Accounts Receivable.
Gas Balancing
EDC follows the entitlement method of accounting for gas balancing.
Gas out-of-balance conditions arise because each working interest owner in a
well has the right to a specific percentage of production. Under entitlement
accounting, EDC defers revenue when it sells more than its ownership percentage
in a given period and accrues a receivable from other owners when it sells less
than its ownership percentage.
F-8
<PAGE> 20
Natural Gas and Crude Oil Hedging
EDC has been authorized by its Board of Directors to use derivatives,
which may include futures contracts, options, commodity swaps and other
products, for the purpose of managing price risk related to natural gas and
crude oil sales and not for speculative purposes. For book purposes, gains and
losses related to the hedging of anticipated transactions are deferred and
recognized in income when the hedged transaction occurs.
Marketing Income
In addition to selling its own production, EDC sells gas and oil which
it purchases from various third parties. The revenues from these sales are
offset with the costs of purchasing the gas and oil and are included in
"Marketing, pipeline transportation and other" revenue in the Consolidated
Statements of Income.
Cash and Temporary Cash Investments
EDC classifies cash and investments with original maturities of three
months or less as cash and temporary cash investments.
Financial Instruments
EDC's financial instruments consist of cash and temporary cash
investments, receivables, payables and debt. As of December 31, 1995, the
estimated fair values of EDC's notes to PSEG Capital Corporation ("PSEG
Capital") and Enterprise Capital Funding Corporation ("EC Funding"), wholly
owned subsidiaries of EDHI, were approximately $160.5 million and $167.4
million, respectively. These estimated fair values were determined based on
the borrowing rates available at December 31, 1995 for debt with similar terms
and maturities. The carrying amount of EDC's other financial instruments
approximates fair value.
Currency Translation
The US dollar is the functional currency for EDC's consolidated
operations. Substantially all foreign revenues and expenses are denominated in
US dollars.
Use of Estimates
The process of preparing financial statements in conformity with
generally accepted accounting principles requires the use of estimates and
assumptions regarding certain types of assets, liabilities, revenues and
expenses. Such estimates primarily relate to unsettled transactions and events
as of the date of the financial statements. Accordingly, upon settlement,
actual results may differ from estimated amounts.
Reclassifications
Certain amounts have been reclassified to conform with the current
period's presentations.
2. STOCKHOLDER'S EQUITY
Common Stock
EDC had 920 shares of no-par common stock issued and outstanding as of
December 31, 1995, 1994 and 1993, with a stated value of $1,000 per share. The
total authorized amount as of December 31, 1995 was 7,500 shares.
F-9
<PAGE> 21
Paid-in Capital
In 1995, EDHI made equity contributions of $28 million to EDC, net of
dividends paid by EDC from paid-in capital of $12 million. EDC used these funds
primarily to reduce debt. In 1994, EDHI made equity contributions of $4.3
million to EDC. In 1993, EDHI made equity contributions of $33.9 million to
EDC. EDC used these funds primarily to finance the acquisition of Brabant
Resources plc and to reduce EDC's debt.
Dividends
In 1995, EDC paid dividends to EDHI of $12 million, which were
declared from paid-in capital. In 1994 and 1993, EDC paid dividends to EDHI of
$8.0 million and $15.6 million, respectively, which were declared from retained
earnings.
3. INCOME TAXES
Income from continuing operations before income taxes is as follows:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
($ in millions)
1993 1994 1995
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
US $69.8 $13.8 $ 49.3
Foreign (7.5) (1.9) 3.5
-------------------------------------------------------------------------------------------------
Total $62.3 $11.9 $ 52.8
=================================================================================================
</TABLE>
The components of taxes on income from continuing operations are summarized as
follows:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
($ in millions)
1993 1994 1995
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Current:
US federal $ 7.7 $(3.8) $(24.4)
Foreign .9 .2 .5
State .4 (.5) .7
-------------------------------------------------------------------------------------------------
Total current 9.0 (4.1) (23.2)
-------------------------------------------------------------------------------------------------
Deferred:
US federal 10.8 5.6 40.3
Foreign .2 .3 .8
State .0 (.9) .2
-------------------------------------------------------------------------------------------------
Total deferred 11.0 5.0 41.3
-------------------------------------------------------------------------------------------------
Total income taxes $20.0 $ .9 $ 18.1
=================================================================================================
</TABLE>
F-10
<PAGE> 22
A reconciliation of income taxes calculated at the US federal
statutory rate of 35% of income before income taxes and the income tax
provision is as follows:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
($ in millions)
1993 1994 1995
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal income tax
expense at statutory rate $21.8 $4.2 $18.5
Foreign taxes for
which benefits are not recognized 2.4 (0.2) 0.0
State income taxes, net of
federal income taxes 0.2 (1.6) 0.6
Tight gas sands tax credits (3.7) (1.6) (1.0)
Deferred income tax rate 1% change (0.8) 0.0 0.0
Other 0.1 0.1 0.0
-------------------------------------------------------------------------------------------------
Income tax expense $20.0 $ 0.9 $18.1
=================================================================================================
</TABLE>
As discussed in Note 1, Summary of Significant Accounting Policies,
EDC adopted SFAS 109 as of the beginning of 1993, which increased earnings by
$1.6 million, and is reported separately in the Consolidated Statements of
Income.
The federal deferred tax liability at December 31, 1995 and federal
deferred tax asset at December 31, 1994 are primarily composed of the
difference between the tax and the book basis of property, plant and equipment.
The state deferred tax asset is primarily composed of the effects of Louisiana
net operating loss expected to be utilized.
At December 31, 1995, EDC had approximately $56 million in net
operating loss carryforwards expiring from 2003 to 2010 available to offset
future state taxable income. Included in the deferred tax liability at
December 31, 1995 and the deferred tax asset at December 31, 1994 is a deferred
state tax asset of $4.4 million that is primarily composed of the difference
between the tax and the book basis of the property, plant and equipment and
state tax net operating loss carryforward. The valuation allowance related to
the deferred state tax asset was $2.4 million at both December 31, 1995 and
1994 and resulted from the uncertainty of the utilization of state tax net
operating loss carryforward to reduce future taxable income.
F-11
<PAGE> 23
The significant components of accumulated deferred income taxes -
non-current attributable to income from continuing operations were as follows:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
($ in millions)
1994 1995
-------------------------------------------------------------------------------------------------
<S> <C> <C>
DEFERRED TAX ASSETS:
Property and leasehold costs $ 27.9 $ 35.7
Excess of book over tax depreciation,
depletion and amortization 195.1 191.1
Federal alternative minimum tax credit
carryforward(1) 28.6 19.4
Other 1.7 1.1
-------------------------------------------------------------------------------------------------
TOTAL DEFERRED TAX ASSETS 253.3 247.3
-------------------------------------------------------------------------------------------------
DEFERRED TAX LIABILITIES:
Property, plant and equipment 26.5 30.3
Exploration and intangible well drilling costs 188.5 211.1
Investments in partnership, due to difference
in depreciation 1.5 1.5
Disposition of assets, book/tax difference 3.0 2.5
Other 1.7 11.1
-------------------------------------------------------------------------------------------------
TOTAL DEFERRED TAX LIABILITIES 221.2 256.5
-------------------------------------------------------------------------------------------------
TOTAL NET DEFERRED TAX LIABILITIES/(ASSETS) $ (32.1) $ 9.2
=================================================================================================
</TABLE>
(1) Available to reduce future U.S. federal income taxes over an indefinite
period.
4. RELATED PARTY TRANSACTIONS
PSE&G
In 1993 and through September 30, 1994, EDC supplied and transported
gas for PSE&G. The New Jersey Board of Public Utilities ("BPU") regulates the
rates of PSE&G and its ability to recover from its customers the price paid to
EDC for gas. The price received from PSE&G was determined each month and
included two components: a commodity rate and a monthly demand charge. The
commodity rate generally reflected the current month's spot market price for
gas delivered at the wellhead. The monthly demand charge was fixed and added
to the commodity rate. In accordance with a BPU ruling, PSE&G ceased gas
purchases from EDC as of September 30, 1994. As a result, gas transportation
services provided to PSE&G also ceased. EDC has incurred no problems in
finding a market for the production that would have been sold to PSE&G after
September 1994. EDC's operating revenues include billings to PSE&G, net of
royalties paid to various unrelated parties, of approximately $39.8 million and
$58.0 million for the years ended December 31, 1994 and 1993, respectively. Of
these amounts, $11.2 million and $20.2 million were sales of natural gas
produced by EDC and $1.5 million and $1.7 million were for gas transportation
services for the years ended December 31, 1994 and 1993, respectively. Also
included were
F-12
<PAGE> 24
$27.1 million and $36.1 million for gas sold to PSE&G that was purchased from
third parties by EDC at a cost of $25.3 million and $33.4 million for the years
ended December 31, 1994 and 1993, respectively.
Payroll and related fringe benefit costs of PSE&G employees and other
expenses incurred by PSE&G on behalf of EDC are billed on a monthly basis.
Such costs amounted to approximately $0.8 million, $0.7 million and $0.5
million for the years ended December 31, 1995, 1994 and 1993, respectively.
Employees of EDC who have completed one year of service become
participants in a non-contributory pension plan. This plan is administered by
PSE&G, and costs related to Company employees are billed on a monthly basis.
Such costs amounted to approximately $0.9 million, $0.8 million and $0.6
million for the years ended December 31, 1995, 1994 and 1993, respectively.
PSEG Capital, EC Funding
EDC has executed and delivered global demand promissory notes
evidencing unsecured loans from PSEG Capital and EC Funding. Each note
provides for borrowings at interest rates based upon the lender's average cost
of debt. The effective interest rates for borrowings from PSEG Capital and EC
Funding were 9.27% and 9.03%, respectively in 1995, 9.66% and 11.21%,
respectively in 1994, and 10.11% and 7.40%, respectively in 1993. Interest
expense incurred on the notes to PSEG Capital and EC Funding were $20.0 million
and $11.4 million, respectively in 1995, $23.0 million and $10.4 million,
respectively in 1994, and $20.9 million and $10.8 million, respectively in
1993. Borrowings under the notes to PSEG Capital and EC Funding were $152.3
million and $159.5 million, respectively at December 31, 1995, $238.9 million
and $126.5 million, respectively at December 31, 1994, and $218.2 million and
$89.2 million, respectively at December 31, 1993. Under EC Funding's borrowing
agreements, EDC must have a consolidated indebtedness to consolidated tangible
net worth ratio not to exceed 1.75:1.
Enterprise, EDHI
EDC was billed administrative overheads of $0.5 million, $0.4 million
and $0.3 million by Enterprise in 1995, 1994 and 1993, respectively. These
administrative overheads are allocated to EDC based upon EDC's percentage of
total Enterprise assets. EDC was billed administrative overheads of $1.8
million, $1.8 million and $1.9 million by EDHI in 1995, 1994 and 1993,
respectively. The administrative overheads are allocated to EDC based upon
EDC's percentage of total EDHI equity, excluding accumulated deficit, plus
contingent obligations.
Management believes these allocation methods are reasonable. However,
such allocated amounts may not be indicative of amounts incurred for these
expenses if EDC were a stand alone entity.
Entech Enterprises, Inc.
During 1989, EDC entered into an incentive compensation agreement with
Entech Enterprises, Inc. ("Entech"), whose president was also the president of
EDC and a member of EDC's Board of Directors from January 1, 1989 until
December 19, 1994. The incentive compensation agreement is in the form of a
Participation Agreement, as amended ("Agreement"). Under the Agreement, Entech
is entitled to a 5% interest in all new properties, which are primarily
properties acquired by EDC subsequent to January 1, 1989 and prior to December
31, 1993. EDC advances for the benefit of Entech and pays 100% of Entech's
obligations with respect to all new properties' costs. Interest accrues on
these advances at a rate of Chase Manhattan Bank prime plus one percent until
such advances are repaid. EDC looks solely to Entech's interest in the
conveyed properties and the proceeds therefrom for the repayment of all
advances and interest. Advances and interest are repaid monthly in
installments equal to 97% of Entech's Net Cash Flow attributable to the
preceding month for those new properties. The remaining 3% of Entech's Net
Cash Flow is distributed to Entech by EDC. New properties' costs advanced to
Entech during 1995, 1994 and 1993 were approximately $1.1 million, $8.7 million
and $4.6 million, respectively. Interest income attributable to 1995, 1994 and
1993 was approximately $3.2 million, $2.8 million and $2.2 million,
respectively. Net Cash Flow was sufficient to pay all accrued interest as of
December 31, 1995. In addition, Net Cash Flow attributable to repayment of the
advance in 1995, 1994 and 1993 was $0.4 million, $4.6 million and $6.8
F-13
<PAGE> 25
million, respectively. The advance balance outstanding was $36.7 million,
$36.0 million and $31.8 million at December 31, 1995, 1994 and 1993,
respectively.
5. NATURAL GAS AND CRUDE OIL HEDGING
EDC utilizes natural gas and crude oil options and futures contracts
in order to limit EDC's exposure to downward price swings on natural gas and
crude oil sales and to protect targeted price levels. EDC had natural gas
futures contracts sold and outstanding that hedged 21.1 million and 10.7
million MMBTU at December 31, 1995 and 1994, respectively at an average price
of $1.93 and $1.95 per MMBTU, respectively. At December 31, 1995, EDC had sold
and outstanding crude oil futures contracts which hedged 1.5 million barrels at
an average price of $17.74 per barrel. All contracts outstanding at December
31, 1995 and 1994 were New York Mercantile Exchange traded contracts. EDC had
no outstanding natural gas or crude oil hedge positions at December 31, 1993.
These contracts are accounted for as hedges for book purposes, and accordingly,
gains and losses are deferred until the related sales are made. The net
unrealized deferred loss on outstanding contracts at December 31, 1995 was $5.1
million. The losses actually realized on these contracts, if any, are expected
to be offset by the higher cash proceeds received from the hedged item when
produced and sold.
6. COMMITMENTS AND CONTINGENCIES
EDC is a party to lawsuits and claims arising in the ordinary course
of business. EDC believes, based on its current knowledge and the advice of
its counsel, that all such lawsuits and claims would not have a material
adverse effect on its financial condition, results of operations and cash
flows.
EDC has operating leases which expire over the next five years with
aggregate future minimum lease payments totaling $6.4 million. Minimum lease
payments during the next five years for leases having initial or remaining
terms in excess of one year are as follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------
($ in millions)
---------------------------------------------------------------------------------
<S> <C>
1996 $1.8
1997 2.2
1998 2.0
1999 .2
2000 .2
---------------------------------------------------------------------------------
Total minimum lease payments $6.4
=================================================================================
</TABLE>
Rent expense for 1995, 1994 and 1993 was approximately $2.3 million, $2.3
million and $1.8 million, respectively.
7. COLUMBIA GAS TRANSMISSION COMPANY ("COLUMBIA") BANKRUPTCY SETTLEMENT
Columbia filed for protection from its creditors in July 1991 under
Chapter 11 of the bankruptcy laws. EDC was an initial creditor because
Columbia breached a take-or-pay natural gas purchase contract. Columbia
subsequently rejected EDC's contract shortly after its bankruptcy filing.
Columbia's Plan of Reorganization ("Plan") was approved in November 1995 and
EDC received a distribution of $36.1 million under the Plan in the same month.
Of the amount received, $35.0 million was included in 1995 operating revenues.
F-14
<PAGE> 26
8. GEOGRAPHIC DATA
Operating revenues, income before income taxes and identifiable assets
by geographic area were as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
($ in millions)
1993 1994 1995
--------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues:
United States $259.9 $197.1 $206.9
United Kingdom 10.8 26.0 33.2
Other foreign 7.8 6.8 7.9
--------------------------------------------------------------------------------------
Operating revenues $278.5 $229.9 $248.0
======================================================================================
Income before income taxes:
United States $ 95.9 $ 38.6 $ 71.6
United Kingdom (.2) 3.7 8.0
Other foreign (4.6) (.7) .7
--------------------------------------------------------------------------------------
91.1 41.6 80.3
Interest expense (28.8) (29.7) (27.5)
--------------------------------------------------------------------------------------
Income before income taxes $ 62.3 $ 11.9 $ 52.8
======================================================================================
Identifiable assets:
United States $621.4 $625.4 $644.6
United Kingdom 20.8 62.6 65.8
Other foreign 33.2 35.1 36.6
--------------------------------------------------------------------------------------
Identifiable assets $675.4 $723.1 $747.0
======================================================================================
</TABLE>
9. QUARTERLY RESULTS (UNAUDITED)
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
($ in millions)
Quarter Ended
March 31 June 30 September 30 December 31
---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1994:
Revenues $65.7 $58.1 $55.0 $51.1
Operating income 19.6 8.6 2.0 6.7
Net income/(loss) 8.5 1.8 (2.8) 3.5
1995:
Revenues $48.1 $54.8 $49.7 $95.4
Operating
income/(loss) 5.7 5.4 (1.0) 48.1
Net income/(loss) .1 .1 (2.3) 36.8
---------------------------------------------------------------------------------------------
</TABLE>
During the fourth quarter of 1995, EDC recorded the settlement of the
Columbia bankruptcy which increased revenues and operating income by $35.0
million and net income by $22.8 million. During the same quarter, EDC sold
property and realized a gain which increased net income by $9.1 million.
F-15
<PAGE> 27
10. SUBSEQUENT EVENTS
On December 6, 1995, Enterprise announced that it intended to pursue
divestiture of its ownership interest in EDC. In connection with the planned
divestiture, EDC declared dividends of $100 million and $75 million on January
31, 1996 and April 15, 1996, respectively. The dividends were funded by
additional intercompany indebtedness of $175 million.
On July 1, 1996, EDHI entered into an agreement to sell all of the
outstanding common stock of EDC to Samedan Oil Corporation, a wholly owned
subsidiary of Noble Affiliates, Inc. The sale is expected to be completed on
July 31, 1996.
F-16
<PAGE> 28
SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (UNAUDITED)
Capitalized Costs Relating to Gas and Oil Producing Activities
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
($ in millions)
United United Other
States Kingdom Argentina Foreign Total
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
- ----------------------------------------------------------------------------------------------------------------
December 31, 1993
Unproved properties,
not being amortized $ 51.2 $ 1.9 $ 0.0 $ 0.6 $ 53.7
Proved properties 1,075.9 17.9 26.7 0.0 1,120.5
- ----------------------------------------------------------------------------------------------------------------
Total capitalized costs 1,127.1 19.8 26.7 0.6 1,174.2
Less accumulated
depreciation, depletion
and amortization 673.4 3.2 2.0 0.0 678.6
- ----------------------------------------------------------------------------------------------------------------
Net capitalized costs (a) $ 453.7 $ 16.6 $ 24.7 $ 0.6 $ 495.6
================================================================================================================
December 31, 1994
Unproved properties,
not being amortized $ 63.6 $ 4.1 $ 0.2 $ 0.0 $ 67.9
Proved properties 1,141.6 56.2 28.3 0.0 1,226.1
- ----------------------------------------------------------------------------------------------------------------
Total capitalized costs 1,205.2 60.3 28.5 0.0 1,294.0
Less accumulated
depreciation, depletion and
amortization 714.0 12.1 3.1 0.0 729.2
- ----------------------------------------------------------------------------------------------------------------
Net capitalized costs (a) $ 491.2 $ 48.2 $ 25.4 $ 0.0 $ 564.8
================================================================================================================
December 31, 1995
Unproved properties,
not being amortized $ 71.5 $ 3.4 $ 0.2 $ 2.4 $ 77.5
Proved properties 1,188.5 62.1 32.8 0.0 1,283.4
- ----------------------------------------------------------------------------------------------------------------
Total capitalized costs 1,260.0 65.5 33.0 2.4 1,360.9
Less accumulated
depreciation, depletion and
amortization 740.5 20.3 4.4 0.0 765.2
- ----------------------------------------------------------------------------------------------------------------
Net capitalized costs (a) $ 519.5 $ 45.2 $ 28.6 $ 2.4 $ 595.7
================================================================================================================
</TABLE>
(a) Excludes capitalized costs related to pipelines, plants and other
miscellaneous non-gas and oil producing assets.
F-17
<PAGE> 29
Costs Incurred in Gas and Oil Producing Activities
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
($ in millions)
United United Other
States Kingdom Argentina Foreign Total
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1993
Property acquisition -
Proved properties $ 1.9 $14.2 $ 0.0 $ 0.0 $ 16.1
Unproved properties 4.4 2.0 0.0 0.0 6.4
Exploration (b) 25.5 2.2 0.0 7.9 35.6
Development 48.0 2.9 3.2 0.0 54.1
- -------------------------------------------------------------------------------------------------------------------------------
Total costs incurred (a) $ 79.8 $21.3 $ 3.2 $ 7.9 $112.2
===============================================================================================================================
Year ended December 31, 1994
Property acquisition -
Proved properties $ 33.8 $35.3 $ 0.0 $ 0.0 $ 69.1
Unproved properties 14.9 2.7 0.1 0.0 17.7
Exploration (b) 35.3 3.9 0.0 2.4 41.6
Development 53.4 6.2 1.7 0.0 61.3
- -------------------------------------------------------------------------------------------------------------------------------
Total costs incurred (a) $137.4 $48.1 $ 1.8 $ 2.4 $189.7
===============================================================================================================================
Year ended December 31, 1995
Property acquisition -
Proved properties $ 0.4 $ 0.0 $ 0.0 $ 0.0 $ 0.4
Unproved properties 16.9 0.3 0.0 1.1 18.3
Exploration (b) 35.7 3.7 0.0 3.6 43.0
Development 81.1 7.0 4.4 0.0 92.5
- -------------------------------------------------------------------------------------------------------------------------------
Total costs incurred (a) $134.1 $11.0 $ 4.4 $ 4.7 $154.2
===============================================================================================================================
</TABLE>
(a) Includes costs whether capitalized or expensed as incurred.
(b) Includes 1993, 1994 and 1995 capitalized interest of $3.1, $4.0 and
$4.4 million, respectively.
F-18
<PAGE> 30
Results of Operations from Gas and Oil Producing Activities
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
($ in millions)
United United Other
States Kingdom Argentina Foreign Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1993
Revenues $251.5 $10.8 $ 7.8 $ 0.0 $270.1
Exploration costs 13.0 2.1 0.0 6.0 21.1
Production costs 42.9 5.1 2.6 0.0 50.6
Depreciation, depletion
and amortization 80.4 2.3 1.0 0.0 83.7
- ----------------------------------------------------------------------------------------------------------------------
115.2 1.3 4.2 (6.0) 114.7
Income tax expense (a) 36.7 0.1 1.5 (2.1) 36.2
- ----------------------------------------------------------------------------------------------------------------------
Results of operations (b) $ 78.5 $ 1.2 $ 2.7 $ (3.9) $ 78.5
======================================================================================================================
Year ended December 31, 1994
Revenues $187.0 $25.9 $ 6.8 $ 0.0 $219.7
Exploration costs 22.3 4.1 0.0 1.7 28.1
Production costs 42.2 6.7 2.6 0.0 51.5
Depreciation, depletion
and amortization 67.1 7.9 1.1 0.0 76.1
- ----------------------------------------------------------------------------------------------------------------------
55.4 7.2 3.1 (1.7) 64.0
Income tax expense (a) 18.4 0.2 1.1 (0.6) 19.1
- ----------------------------------------------------------------------------------------------------------------------
Results of operations (b) $ 37.0 $ 7.0 $ 2.0 $ (1.1) $ 44.9
======================================================================================================================
Year ended December 31, 1995
Revenues $198.7 $32.4 $ 8.0 $ 0.0 $239.1
Exploration costs 22.3 3.5 0.0 .6 26.4
Production costs 38.3 7.7 2.8 0.0 48.8
Depreciation, depletion
and amortization 65.2 8.2 1.3 0.0 74.7
- ----------------------------------------------------------------------------------------------------------------------
72.9 13.0 3.9 (.6) 89.2
Income tax expense (a) 25.1 1.1 1.4 (.2) 27.4
- ----------------------------------------------------------------------------------------------------------------------
Results of operations (b) $ 47.8 $11.9 $ 2.5 $(.4) $ 61.8
======================================================================================================================
</TABLE>
(a) Income tax expense is calculated by applying the statutory rates to
pre-tax income, taking into consideration any permanent differences
and tax credits.
(b) Excludes general corporate overhead, interest costs and other income.
F-19
<PAGE> 31
Estimated Proved Gas and Oil Reserves
Net quantities of proved and proved developed reserves of crude oil
and natural gas for 1993, 1994 and 1995 are set forth in the tables below.
Proved developed gas and oil reserves can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved gas and
oil reserves that are not developed are expected to be recovered from new wells
or from existing wells where a relatively major expenditure is required to
establish production.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
Gas
(Bcf)
United United
States Kingdom Argentina Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Proved reserves at
December 31, 1992 554 0 0 554
Purchases of reserves in place 2 8 0 10
Sales of reserves in place (1) 0 0 (1)
Revisions of previous estimates 37 3 0 40
Extensions, discoveries
and other additions 31 0 0 31
Production (95) (1) 0 (96)
- ----------------------------------------------------------------------------------------------------------------------
Proved reserves at
December 31, 1993 528 10 0 538
Purchases of reserves in place 28 32 0 60
Sales of reserves in place 0 (4) 0 (4)
Revisions of previous estimates 17 (1) 5 21
Extensions, discoveries
and other additions 62 0 0 62
Production (79) (4) 0 (83)
- ----------------------------------------------------------------------------------------------------------------------
Proved reserves at
December 31, 1994 556 33 5 594
Purchases of reserves in place 1 0 0 1
Sales of reserves in place (6) (2) 0 (8)
Revisions of previous estimates (11) 12 0 1
Extensions, discoveries
and other additions 112 5 0 117
Production (71) (4) 0 (75)
- ----------------------------------------------------------------------------------------------------------------------
Proved reserves at
December 31, 1995 581 44 5 630
======================================================================================================================
Proved developed reserves at December 31,
1992 514 0 0 514
1993 486 6 0 492
1994 499 20 4 523
1995 452 22 3 477
======================================================================================================================
</TABLE>
F-20
<PAGE> 32
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
Oil
(MBbls)
United United
States Kingdom Argentina Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Proved reserves at
December 31, 1992 22,027 0 15,409 37,436
Purchases of reserves in place 107 4,750 0 4,857
Sales of reserves in place (60) 0 0 (60)
Revisions of previous estimates 1,600 709 16 2,325
Extensions, discoveries
and other additions 4,353 0 0 4,353
Production (2,610) (662) (535) (3,807)
- ----------------------------------------------------------------------------------------------------------------------
Proved reserves at
December 31, 1993 25,417 4,797 14,890 45,104
Purchases of reserves in place 159 1,203 0 1,362
Sales of reserves in place (85) (2) 0 (87)
Revisions of previous estimates (102) 1,475 (863) 510
Extensions, discoveries
and other additions 6,134 0 0 6,134
Production (2,394) (1,149) (517) (4,060)
- ----------------------------------------------------------------------------------------------------------------------
Proved reserves at
December 31, 1994 29,129 6,324 13,510 48,963
Purchases of reserves in place 39 0 0 39
Sales of reserves in place (3,362) (179) 0 (3,541)
Revisions of previous estimates (1,474) 1,871 118 515
Extensions, discoveries
and other additions 5,746 666 0 6,412
Production (2,481) (995) (540) (4,016)
- ----------------------------------------------------------------------------------------------------------------------
Proved reserves at
December 31, 1995 27,597 7,687 13,088 48,372
======================================================================================================================
Proved developed reserves at December 31,
1992 16,862 0 8,550 25,412
1993 20,589 4,736 8,022 33,347
1994 24,160 5,958 6,505 36,623
1995 19,497 6,756 6,658 32,911
======================================================================================================================
</TABLE>
The proved reserve estimates presented herein for each of the three years
ended December 31, 1995 were prepared by EDC, and approximately 80% of such
reserve estimates were reviewed and found to be, in the aggregate, reasonable
and in accordance with generally accepted engineering and evaluation principles
by Miller and Lents, Ltd., independent petroleum engineers.
F-21
<PAGE> 33
Standardized Measure
The amounts presented below are based upon the methods and assumptions
prescribed in the Statement of Financial Accounting Standards No. 69 ("SFAS
69"). The disclosure is a tool which is intended to provide a uniform
calculation for entities with gas and oil reserves that will allow
comparability among entities. It is not intended to be an estimate of fair
market value or the net present value of future cash flows.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
($ in millions)
United United
States Kingdom Argentina Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
December 31, 1993
Future cash inflows (a) $1,621.8 $ 98.8 $213.0 $1,933.6
Future costs -
Production (b) (272.5) (60.4) (102.3) (435.2)
Development and
abandonment (b) (68.1) (12.9) (22.5) (103.5)
Future income taxes (c) (257.2) (3.5) (18.0) (278.7)
- ----------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,024.0 22.0 70.2 1,116.2
- ----------------------------------------------------------------------------------------------------------------------
10% annual discount (d) (260.1) (3.9) (28.6) (292.6)
- ----------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net cash flows $ 763.9 $ 18.1 $ 41.6 $ 823.6
======================================================================================================================
December 31, 1994
Future cash inflows (a) $1,389.6 $203.0 $194.9 $1,787.5
Future costs -
Production (b) (258.6) (102.4) (65.7) (426.7)
Development and
abandonment (b) (75.5) (20.8) (28.4) (124.7)
Future income taxes (c) (214.2) (14.5) (22.7) (251.4)
- ----------------------------------------------------------------------------------------------------------------------
Future net cash flows 841.3 65.3 78.1 984.7
- ----------------------------------------------------------------------------------------------------------------------
10% annual discount (d) (221.3) (13.8) (32.8) (267.9)
- ----------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net cash flows $ 620.0 $ 51.5 $ 45.3 $ 716.8
- ----------------------------------------------------------------------------------------------------------------------
December 31, 1995
Future cash inflows (a) $1,909.5 $262.1 $216.2 $2,387.8
Future costs -
Production (b) (281.7) (115.0) (63.0) (459.7)
Development and
abandonment (b) (86.9) (23.5) (22.0) (132.4)
Future income taxes (c) (406.3) (33.6) (35.9) (475.8)
- ----------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,134.6 90.0 95.3 1,319.9
- ----------------------------------------------------------------------------------------------------------------------
10% annual discount (d) (330.8) (23.2) (37.3) (391.3)
======================================================================================================================
Standardized measure of
discounted future net cash flows $ 803.8 $ 66.8 $ 58.0 $ 928.6
======================================================================================================================
</TABLE>
(a) Calculated using year-end gas and oil prices (adjusted for contractual
price changes which can be determined) applied to the estimated future
production of proved reserves assuming continuation of year-end economic
conditions.
(b) Estimated based upon year-end costs held constant in the future.
(c) Calculated using statutory tax rates and adjusted for permanent
differences and tax credits.
(d) The 10% discount rate is prescribed in SFAS 69 and is not necessarily
representative of EDC's cost of capital.
F-22
<PAGE> 34
Principal Sources of Change in the Standardized Measure
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
($ in millions)
1993 1994 1995
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Standardized measure -
beginning of year $ 822.0 $ 823.6 $ 716.8
Sales and transfers,
net of production costs (218.7) (164.3) (150.1)
Net change in sales and transfer prices,
net of production costs (16.7) (211.9) 299.3
Extensions and discoveries and improved
recovery, net of future production and
development costs 70.5 124.4 168.2
Changes in estimated future
development costs (18.6) (12.5) (11.6)
Development costs incurred during the period
that reduced future development costs 12.0 14.7 43.8
Revisions of quantity estimates 66.4 24.3 4.4
Accretion of discount 93.6 94.6 82.6
Net change in income taxes (8.5) 13.1 (150.3)
Purchase of reserves in place 27.3 80.5 0.7
Sale of reserves in place (1.4) (1.1) (23.8)
Changes in production rates (timing) and other (4.3) (68.6) (51.4)
- ----------------------------------------------------------------------------------------------------------------------
Standardized measure - end of year $ 823.6 $ 716.8 $ 928.6
======================================================================================================================
</TABLE>
F-23
<PAGE> 35
ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
FOR THE SIX MONTHS ENDED JUNE 30, 1995 AND 1996
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1996
------------------- ------------------
<S> <C> <C>
REVENUES:
Oil and gas sales and royalties $ 99,439 $ 121, 074
Gathering, marketing and processing 47,635 61,774
Other income 4,071 3,506
------------------- ------------------
151,145 186,354
COSTS AND EXPENSES:
Oil and gas operations 27,775 29,633
Oil and gas exploration 18,636 29,055
Gathering, marketing and processing 45,463 58,001
Depreciation, depletion and amortization 39,262 65,820
Selling, general and administrative 6,140 5,121
Interest 15,072 15,489
------------------- ------------------
152,348 203,119
------------------- ------------------
INCOME (LOSS) BEFORE TAXES (1,203) (16,765)
INCOME TAX BENEFIT (641) (7,732)
------------------- ------------------
NET INCOME (LOSS) $ (562) $ (9,033)
=================== ==================
</TABLE>
See accompanying Notes to Consolidated Condensed Financial Statements.
F-24
<PAGE> 36
ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEET
AS OF JUNE 30, 1996
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
June 30, 1996
---------------
<S> <C>
ASSETS:
Current assets $ 73,563
Property, plant and equipment 604,795
Other 48,846
---------------
$ 727,204
===============
LIABILITIES AND STOCKHOLDER'S EQUITY:
Current liabilities $ 60,784
Payables - affiliated companies 487,818
Deferred incomes taxes 7,172
Other deferred credits and noncurrent liabilities 4,425
Stockholder's equity 167,005
----------------
$ 727,204
================
</TABLE>
See accompanying Notes to Consolidated Condensed Financial Statements.
F-25
<PAGE> 37
ENERGY DEVELOPMENT CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 1995 AND 1996
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1996
----------------- ----------------
<S> <C> <C>
Cash flow from operating activities:
Net income (loss) $ (562) $ (9,033)
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 39,262 65,820
Unproved leasehold impairment/abandonment 2,021 4,962
Gain on property sales (301) (161)
Gas balancing 768 776
Deferred income taxes 7,410 (2,010)
Accrued/deferred revenue 1,148 (481)
Changes in current assets and current liabilities:
Accounts receivable 1,059 (8,700)
Prepaid items 1,172 11,689
Materials and supplies inventories 10 (251)
Accounts payable (271) 6,946
Accrued taxes payable 332 (320)
Other current liabilities (4,900) (9,293)
---------------- ----------------
Total adjustments 47,710 68,977
---------------- ----------------
Net cash provided by operating activities 47,148 59,944
Cash flows from investing activities:
Additions to property, plant and equipment (52,879) (63,572)
Additions to (reductions in) long-term receivable (662) 868
---------------- ----------------
Net cash used by investing activities (53,541) (62,704)
Cash flows from financing activities:
Proceeds from (repayments of) borrowings (29,600) 168,691
Additions to paid-in capital 40,000 0
Dividends paid (3,550) (178,500)
---------------- ----------------
Net cash provided (used) by financing activities 6,850 (9,809)
Net increase in cash and temporary cash investments 457 (12,569)
Cash and temporary cash investments - beginning of period 2,376 14,269
---------------- ----------------
Cash and temporary cash investments - end of period $ 2,833 $ 1,700
================ ================
Supplemental disclosure of cash flow information:
Cash paid for interest expense, net of capitalized
interest $ 13,807 $ 12,550
Cash paid (received) for income taxes $ (9,097) $ (1,573)
</TABLE>
See accompanying Notes to Consolidated Condensed Financial Statements.
F-26
<PAGE> 38
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
In the opinion of the Company, the accompanying unaudited consolidated
condensed financial statements of EDC contain all adjustments, consisting only
of necessary and normal recurring adjustments, necessary to present fairly
EDC's financial position as of June 30, 1996, and the statements of income for
the six month periods ended June 30, 1996 and 1995 and the cash flows for the
six month periods ended June 30, 1996 and 1995. These consolidated condensed
financial statements of EDC should be read in conjunction with the audited
consolidated financial statements of EDC and the notes thereto included
elsewhere in this Form 8-K/A (No. 1).
(1) DEPRECIATION, DEPLETION AND AMORTIZATION
During the six months ended June 30, 1996, depreciation, depletion and
amortization increased $26.6 million over the comparable period in 1995, or an
increase from $.80 per Mcfe to $1.31 per Mcfe, primarily as a result of
downward revisions to oil and gas reserve estimates made during the first six
months of 1996.
(2) CONTINGENCIES
EDC is a party to lawsuits and claims arising in the ordinary course
of business. EDC believes, based on its current knowledge and the advice of
its counsel, that all such lawsuits and claims would not have a material
adverse effect on its financial condition, results of operations and cash
flows.
(3) DIVIDENDS
In the six months ended June 30, 1996 and 1995, EDC paid dividends to
EDHI of $178.5 million and $3.55 million, respectively, which were declared
from paid-in capital.
(4) SUBSEQUENT EVENT
On July 31, 1996, Samedan Oil Corporation, a wholly owned subsidiary
of Noble Affiliates, Inc., acquired all the outstanding common stock of EDC for
approximately $768 million in cash.
F-27
<PAGE> 39
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
PRO FORMA CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
The unaudited pro forma consolidated condensed financial statements
set forth below present the pro forma consolidated condensed statement of
operations of Noble Affiliates, Inc. and Energy Development Corporation ("EDC")
(together, the "Company") for the six months ended June 30, 1996 as if the
acquisition of EDC (the "EDC Acquisition") and the financing thereof had
occurred on January 1, 1996 and the pro forma consolidated condensed statement
of operations of the Company for the year ended December 31, 1995 as if the EDC
Acquisition and the financing thereof had occurred on January 1, 1995. Also
presented is the pro forma consolidated condensed balance sheet of the Company
at June 30, 1996 as if the EDC Acquisition and the financing thereof had
occurred on such date.
The unaudited pro forma consolidated condensed financial statements
have been prepared on the basis of assumptions described in the notes thereto
and include assumptions relating to the allocation of the consideration paid
for EDC to the assets and liabilities of EDC based on preliminary estimates of
their respective fair values. The EDC Acquisition has been accounted for using
the purchase method of accounting.
The unaudited pro forma consolidated condensed financial statements do
not necessarily represent what the Company's financial position and results of
operations would have been if the EDC Acquisition and the financing thereof had
actually been completed as of the dates indicated, and they are not intended to
project the Company's financial position or results of operations for any
future period.
The unaudited pro forma consolidated condensed financial statements
should be read in conjunction with the consolidated financial statements of
Noble Affiliates, Inc. and the related notes thereto incorporated by reference
in the Company's annual report on Form 10-K for the year ended December 31,
1995, the consolidated condensed financial statements of Noble Affiliates, Inc.
and the related notes thereto contained in the Company's quarterly report on
Form 10-Q for the quarter ended June 30, 1996, EDC's audited financial
statements as of December 31, 1994 and 1995 and for each of the three years in
the period ended December 31, 1995 and the related notes thereto included
elsewhere in this Form 8-K/A (No. 1) and EDC's unaudited consolidated condensed
financial statements as of June 30, 1995 and 1996 and for the six months then
ended and the related notes thereto included elsewhere in this Form 8-K/A (No.
1).
F-28
<PAGE> 40
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1996(1)
-----------------------------------------------------------------------
ENERGY
NOBLE DEVELOPMENT
AFFILIATES, INC. CORPORATION ADJUSTMENTS PRO FORMA
---------------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales and royalties $ 227,937 $ 121,074 $ $ 349,011
Gathering, marketing and processing 122,087 61,774 183,861
Other income 3,971 3,506 7,477
------------ --------- ------------ ----------
353,995 186,354 --- 540,349
------------ --------- ------------ ----------
COSTS AND EXPENSES:
Oil and gas operations 49,358 29,633 78,991
Oil and gas exploration 20,455 29,055 (7,346)(c) 42,164
Gathering, marketing and processing 110,895 58,001 168,896
Depreciation, depletion and amortization 82,926 65,820 2,700 (a) 151,446
Selling, general and administrative 18,885 5,121 (169)(b)(c) 23,837
Interest 9,799 15,489 7,142 (d) 32,430
------------ --------- ----------- ----------
292,318 203,119 2,327 497,764
------------ --------- ----------- ----------
INCOME BEFORE TAXES 61,677 (16,765) (2,327) 42,585
INCOME TAX PROVISION 22,139 (7,732) (838)(e) 13,569
------------ --------- ----------- ----------
NET INCOME $ 39,538 $ (9,033) $ (1,489) $ 29,016
============ ========= =========== ==========
NET INCOME PER COMMON SHARE $ 0.78 $ 0.58
============ ==========
FULLY DILUTED EARNINGS PER SHARE $ 0.75 $ 0.56
============ ==========
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995(1)
-----------------------------------------------------------------------
ENERGY
NOBLE DEVELOPMENT
AFFILIATES, INC. CORPORATION ADJUSTMENTS PRO FORMA
---------------- ------------- ----------- -----------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales and royalties $ 328,134 $ 204,050 $ $ 532,184
Gathering, marketing and processing 112,702 90,049 202,751
Other income(2) 46,182 61,640 107,822
--------------- ------------- ----------- -----------
487,018 355,739 --- 842,757
--------------- ------------- ----------- -----------
COSTS AND EXPENSES:
Oil and gas operations 33,246 56,919 90,165
Oil and gas exploration 81,735 43,662 (15,339)(c) 110,058
Gathering, marketing and processing 107,867 85,605 193,472
Depreciation, depletion and amortization(2) 200,914 77,274 57,375 (a) 335,563
Selling, general and administrative 36,514 11,961 1,433 (b)(c) 49,908
Interest 18,744 27,486 17,240 (d) 63,470
--------------- ------------- ---------- -----------
479,020 302,907 60,709 842,636
--------------- ------------- ---------- -----------
INCOME BEFORE TAXES 7,998 52,832 (60,709) 121
INCOME TAX PROVISION 3,912 18,088 (21,952)(e) 48
--------------- ------------- ---------- -----------
NET INCOME $ 4,086 $ 34,744 $ (38,757) $ 73
=============== ============= ========== ===========
NET INCOME PER COMMON SHARE $ 0.08 $ 0.00
=============== ===========
FULLY DILUTED EARNINGS PER SHARE $ 0.08 $ 0.00
=============== ===========
</TABLE>
(Footnotes on following page)
F-29
<PAGE> 41
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
NOTES TO THE PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
(1) Basis of Presentation
The pro forma consolidated condensed statement of operations has been
prepared by combining the consolidated statements of operations of Noble
Affiliates, Inc. for the six months ended June 30, 1996 and the year ended
December 31, 1995 with the consolidated statements of operations of EDC for the
six months ended June 30, 1996 and the year ended December 31, 1995,
respectively, assuming the EDC Acquisition and the financing thereof occurred
at the beginning of the respective periods. The EDC Acquisition has been
accounted for using the purchase method of accounting.
Fully diluted earnings per share were computed using the "if converted
method" assuming the outstanding convertible debt securities of Noble
Affiliates, Inc. were converted into common stock at the beginning of the
period. Such debt securities were antidilutive for the year ended December 31,
1995.
(2) Non-Recurring Events
Columbia Gas Transmission Corporation Settlement
During 1995, both Noble Affiliates, Inc. and EDC settled their
bankruptcy claims against Columbia Gas Transmission Corporation (Columbia)
through the receipt of $48.9 million and $36.1 million, respectively. Noble
Affiliates, Inc. and EDC recorded $39 million and $35 million as other income,
respectively, related to these settlements during the year ended December 31,
1995.
Impairment of Long-Lived Assets
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Standards (SFAS) No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." Noble
Affiliates, Inc. adopted SFAS No. 121 during 1995. Noble Affiliates recognized
a $59.5 million SFAS No. 121 impairment for 1995. EDC evaluated the impact of
SFAS No. 121 and determined that it would not have a significant impact on the
financial condition or results of operations of EDC for 1995, based upon the
current economic conditions.
(3) Pro Forma Adjustments
The unaudited pro forma consolidated condensed statement of operations
reflects the following adjustments:
(a) To record depreciation, depletion and amortization of the
estimated net increase in the fair value of property and
equipment acquired over historical cost related to such
property and equipment and to provide for estimated additional
restoration and abandonment costs related to oil and gas
properties using the proved developed oil and gas reserves
allocated property-by-property, estimated by Company
engineers. Such fair values of assets and liabilities are
based on estimates made at the time of the EDC Acquisition.
(b) To reflect the estimated cost savings that the Company
anticipates will be realized as a result of the EDC
Acquisition, including those from facilities consolidation and
elimination of employee costs of those EDC employees whose
employment with the Company is expected to be terminated.
(c) To reclassify certain costs and expenses (primarily employee
costs) that Noble Affiliates, Inc. would classify as general
and administrative costs that were included in EDC's financial
statements as oil and gas exploration costs and expenses.
F-30
<PAGE> 42
(d) To reflect the net adjustment for the six months ended June
30, 1996 and the year ended December 31, 1995 of (i) the
elimination of interest expense of $31.4 million for the year
ended December 31, 1995 and $17 million for the six months
ended June 30, 1996 associated with $312 million and $481
million of borrowings from affiliated companies at December 31,
1995 and June 30, 1996, respectively, which was contributed to
EDC in connection with the EDC Acquisition, (ii) the addition
of interest expense of $52 million for the year ended December
31, 1995 and $26 million for the six months ended June 30, 1996
associated with the $800 million borrowing under the line of
credit and (iii) the reduction of interest expense of $3.4
million for the year ended December 31, 1995 and $1.7 million
for the six months ended June 30, 1996 associated with the
repayment of the $48 million borrowing under the line of credit
in place during 1995 and the six months ended June 30, 1996.
(e) To provide for income taxes at an assumed effective rate of
36% for all adjustments.
F-31
<PAGE> 43
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996(1)
------------------------------------------------------------------------------
ENERGY
NOBLE DEVELOPMENT
AFFILIATES, INC. CORPORATION ADJUSTMENTS PRO FORMA
------------------ ----------- ----------- ---------
<S> <C> <C> <C>
ASSETS:
Current Assets $ 144,307 $ 73,563 $ (51,018)(a)(d) $ 166,852
Property, Plant and Equipment 885,462 604,795 130,989 (a) 1,621,246
Other 26,035 48,846 (6,825)(a) 68,056
------------- ----------- ----------- ------------
$ 1,055,804 $ 727,204 $ 73,146 $ 1,856,154
============= =========== =========== ============
LIABILITIES AND SHAREHOLDERS'
EQUITY:
Current Liabilities $ 113,324 $ 60,784 $ 74,322 (a) $ 248,430
Notes Payable - Affiliated Companies -- 487,818 (487,818)(c) --
Deferred Income Taxes 76,852 7,172 (4,422)(b) 79,602
Other Deferred Credits and Noncurrent
Liabilities 38,286 4,425 6,069 (a) 48,780
Long-term Debt 377,010 -- 652,000 (d) 1,029,010
Shareholders' Equity 450,332 167,005 (167,005)(a) 450,332
------------- ----------- ----------- ------------
Total Liabilities and Shareholders'
Equity $ 1,055,804 $ 727,204 $ 73,146 $ 1,856,154
============= =========== =========== ============
</TABLE>
(Footnotes on following page)
F-32
<PAGE> 44
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
NOTES TO THE PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET
(1) Basis of Presentation
The pro forma consolidated condensed balance sheet has been prepared
by combining the consolidated balance sheet of Noble Affiliates, Inc. with the
consolidated balance sheet of EDC as of June 30, 1996 using the purchase method
of accounting and assuming the EDC Acquisition and the financing thereof
occurred on June 30, 1996.
(2) Pro Forma Adjustments
The unaudited pro forma consolidated condensed balance sheet reflects
the following adjustments:
(a) To reflect purchase accounting adjustments required to record
the fair value of EDC's assets and liabilities. Such fair
values are based on estimates made at the time of the EDC
Acquisition.
(b) To record the impact on deferred income taxes related to
foreign operations resulting from fair market value
adjustments described in these notes. For U.S. tax purposes,
the Company elected to write up the assets acquired to their
fair value. No such election for tax purposes is available in
certain foreign countries. As a result, the adjustment
reflects the estimated future tax effects of differences
between financial statement and tax bases of assets and
liabilities related to these foreign operations.
(c) To record the net effect of the elimination of $488 million of
borrowings from affiliated companies at June 30, 1996, which
was contributed to EDC in connection with the EDC Acquisition.
(d) To record the net effect of the $800 million borrowing under
the Company's bank credit facility and the use of the proceeds
therefrom to purchase all the outstanding common stock of EDC
for approximately $768 million and to repay $48 million of
outstanding indebtedness under a bank credit agreement at June
30, 1996.
(e) To eliminate EDC equity accounts.
F-33
<PAGE> 45
Index to Exhibits
23.1 - Consent of Miller and Lents, Ltd.
23.2 - Consent of Deloitte & Touche LLP
99.1 - Summary Reserve Report on the estimated reserves of
EDC as of July 1, 1996, prepared by Miller and Lents,
Ltd., independent petroleum consultants
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the use of our report to Energy Development Corporation
dated September 27, 1996, and titled "Proved Reserves as of July 1, 1996," in
the Noble Affiliates, Inc. Securities and Exchange Commission Form 8-K/A (No.
1) and to the references to Miller and Lents, Ltd. under the heading "Miller
and Lents Reserve Report."
MILLER AND LENTS, LTD.
By:/s/ LARRY M. GRING
-------------------------------
Larry M. Gring,
Senior Vice President
Houston, Texas
September 27, 1996
<PAGE> 1
EXHIBIT 23.2
INDEPENDENT AUDITORS' CONSENT
Noble Affiliates, Inc.
Ardmore, Oklahoma
We consent to the incorporation by reference in the Registration Statements on
Form S-8 (Nos. 2-64600, 2-81590, 33- 32692, 2-66654 and 33-54084) of Noble
Affiliates, Inc. of our report on Energy Development Corporation dated February
16, 1996 (July 2, 1996 as to Notes 1 and 10), appearing in Form 8-K of Noble
Affiliates, Inc., as amended.
Deloitte & Touche LLP
Houston, Texas
September 27, 1996
<PAGE> 1
EXHIBIT 99.1
[Letterhead of Miller and Lents, Ltd.]
September 27, 1996
Energy Development Corporation
1000 Louisiana, Suite 2900
Houston, Texas 77002
Re: PROVED RESERVES AS OF JULY 1, 1996
Gentlemen:
As requested, we estimated the proved reserves attributed to Energy
Development Corporation as of July 1, 1996. The results of our estimates using
instructed prices and costs are shown below:
TOTAL PROVED AND PROVED DEVELOPED
RESERVES AS OF JULY 1, 1996
<TABLE>
<CAPTION>
GAS (BCF) OIL (MMBBLS)
------------------------- ---------------------
<S> <C> <C>
Total Proved Reserves:
Domestic:
Offshore Gulf of Mexico . . . . . . . . . . 182.1 8.2
Onshore . . . . . . . . . . . . . . . . . . 201.3 7.3
--------- ---------
383.4 15.5
International . . . . . . . . . . . . . . . . . . 40.6 24.9
--------- ---------
424.0 40.5
========= =========
Total Proved Developed Reserves . . . . . . . . . . . . 347.6 28.8
========= =========
</TABLE>
The proved reserves of oil, condensate, and natural gas were estimated in
accordance with the standards of the Society of Petroleum Engineers, Inc. as
defined in the Appendix with the exception of using the instructed price
schedules.
The reserves reported herein were estimated from material balance,
production performance, analogy, and volumetric calculations. Reserve estimates
based on volumetric calculations and on analogy are often less certain than
reserve estimates based on well performance obtained over a period during which
a substantial portion of the reserves was produced.
Prices for oil and gas were specified by Energy Development Corporation
and were represented to be net of basis, Btu, and transportation charges.
Operating costs and capital requirements were based on information provided by
Energy Development Corporation. As you instructed, prices, operating costs and
capital expenditures were not escalated.
<PAGE> 2
Energy Development Corporation
September 27, 1996
Page 2
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on accepted
standards of professional investigation but are subject to those generally
recognized uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies and market
conditions different from those employed in this study may cause the total
quantity of oil or gas to be recovered, actual production rates, prices
received, or operating and capital costs to vary from those presented in this
report.
In conducting these evaluations we relied upon cost data and other
financial, operating engineering, and geological data from Energy Development
Corporation, from the files of Miller and Lents, Ltd., and from public
information sources. We relied upon Energy Development Corporation's
representation of the ownership interests evaluated herein. No independent
verifications of these matters were made by Miller and Lents, Ltd., as such
verifications are beyond the scope of this assignment.
The details of our investigations are in our files. Please call if you
require additional information.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ LARRY M GRING
----------------------------------
Larry M. Gring,
Senior Vice President
<PAGE> 3
Appendix
Page 1
DEFINITIONS FOR OIL AND GAS RESERVES (1)
RESERVES
Reserves are estimated volumes of crude oil, condensate, natural gas, natural
gas liquids, and associated substances anticipated to be commercially
recoverable from known accumulations from a given date forward, under existing
economic conditions, by established operating practices, and under current
government regulations. Reserve estimates are based on interpretation of
geologic and/or engineering data available at the time of the estimate.
Reserve estimates generally will be revised as reservoirs are produced,
as additional geologic and/or engineering data become available, or as economic
conditions change.
Reserves do not include volumes of crude oil, condensate, natural gas,
or natural gas liquids being held in inventory. If required for financial
reporting or other special purposes, reserves may be reduced for on-site usage
and/or processing losses.
The ownership status of reserves may change due to the expiration of a
production license or contract; when relevant to reserve assignment such
changes should be identified for each reserve classification.
Reserves may be attributed to either natural reservoir energy, or
improved recovery methods. Improved recovery includes all methods for
supplementing natural reservoir energy to increase ultimate recovery from a
reservoir. Such methods include (1) pressure maintenance, (2) cycling, (3)
waterflooding, (4) thermal methods, (5) chemical flooding, and (6) the use of
miscible and immiscible displacement fluids.
All reserve estimates involve some degree of uncertainty, depending
chiefly on the amount and reliability of geologic and engineering data
available at the time of the estimate and the interpretation of these data.
The relative degree of uncertainty may be conveyed by placing reserves in one
of two classifications, either proved or unproved. Unproved reserves are less
certain to be recovered than proved reserves and may be subclassified as
probable or possible to denote progressively increasing uncertainty.
PROVED RESERVES
Proved reserves can be estimated with reasonable certainty to be recoverable
under current economic conditions. Current economic conditions include prices
and costs prevailing at the time of the estimate. Proved reserves may be
developed or undeveloped.
In general, reserves are considered proved if commercial producibility
of the reservoir is supported by actual production or formation tests. The
term proved refers to the estimated volume of reserves and not just to the
productivity of the well or reservoir. In certain instances, proved reserves
may be assigned on the basis of electrical and other type logs and/or core
analysis that indicate subject reservoir is hydrocarbon bearing and is
analogous to reservoirs in the same area that are producing, or have
demonstrated the ability to produce on a formation test.
The area of a reservoir considered proved includes (1) the area
delineated by drilling and defined by fluid contacts, if any, and (2) the
undrilled areas that can be reasonably judged as commercially productive on the
basis of available geological and engineering data. In the absence of data on
fluid contacts, the lowest known structural occurrence of hydrocarbons controls
the proved limit unless otherwise indicated by definitive engineering or
performance data.
Proved reserves must have facilities to process and transport those
reserves to market that are operational at the time of the estimate, or there
is a commitment or reasonable expectation to install such facilities in the
future.
- ------------------------
1 Approved by the Board of Directors, Society of Petroleum Engineers (SPE),
Inc. February 27, 1987.
<PAGE> 4
Appendix
Page 2
In general, proved undeveloped reserves are assigned to undrilled
locations that satisfy the following conditions: (1) the locations are direct
offsets to wells that have indicated commercial production in the objective
formation, (2) it is reasonably certain that the locations are within the known
proved productive limits of the objective formation, (3) the locations conform
to existing well spacing regulations, if any, and (4) it is reasonably certain
that the locations will be developed. Reserves for other undrilled locations are
classified as proved undeveloped only in those cases where interpretations of
data from wells indicate that the objective formation is laterally continuous
and contains commercially recoverable hydrocarbons at locations beyond direct
offsets.
Reserves that can be produced through the application of established
improved recovery methods are included in the proved classification when (1)
successful testing by a pilot project or favorable production or pressure
response of an installed program in that reservoir, or one in the immediate
area with similar rock and fluid properties, provides support for the
engineering analysis on which the project or program is based and (2) it is
reasonably certain the project will proceed.
Reserves to be recovered by improved recovery methods that have yet to
be established through repeated commercially successful applications are
included in the proved classification only (1) after a favorable production
response from subject reservoir from either (a) a representative pilot or (b)
an installed program, where the response provides support for the engineering
analysis on which the project is based, and (2) it is reasonably certain the
project will proceed.
UNPROVED RESERVES
Unproved reserves are based on geologic and/or engineering data similar
to that used in estimates of proved reserves; but technical, contractual,
economic, or regulatory uncertainties preclude such reserves being classified
as proved. They may be estimated assuming future economic conditions different
from those prevailing at the time of the estimate.
Estimates of unproved reserves may be made for internal planning or
special evaluations, but are not routinely compiled.
Unproved reserves are not to be added to proved reserves because of
different levels of uncertainty.
Unproved reserves may be divided into two subclassifications: PROBABLE
and POSSIBLE.
PROBABLE RESERVES. Probable reserves are less certain than proved reserves and
can be estimated with a degree of certainty sufficient to indicate they are
more likely to be recovered than not.
In general, probable reserves may include (1) reserves anticipated to be
proved by normal stepout drilling where subsurface control is inadequate to
classify these reserves as proved; (2) reserves in formations that appear to be
productive based on log characteristics but that lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the
area; (3) incremental reserves attributable to infill drilling that otherwise
could be classified as proved but closer statutory spacing had not been
approved at the time of the estimate; (4) reserves attributable to an improved
recovery method which has been established by repeated commercially successful
applications when a project or pilot is planned but not in operation and rock,
fluid, and reservoir characteristics appear favorable for commercial
application; (5) reserves in an area of a formation that has been proved
productive in other areas of the field but subject area appears to be separated
from the proved area by faulting and the geologic interpretation indicates
subject area is structurally higher than the proved area; (6) reserves
attributable to a successful workover, treatment, retreatment, change of
equipment, or other mechanical procedure, where such procedure has not been
proved successful in wells exhibiting similar behavior in analogous reservoirs;
and (7) incremental reserves in a proved producing reservoir where an alternate
interpretation of performance or volumetric data indicates significantly more
reserves than can be classified as proved.
<PAGE> 5
Appendix
Page 3
POSSIBLE RESERVES. Possible reserves are less certain than probable reserves
and can be estimated with a low degree of certainty, insufficient to indicate
whether they are more likely to be recovered than not.
In general, possible reserves may include (1) reserves suggested by
structural and/or stratigraphic extrapolation beyond areas classified as
probable, based on geologic and/or geophysical interpretation; (2) reserves in
formations that appear to be hydrocarbon bearing based on logs or cores but
that may not be productive at commercial rates; (3) incremental reserves
attributable to infill drilling that are subject to technical uncertainty; (4)
reserves attributable to an improved recovery method when a project or pilot is
planned but not in operation and rock, fluid, and reservoir characteristics are
such that a reasonable doubt exists that the project will be commercial; and
(5) reserves in an area of a formation that has been proved productive in other
areas of the field but subject area appears to be separated from the proved
area by faulting and geologic interpretation indicates subject area is
structurally lower than the proved area.
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of wells
and/or reservoirs.
DEVELOPED. Developed reserves are expected to be recovered from existing wells
(including reserves behind pipe). Improved recovery reserves are considered
developed only after the necessary equipment has been installed, or when the
costs to do so are relatively minor. Developed reserves may be subcategorized
as producing or non-producing.
PRODUCING. Producing reserves are expected to be recovered from
completion intervals open at the time of the estimate and producing. Improved
recovery reserves are considered to be producing only after an improved
recovery project is in operation.
NONPRODUCING. Nonproducing reserves include shut-in and behind-pipe
reserves. Shut-in reserves are expected to be recovered from completion
intervals open at the time of the estimate, but which had not started
producing, or were shut in for market conditions or pipeline connection, or
were not capable of production for mechanical reasons, and the time when sales
will start is uncertain.
Behind-pipe reserves are expected to be recovered from zones behind
casing in existing wells, which will require additional completion work or a
future recompletion prior to the start of production.
UNDEVELOPED. Undeveloped reserves are expected to be recovered: (1) from new
wells on undrilled acreage, (2) from deepening existing wells to a different
reservoir, or (3) where a relatively large expenditure is required to (a)
recomplete an existing well or (b) install production or transportation
facilities for primary or improved recovery projects.
