<PAGE>
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K
(MARK ONE)
<TABLE>
<C> <S>
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
</TABLE>
COMMISSION FILE NUMBER 1-9033
------------------------
SUN ENERGY PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)
<TABLE>
<S> <C>
DELAWARE 75-2070723
(State or other jurisdiction of (I.R.S. employer identification number)
incorporation or organization)
13155 NOEL ROAD
DALLAS, TEXAS 75240-5067
(Address of principal executive offices) (Zip code)
</TABLE>
Registrant's telephone number, including area code:
(214) 715-4000
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
Name of Each Exchange
Title of Each Class on Which Registered
--------------------------------------------------- ---------------------------------------------------
<S> <C>
Depositary Units New York Stock Exchange, Inc.
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy of information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. _X_
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes _X_ No ____
The aggregate market value of the Depositary Units held by nonaffiliates of
the Registrant as of February 28, 1995, was approximately $33 million.
The number of Depositary Units outstanding as of February 28, 1995, was
7,543,100.
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<PAGE>
CERTAIN ABBREVIATIONS AND OTHER MATTERS
As used herein, the following terms have specific meanings: "m" means
thousand, "mm" means million, "bbl" means barrel, "mb" means thousands of
barrels, "mmb" means millions of barrels, "mcf" means thousand cubic feet,
"mmcf" means million cubic feet, "bcf" means billion cubic feet, "eb" means
equivalent barrel, "mmeb" means millions of equivalent barrels, "b/d" means
barrels per day, "mmcf/d" means million cubic feet per day, "ED&A" means
exploration, development and acquisition and "FD&A" means finding, development
and acquisition.
Natural gas equivalents are determined under the relative energy content
method by using the ratio of 6.0 mcf of natural gas to 1.0 bbl of crude oil,
condensate or natural gas liquids.
With respect to information on the working interest in wells, drilling
locations and acreage, "net" oil and gas wells, drilling locations and acres are
determined by multiplying "gross" oil and gas wells, drilling locations and
acres by Sun Energy Partners, L.P.'s working interest in such wells, drilling
locations or acres.
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
Sun Energy Partners, L.P. (Sun Energy Partners) engages exclusively in the
exploration and development of oil and gas in the United States. Sun Energy
Partners is controlled by Oryx Energy Company and certain of its affiliates
(together the Company), which is the managing general partner. As of December
31, 1994, the Company owned 98 percent of Sun Energy Partners. The remaining two
percent interest is comprised of limited partnership interests held by public
unitholders in the form of depositary units (Units). Eighty-five percent of the
Company's Board of Directors must approve any additional issuance, sale or
transfer of units which would reduce the Company's holdings below eighty-five
percent of the outstanding units. Sun Energy Partners sold 8.7 million limited
partnership units during 1993 to the Company. It did not sell any additional
units in 1994 and does not expect to sell any in 1995.
Sun Energy Partners' business is conducted through Sun Operating Limited
Partnership, a Delaware limited partnership, and several other operating
partnerships (collectively, the Operating Partnerships). In all of the
partnerships which comprise the Operating Partnerships, Sun Energy Partners
holds a 99 percent interest as the sole limited partner, while the Company holds
a one percent interest as the managing general partner.
Sun Energy Partners and the Operating Partnerships (collectively, the
Partnership), are managed by the Company. The holders of limited partnership
units have no power to direct or participate in the control of the Partnership.
The Company makes all decisions regarding exploration, development, production
and marketing for properties belonging to the Partnership, all decisions
regarding the sale of less than substantially all of such properties or the
acquisition of properties by the Partnership and all other decisions regarding
the Partnership's business or operations.
The Partnership has no officers or employees. Officers and employees of the
Company perform all management functions required for Sun Energy Partners. As of
December 31, 1994, the number of full-time employees of the Company was
approximately 1,200.
The Partnership's strategy is to target as future growth opportunities those
areas where its advanced technological capabilities will have the greatest
impact. The Partnership is focusing its efforts on high potential Gulf of Mexico
prospects with lower-risk and shorter cycle times.
RESERVES
As of December 31, 1994, the Partnership's proved reserves were an estimated
222 mmb of liquids and an estimated 1,320 bcf of natural gas which represents an
aggregate of 442 mmeb of reserves. More information on the estimated quantities
of proved oil and gas reserves and information on proved developed oil and gas
reserves, as well as information concerning the standardized measure of
discounted future net cash flows from estimated production of proved oil and gas
reserves (Standardized Measure), are presented in the "Consolidated Financial
Statements Supplementary Financial
<PAGE>
and Operating Information." The Partnership files estimates of oil and gas
reserve data with various governmental regulatory authorities and agencies. The
basis of reporting reserves to these authorities and agencies in some cases may
not be comparable. However, the difference in estimates does not exceed five
percent.
The Partnership's production is exclusively in the United States and in
1994, the Partnership produced 52 mmeb. The Partnership seeks production
replacement through a balanced approach that combines exploration, development
and acquisition. In 1994, the Partnership replaced 81 percent of its production
at a finding, development and acquisition cost of $4.36 per eb.
OFFSHORE
EXPLORATION
As of December 31, 1994, the Partnership held 341 thousand net undeveloped
acres offshore, as compared to 384 thousand as of December 31, 1993. The
Partnership owns interests in about 150 Gulf of Mexico blocks of which 98 are
undeveloped. In 1994, the Partnership spent $4.3 million to acquire interests in
15 blocks.
As of December 31, 1994, no exploratory wells were being drilled. The
Partnership drilled 4 gross (3 net) exploratory wells offshore in 1994 and 7
gross (4 net) in 1993. Of the wells drilled in 1994, 1 gross (1 net) was
successful.
The Partnership's offshore exploration program will focus on projects in the
Gulf of Mexico and make extensive use of proven technology. The Partnership will
focus on projects with rapid cycle times located near existing infrastructure in
water depths less than 1,200 feet.
The Partnership owns a 99 percent interest in the four-block High Island 384
unit. The High Island 384 unit is composed of blocks 378, 379, 384 and 385 and
is located approximately 112 miles off the Texas coast in water with an average
depth of approximately 360 feet. In 1993, the Partnership announced an oil
discovery in High Island 379. The HI-A-379 #1 discovery well encountered 179
feet of oil pay from three Pleistocene sands between 4,600 and 5,130 feet. In
the early part of 1994, the Partnership announced an oil and gas discovery in
High Island 385. The High Island 385 discovery encountered 80 feet of net pay in
two Basal Nebraskan sands between 14,300 and 14,410 feet. The combined
production from the two discoveries is expected to peak at approximately 20 meb
per day. This new development, which has been named the Patton Project, began
production in January 1995.
The Partnership also owns a 99 percent interest in the High Island A-576
block. The HI A-576 #1 discovery well encountered 168 feet of net pay from the
Lower Pleistocene sands. The well is located 110 miles off the Texas coast in
290 feet of water and is 20 miles southwest of the Partnership's recent
discoveries at High Island 379 and 385. This development, which has been named
the Sherman Project, is expected to begin production in early 1996 with peak
production of about 6 to 9 meb per day. An appraisal well was drilling at
December 31, 1994.
PRODUCTION AND DEVELOPMENT
Average daily production of crude oil and condensate offshore was 9.6, 8.5
and 7.1 mbbls in 1994, 1993 and 1992. Average daily production of natural gas
offshore was 201, 191 and 179 mmcf in 1994, 1993 and 1992.
In the first quarter of 1994, the Partnership announced the results of an
appraisal well on Garden Banks 260 Block. This was the third successful well on
the block. The well encountered three zones containing hydrocarbons with a total
of 183 feet of pay. This development, which has been named the Baldpate Project,
is in federal waters offshore Texas in water depths of approximately 1,700 feet.
The Partnership expects to begin production in 1998 with gross peak production
of about 40 meb per day. The Partnership owns a 50 percent interest in a
three-block area.
The Partnership recently announced plans for the development of Viosca Knoll
826 which lies 80 miles off the Alabama coast in water depths of 1,500 to 2,500
feet. This development has been named
2
<PAGE>
the Neptune Project. First production is anticipated in 1997 with a gross peak
rate of 24 to 30 meb per day. The Partnership operates the four-block Viosca
Knoll unit and owns a 50 percent interest. The project will utilize a new type
of floating production facility called a spar which is on the leading edge of
today's technology. The spar is a cylindrical-shaped vessel which floats in a
vertical position, similar to a buoy. Production risers will be routed through
the cylinder to allow the spar to float around them. The field will be developed
in multiple phases with the spar being moved from location to location. In the
third quarter of 1994, the Partnership exchanged its interest in an undeveloped
block in the Gulf of Mexico for a royalty interest in Viosca Knoll 826.
As of December 31, 1994, the Partnership was drilling 8 gross and 5 net
development wells. The Partnership drilled 16 gross (6 net) development wells
offshore in 1994 and 16 gross (8 net) in 1993. Of the 16 gross (6 net)
development wells drilled in 1994, 14 gross (5 net) were successful.
ONSHORE
The onshore area continues to be a major contributor of production volumes
and cash flow. The Partnership is applying 3-D technology in and around mature
fields creating opportunities in new fault blocks and deeper pool horizons which
provide primarily new gas volumes. To optimize crude oil volumes and cash flow,
the Partnership will continue to exploit its waterflood operations. Assets are
regularly subjected to performance reviews and divestments will continue to be
made to upgrade the overall portfolio. The onshore will be managed for maximum
cash flow generation.
EXPLORATION
The Partnership drilled 1 gross exploratory well onshore in 1994 which was
successful. At December 31, 1994, no exploratory wells were being drilled.
PRODUCTION AND DEVELOPMENT
Average daily production of crude oil and condensate onshore was 37.8, 46.8
and 55.7 mb in 1994, 1993 and 1992. The decrease in 1994 crude oil and
condensate production compared to 1993 and in 1993 compared to 1992 was due
primarily to asset sales and normal declines. Average daily net production of
natural gas onshore was 332, 326 and 399 mmcf in 1994, 1993 and 1992. The
decrease in 1993 natural gas production compared to 1992 was due primarily to
divestments.
As of December 31, 1994, the Partnership was drilling or participating in
the drilling of 33 gross (19 net) development wells onshore. Of the 80 gross (38
net) development wells drilled onshore, 76 gross (34 net) were successful during
1994.
As part of an asset sale program, the Partnership sold substantially all its
gas processing plant business in 1992. The Partnership's remaining gas plant
business at December 31, 1994 consisted of 11 operated gas processing plants and
interests in 4 others.
3
<PAGE>
TABULAR INFORMATION
The following table sets forth the Partnership's undeveloped and developed
oil and gas acreage (in thousands) held at December 31, 1994 and 1993:
<TABLE>
<CAPTION>
GROSS NET
-------------------- --------------------
1994 1993 1994 1993
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
UNDEVELOPED ACREAGE
Onshore............................................................... 1,142 997 566 429
Offshore.............................................................. 511 674 341 384
--------- --------- --- ---
Total............................................................... 1,653 1,671 907 813
--------- --------- --- ---
--------- --------- --- ---
<CAPTION>
GROSS NET
-------------------- --------------------
1994 1993 1994 1993
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
DEVELOPED ACREAGE
Onshore............................................................... 1,137 1,599 625 861
Offshore.............................................................. 244 253 96 103
--------- --------- --- ---
Total............................................................... 1,381 1,852 721 964
--------- --------- --- ---
--------- --------- --- ---
</TABLE>
The following table sets forth the Partnership's net exploratory and
development oil and gas wells drilled in 1994, 1993 and 1992:
<TABLE>
<CAPTION>
EXPLORATORY DEVELOPMENT
WELLS WELLS
---------------- ----------------
1994 1993 1992 1994 1993 1992
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Oil
Onshore..................................................... - - 1 11 29 43
Offshore.................................................... - 1 1 2 2 -
---- ---- ---- ---- ---- ----
- 1 2 13 31 43
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
Gas
Onshore..................................................... - - 1 23 15 11
Offshore.................................................... 1 1 3 3 3 2
---- ---- ---- ---- ---- ----
1 1 4 26 18 13
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
Dry
Onshore..................................................... - 2 3 4 1 3
Offshore.................................................... 2 2 - 1 3 -
---- ---- ---- ---- ---- ----
2 4 3 5 4 3
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
</TABLE>
The following table sets forth the Partnership's gross and net producing oil
and gas wells at December 31, 1994:
<TABLE>
<CAPTION>
GROSS* NET
-------------------- --------------------
OIL GAS OIL GAS
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Onshore............................................................... 3,603 897 1,945 535
Offshore.............................................................. 66 177 24 69
--------- --------- --------- ---
Total............................................................. 3,669 1,074 1,969 604
--------- --------- --------- ---
--------- --------- --------- ---
<FN>
------------------------
*Gross producing wells include 197 multiple completion wells (more than one
formation producing into the same well bore).
</TABLE>
4
<PAGE>
The following table sets forth the Partnership's average daily net
production for 1994, 1993 and 1992:
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
<S> <C> <C> <C>
Crude & Condensate:
(Thousands of barrels daily)
Onshore...................................................................... 37.8 46.8 55.7
Offshore..................................................................... 9.6 8.5 7.1
--- --- ---
47.4 55.3 62.8
Processed Natural Gas:*
(Thousands of barrels daily)................................................... 6.3 7.3 19.5
--- --- ---
53.7 62.6 82.3
--- --- ---
--- --- ---
Natural Gas:**
(Millions of cubic feet daily)
Onshore...................................................................... 332 326 399
Offshore..................................................................... 201 191 179
--- --- ---
533 517 578
--- --- ---
--- --- ---
<FN>
------------------------
*The Partnership sold substantially all of its gas plant business during 1992.
(See Note 4 to the Consolidated Financial Statements.)
**Natural gas production includes unprocessed natural gas liquids.
</TABLE>
The following table sets forth the Partnership's average revenues and
production costs per unit of oil and gas production for 1994, 1993 and 1992:
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
<S> <C> <C> <C>
Revenues:
Crude oil & condensate (per barrel).................................... $ 14.69 $ 15.96 $ 18.51
Crude oil, condensate & natural gas liquids (per barrel)............... $ 13.44 $ 14.08 $ 18.21
Natural gas (per mcf).................................................. $ 1.87 $ 1.96 $ 1.72
Average production cost per unit of oil and gas production (per
equivalent barrel)*................................................... $ 4.54 $ 4.56 $ 4.12
<FN>
------------------------
*Average production cost consists of lease operating cost and production taxes.
</TABLE>
ASSET DISPOSALS
Assets are managed on a portfolio basis. The Partnership will continue to
buy and sell assets with the intention of upgrading its asset base.
RECOVERY METHODS
During 1994, the Partnership obtained 55, 38, and 7 percent of its crude
production from primary, secondary and tertiary recovery methods. This compares
to 49, 39 and 12 percent of its crude oil production in 1993. At December 31,
1994, the Partnership operated or participated in 3 major tertiary oil recovery
programs that produced approximately 4 thousand net barrels of crude and
condensate daily in 1994.
The terms "secondary recovery" and "tertiary recovery" relate to those
methods used to increase the quantity of crude oil and condensate and natural
gas that can be recovered in excess of the quantity recoverable using the
primary energy found in a reservoir. Secondary recovery methods include pressure
maintenance by waterflooding or natural gas injection. Tertiary recovery methods
include injection of carbon dioxide, nitrogen, chemicals, steam or a combination
of these with natural gas or water. Tertiary and, to a lesser extent, secondary
recovery operations generally have higher operating costs compared to those
incurred in primary production efforts.
5
<PAGE>
MARKETING OF OIL AND GAS
DISTRIBUTION
Crude oil, condensate and natural gas are distributed to end users through
pipelines and/or trucks. In addition to end users, purchasers include
intermediaries such as gatherers, transporters and traders. Sufficient
distribution systems exist and are readily available in the areas of the
Partnership's production to enable the Partnership to effectively market its oil
and gas. In some instances, the Partnership owns an interest in these systems.
CRUDE OIL AND CONDENSATE
During 1994, sales of crude oil and condensate to the Partnership's top
purchaser totaled approximately 8 percent of crude oil and condensate revenue.
No other customer purchased more than 4 percent of the Partnership's sales of
crude oil and condensate.
Since most of the Partnership's crude oil and condensate is produced in
areas where there are other buyers offering to purchase at market prices, the
Partnership believes that the loss of any major purchaser would not have a
material adverse effect on the Partnership's business. In 1994, the ten largest
customers accounted for approximately 22 percent of such sales.
Currently, approximately 53 percent of sales are made pursuant to
arrangements that are cancelable upon 30 days' written notice by the Partnership
or the purchaser, with substantially all of the remainder of the production
being sold pursuant to contracts of varying terms of up to ten years in length.
NATURAL GAS
The Partnership's natural gas marketing strategies are designed to be
effective in the current competitive environment. Sales of natural gas into
short-term markets averaged 56 percent of total sales. At year-end over 50
percent of total sales were contracted to end-users of natural gas on a long-
term basis. The Partnership's strategy is to sell to end-users that possess firm
transportation rights from the producing basin to the city gate on major
interstate pipelines. Contract length of these term sales ranges from one to ten
years.
During 1994, no individual customer accounted for more than five percent of
the Partnership's natural gas sales. The ten largest customers accounted for
approximately 13 percent of total gas sales during 1994.
HEDGING
Because of the volatility of oil and gas prices, the Partnership
periodically enters into crude oil and natural gas hedging activities.
REGULATION
GENERAL
The oil and gas industry is subject to regulation by national, state and
local governments relating to such matters as the award of exploration and
production interests, the imposition of specific drilling obligations,
environmental protection controls, control over the development and abandonment
of a field (including restrictions on production and abandonment of production
facilities). The industry is also subject to the payment of royalties and taxes,
which tend to be high compared to those levied on other commercial activities.
The Partnership cannot predict the impact of future regulatory and taxation
initiatives.
NATURAL GAS
The domestic gas industry remains under federal regulation pursuant to the
Natural Gas Act and the Natural Gas Policy Act. However, as a result of the
Natural Gas Decontrol Act, wellhead regulation of gas prices ended January 1,
1993.
6
<PAGE>
ENVIRONMENTAL MATTERS
The Partnership is subject to, and makes every effort to comply with,
various environmental quality control regulations of national and local
governments. Although environmental requirements can have a substantial impact
upon the energy industry, generally these requirements do not appear to affect
the Partnership any differently or to any greater or lesser extent than other
exploration and production companies.
The Partnership has been named as a potentially responsible party (PRP) at
four sites pursuant to the Comprehensive Environmental Response, Compensation,
and Liability Act of 1980, as amended. At two of these sites, the Partnership
has been named as a de minimis party and therefore expects its liability to be
small. At a third site, the Partnership is reviewing its options and anticipates
that it will participate in steering committee activities with the Environmental
Protection Agency (EPA). At the fourth and largest site, the Operating
Industries, Inc. site in California, the Partnership has participated in a
steering committee consisting of 139 companies. The steering committee and other
PRP's previously entered into two partial consent decrees with the EPA providing
for remedial actions which have been or are to be completed. The steering
committee has recently successfully negotiated a third partial consent decree
which provides for the following remedial actions: a clay cover, methane
capturing wells, and leachate destruction facilities. The remaining work at the
site involves groundwater evaluation and long-term operation and maintenance.
Based on the facts outlined above and the Partnership's ongoing analyses of
the actions where it has been identified as a PRP, the Partnership believes that
it has accrued sufficient reserves to absorb the ultimate cost of such actions
and that such costs will not have a material impact on the Partnership's
financial condition. While liability at superfund sites is typically joint and
several, the Partnership has no reason to believe that defaults by other PRP's
will result in liability of the Partnership materially larger than expected.
COMPETITION
The oil and gas industry is highly competitive. Integrated companies,
independent companies and individual producers and operators are active bidders
for desirable oil and gas properties, as well as for the equipment and labor
required to operate and develop such properties. Although several of these
competitors have financial resources substantially greater than those of the
Partnership, management believes that the Partnership is in a position to
compete effectively.
The availability of a ready market for the Partnership's oil and gas
production depends on numerous factors beyond its control, including the level
of prices and consumer demand, the extent of worldwide oil and gas production,
the cost and availability of alternative fuels, the cost and proximity of
pipelines and other transportation facilities, regulation by national and local
authorities and the cost of compliance with applicable environmental
regulations.
TECHNOLOGY
The Partnership's exploration, development and production activities depend
upon the use of applied technology. In support of this, the Partnership, through
the Company, has 29 engineers, geoscientists, technicians and support personnel
focusing on the technology used in the exploration for, and development and
production of, energy resources. The Partnership's expenditures on technology
activities, including its share of the Company's employee-related costs, were
$11 million, $15 million and $15 million for the years 1994, 1993 and 1992,
respectively.
CONFLICTS OF INTEREST
Certain conflicts of interest may arise as a result of the relationships
between the Company and the Partnership. The directors and officers of the
Company have fiduciary duties to manage the Company in the best interest of its
stockholders. The Company, as managing general partner of the Partnership, has a
fiduciary duty to manage the Partnership in a manner that is fair to the public
unitholders. The duty of the directors of the Company to its stockholders may
therefore come into conflict with the duties of the Company to the public
unitholders.
7
<PAGE>
The Audit Committee of the Board of Directors of the Company (Audit
Committee), none of whose members is affiliated with the Company except as
company directors or stockholders or as holders of units, reviews policies and
procedures developed by the Company for dealing with various matters as to which
a conflict of interest may arise. The Audit Committee also monitors the
application of such policies and procedures.
OTHER
The Partnership's financial condition and business operations are affected
from time to time by political developments and laws and regulations which
relate to such matters as production, taxes, property, imports, pricing and
environmental controls. The Company makes no representations as to future events
and developments which could affect the Partnership's operations and financial
condition. Oil and gas prices are subject to international supply and demand.
Political developments (especially in the Middle East) and the decisions of OPEC
can particularly affect world oil supply and oil prices. Furthermore, the
Partnership's business and financial condition could be affected by, among other
things, competition, future price changes or controls, material and labor costs,
legislation, transportation regulations, tariffs, embargoes and armed conflicts.
ITEM 3. LEGAL PROCEEDINGS
The Partnership is involved in a number of legal and administrative
proceedings arising in the ordinary course of its oil and gas business. Although
the ultimate outcome of these proceedings cannot be ascertained at this time, it
is reasonably possible that some of the proceedings could be resolved
unfavorably to the Partnership. Management of the Company believes that any
liabilities which may arise would not be material. The Company intends to
maintain liability and other insurance for the Partnership of the type customary
in the oil and gas business with such coverage limits as the Company deems
prudent.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNITHOLDERS
None.
PART II
ITEM 5.MARKET FOR THE REGISTRANT'S LIMITED PARTNERSHIP
UNITS AND RELATED SECURITY HOLDER MATTERS
The depositary units of Sun Energy Partners, L.P. are traded on the New York
Stock Exchange, Inc. The following table sets forth the high and low sales
prices per unit, as reported on the New York Stock Exchange Composite
Transactions quotations, for the periods indicated:
<TABLE>
<CAPTION>
1994 1993
------------------ ------------------
HIGH LOW HIGH LOW
------- ------- ------- -------
<S> <C> <C> <C> <C>
First Quarter........................... $ 7 3/8 $ 6 $ 8 7/8 $ 7 5/8
Second Quarter.......................... $ 6 1/8 $ 5 3/8 $ 8 3/4 $ 6 7/8
Third Quarter........................... $ 5 7/8 $ 4 1/8 $ 8 1/4 $ 7 1/8
Fourth Quarter.......................... $ 4 7/8 $ 3 3/4 $ 9 1/8 $ 6
</TABLE>
The Partnership had approximately 2,656 holders of record of depositary
units as of February 28, 1995.
During 1994 and 1993, the quarterly cash distributions per unit paid to
unitholders were as follows:
<TABLE>
<CAPTION>
1994 1993
--------- ---------
<S> <C> <C>
First Quarter............................................................................ $ .08 $ .25
Second Quarter........................................................................... $ .07 $ .16
Third Quarter............................................................................ $ .07 $ .23
Fourth Quarter........................................................................... $ .05 $ .18
</TABLE>
8
<PAGE>
The first quarterly cash distribution for 1995 in the amount of $.14 per
unit was paid in March 1995. Future quarterly cash distributions to unitholders
are expected to be paid on or about the 10th day of March, June, September and
December in each year. (See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Cash Distribution Policy.")
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
(MILLIONS OF DOLLARS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
For the Period
Revenues.................................................... $ 613 $ 676 $ 937 $ 1,079 $ 1,455
Income before cumulative effect of accounting change (1).... $ 100 $ 44 $ 120 $ 114 $ 300
Net income (loss) (1)....................................... $ (477) $ 44 $ 120 $ 114 $ 300
Net income per unit before cumulative effect of accounting
change (1)................................................. $ .24 $ .11 $ .29 $ .28 $ .77
Net income (loss) per unit (1).............................. $ (1.13) $ .11 $ .29 $ .28 $ .77
Cash distributions paid to unitholders (2).................. $ 114 $ 340 $ 360 $ 535 $ 531
Cash distributions per unit (2)............................. $ .27 $ .82 $ .87 $ 1.33 $ 1.36
Weighted average units outstanding (in thousands)........... 421.2 414.7 412.5 404.4 390.8
Capital expenditures........................................ $ 166 $ 199 $ 100 $ 306 $ 358
At End of Period
Total assets................................................ $ 1,181 $ 1,822 $ 2,038 $ 2,592 $ 3,636
Long-term debt (3).......................................... $ 74 $ 86 $ 100 $ 319 $ 887
Partners' capital........................................... $ 934 $ 1,525 $ 1,751 $ 1,991 $ 2,311
<FN>
------------------------
(1) Effective January 1, 1994, the Partnership adopted a new policy for
determining the ceiling test for its oil and gas properties. A one-time
non-cash charge of $577 million for the cumulative effect of the change was
recognized in the earnings for 1994. (See Note 7 to the Consolidated
Financial Statements.) The net income for 1993 includes a $7 million loss
from the sale of assets. The net incomes of 1992, 1991 and 1990 include
gains from sales of assets of $115 million, $75 million and $92 million.
(2) In the fourth quarter of 1993, the Company announced that it would no
longer purchase newly issued partnership units to fund the Partnership's
capital outlays. The Partnership will fund its capital outlays from
internally generated funds and make distributions to partners from the cash
flow remaining after such outlays (see Note 13 to the Consolidated
Financial Statements).
(3) Includes $72 million, $82 million, $91 million, $312 million and $932
million of long-term debt due to the Company. The Partnership prepaid $213
million and $575 million of such debt in 1992 and 1991.
</TABLE>
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Management's discussion and analysis of the Partnership's financial position
and results of operations follows. This discussion should be read in conjunction
with the Consolidated Financial Statements and Selected Financial Data included
in this report.
BUSINESS CLIMATE
The fundamentals in worldwide oil markets continue to reflect an excess of
supply over demand. Following very depressed price levels in early 1994, prices
improved as a result of OPEC's general adherence to announced quotas. Crude
prices continue to be impacted by the overhang of Iraq oil production as well as
increases in non-OPEC production. The Partnership's realized oil price in 1994
9
<PAGE>
fell by $1.27 per barrel, or 8 percent less than the 1993 price. The decline in
1994 followed a 14 percent decline in the Partnership's realized oil price in
1993 compared to 1992. Prices in early 1995 approximate the levels realized in
the fourth quarter of 1994.
As a result of unseasonable weather, natural gas supplies have exceeded
demand causing higher storage levels and depressed prices. The Partnership's
realized gas price in 1994 was $1.87 per mcf or 5 percent lower than the $1.96
per mcf realized in 1993. Natural gas prices remain depressed in early 1995.
The Partnership produced 50 million equivalent barrels of crude oil and
natural gas in 1994, 35 percent crude oil and 65 percent natural gas. Production
in 1995 is expected to be to approximately 44 million equivalent barrels of
crude oil and natural gas, depending on the timing of any asset sales.
RESULTS OF OPERATIONS
The Partnership's income in 1994, excluding the cumulative effect of an
accounting change, was $100 million, or $.24 per unit, as compared to net income
of $44 million, or $.11 per unit, in 1993 and net income of $120 million, or
$.29 per unit in 1992. (See Note 7 to the Consolidated Financial Statements.)
Higher income, before the cumulative effect of the accounting change, in
1994 as compared to 1993 was caused primarily by lower depreciation, depletion
and amortization expense and lower general and administrative expense offset by
lower crude oil production volumes and lower prices for both crude oil and
natural gas. Additionally, net income in 1993 included $7 million in losses from
the sale of assets while no gains or losses were included in net income in 1994.
Depreciation, depletion and amortization expense declined by $93 million or 36
percent primarily because of the accounting change effective at the beginning of
1994 which decreased the Partnership's producing property balance by $577
million. (See Note 7 to the Consolidated Financial Statements.) General and
administrative expense decreased by $15 million or 22 percent primarily because
of fewer employees of the Company which decreased the Company's charge to the
Partnership. Total costs and expenses decreased $119 million or 19 percent to
$513 million in 1994 from $632 million in 1993.
Lower net income in 1993 as compared to 1992 was caused by lower production
volumes and a lower average oil price partially offset by a higher average price
for gas and lower costs and expenses. Additionally, results for 1992 include
$115 million in gains from the sale of assets while results for 1993 include $7
million in losses from asset disposals. Oil volumes were 13 percent lower and
gas volumes were 11 percent lower in 1993 resulting from divestments of
producing properties in 1992. Total costs and expenses decreased $185 million or
23 percent to $632 million in 1993 from $817 million in 1992.
Average net production of oil in 1994 was 47 thousand barrels daily, or 15
percent lower than the average net production in 1993 of 55 thousand barrels
daily. The average price received for the Partnership's oil production in 1994
was $14.69 per barrel, representing an 8 percent decrease from the 1993 average
price of $15.96.
Average net production of oil in 1993 was 55 thousand barrels daily, or 13
percent lower than the average net production in 1992 of 63 thousand barrels
daily. The average price received for the Partnership's oil production in 1993
was $15.96 per barrel, representing a 14 percent decrease from the 1992 average
price of $18.51.
Average net production of gas in 1994 was 533 million cubic feet daily, or 3
percent higher than average net production for 1993 of 517 million cubic feet
daily. The Partnership received an average price of $1.87 per thousand cubic
feet for its gas production in 1994 compared to an average price of $1.96 per
thousand cubic feet in 1993, representing a 5 percent decrease.
10
<PAGE>
Average net production of gas in 1993 was 517 million cubic feet daily, or
11 percent lower than average net production for 1992 of 578 million cubic feet
daily. The Partnership received an average price of $1.96 per thousand cubic
feet for its gas production in 1993 compared to an average price of $1.72 per
thousand cubic feet in 1992, representing a 14 percent increase.
LIQUIDITY AND CAPITAL RESOURCES
In 1992, cash flow from operating activities decreased $208 million compared
to 1991 primarily due to lower sales volumes and oil prices, and reductions in
current liabilities, offset in part by an increase in gas prices and reductions
in costs and expenses. Cash flow provided from investing activities declined by
$28 million, reflecting a $258 million decrease in proceeds from divestments,
partially offset by a $206 million decrease in capital expenditures. Cash flow
used for financing activities decreased by $445 million in 1992, principally
reflective of declines of $361 million and $175 million in cash used for
repayments of long-term debt and cash distributions paid to unitholders, offset
in part by a $101 million decrease in cash flow provided from the sale of
limited partnership units.
In 1993, cash flow from operating activities increased $68 million from 1992
primarily due to favorable increases in cash from working capital components, a
higher average price for gas and lower costs and expenses partially offset by
lower production volumes and a lower average price for oil. Cash flow from
investing activities used $148 million in 1993 compared to providing $252
million in 1992. Proceeds from divestments were $298 million lower in 1993 while
capital expenditures increased by $99 million. Cash flow used for financing
activities decreased by $305 million in 1993 primarily because of the repayment
of $239 million in long-term debt in 1992 compared to repayment of $19 million
in 1993.
In 1994, cash flow from operating activities decreased $129 million compared
to 1993 primarily due to lower oil volumes, lower average prices for oil and gas
and unfavorable decreases in cash flow working capital components. Cash flow
from investing activities used $136 million in 1994 compared to a use of $148
million in 1993. Capital expenditures were $33 million lower and proceeds from
divestments were $17 million lower in 1994. Cash flow from financing activities
used $128 million in 1994 compared to a use of $284 million in 1993. Cash
distributions paid to unitholders were $226 million lower in 1994 than 1993 and
1993 included $70 million of cash flow from the sale of limited partnership
units. No such sale occurred in 1994.
In the fourth quarter of 1993, the Company's Board of Directors elected to
change its investment policy concerning ownership of the Partnership. Effective
in 1994, the policy of distributing all cash to unitholders and then selling
newly issued Partnership units to the Company to fund capital outlays was
changed. The Partnership now funds its capital outlays from internally generated
funds and makes distributions of only that cash remaining after such outlays.
The Partnership's spending levels will be governed by its cash flow from
operating activities which will continue to be affected by prevailing oil and
gas prices, cost levels and production volumes. Any shortfall in expected cash
flow from operating activities may require adjustment of the business plans.
Options include deferral of discretionary ED&A outlays and the sale of
Partnership units. The Partnership's long-term cash generation capability is
ultimately tied to the value of proved reserves.
RESERVE REPLACEMENT
The ability to sustain cash flow is dependent, among other things, on the
level of the Partnership's oil and gas reserves, oil and gas prices and cost
containment. Replacement of proved reserves through extensions and discoveries,
improved recovery, purchases and revisions to prior reserve estimates in 1994
was 35 percent of liquids production and 109 percent of gas production. Reserve
replacement rates of liquids and gas were 74 and 93 percent in 1993 and 17 and
68 percent in 1992.
HEDGING ARRANGEMENTS
The Partnership, from time to time, enters into hedging arrangements for oil
and natural gas prices. The Partnership has entered into swaps for approximately
26 percent of its estimated 1995
11
<PAGE>
crude oil production under agreements with an average price of $18.24 per
barrel. An additional 14 percent is under call option agreements at an average
price ceiling of $18.56 per barrel. Approximately 44 percent of its estimated
1995 gas production is under swap agreements with an average price of $1.88 per
mmbtu. The Partnership's hedging activities increased oil and gas revenue by $3
million in 1994 and decreased oil and gas revenue by $17 million in 1993. (See
Note 2 to the Consolidated Financial Statements.)
ENVIRONMENTAL
The Partnership's oil and gas operations are subject to stringent
environmental regulations. The Company is dedicated to the preservation of the
environment and has committed significant resources to comply with such
regulations. Although the Partnership has been named as a potentially
responsible party at sites related to past operations, the Company believes the
Partnership is in general compliance with applicable governmental regulations
and that the potential costs to it, in the aggregate, are not material to its
financial condition. However, risks of substantial costs and liabilities are
inherent in the oil and gas business. Should other developments occur, such as
increasingly strict environmental laws, regulations and enforcement policies or
claims for damages resulting from the Partnership's operations, they could
result in additional costs and liabilities in the future. (See Note 14 to the
Consolidated Financial Statements.)
CASH DISTRIBUTION POLICY
In the fourth quarter of 1993, the Company's Board of Directors elected to
change the Company's investment policy concerning purchase of additional
Partnership units. Effective in 1994, the Company no longer routinely purchases
newly issued Partnership units to fund capital outlays. The Partnership now
funds its capital outlays from internally generated funds and make distributions
of only that cash remaining after such outlays. The newly adopted policy reduced
the cash paid to unitholders in 1994 and will reduce the cash paid to
unitholders in the future, but will also end the ownership dilution caused by
the issuance of additional units.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL AND OPERATING
INFORMATION
<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
Report of Independent Accountants.......................................................................... 13
Financial Statements:
Consolidated Statements of Income for the Years Ended December 31, 1994, 1993 and 1992................... 14
Consolidated Balance Sheets at December 31, 1994 and 1993................................................ 15
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992............... 16
Notes to Consolidated Financial Statements............................................................... 17
Supplementary Financial and Operating Information -- (Unaudited):
Oil and Gas Data......................................................................................... 25
Quarterly Financial Information.......................................................................... 28
Quarterly Operating Information.......................................................................... 29
</TABLE>
12
<PAGE>
SUN ENERGY PARTNERS, L.P.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Sun Energy Partners, L.P. and the Board of Directors of Oryx
Energy Company:
We have audited the accompanying consolidated balance sheets of Sun Energy
Partners, L.P. and its Subsidiaries as of December 31, 1994 and 1993 and the
related consolidated statements of income and cash flows for each of the three
years in the period ended December 31, 1994. These financial statements are the
responsibility of Oryx Energy Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform 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, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Sun Energy
Partners, L.P. and its Subsidiaries as of December 31, 1994 and 1993, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1994 in conformity with generally
accepted accounting principles.
As discussed in Note 7 to the Consolidated Financial Statements, the
Partnership changed its accounting policy for calculating the oil and gas
ceiling test in 1994.
COOPERS & LYBRAND L.L.P.
Dallas, Texas
February 19, 1995
13
<PAGE>
SUN ENERGY PARTNERS, L.P
CONSOLIDATED STATEMENTS OF INCOME
(MILLIONS OF DOLLARS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1994 1993 1992
--------- --------- ---------
<S> <C> <C> <C>
Revenues
Oil and gas..................................................................... $ 618 $ 693 $ 791
Other -- net (Notes 3, 4 and 5)................................................. (5) (17) 146
--------- --------- ---------
613 676 937
--------- --------- ---------
Costs and Expenses
Operating costs................................................................. 195 195 213
Production taxes (Note 6)....................................................... 41 48 56
Exploration costs............................................................... 50 53 64
Depreciation, depletion and amortization........................................ 163 256 271
General and administrative expense (Note 3)..................................... 52 67 107
Interest and debt expense (Note 3).............................................. 17 13 44
Interest capitalized............................................................ (5) -- --
Provision for relinquishment of non-producing properties (Note 4)............... -- -- 62
--------- --------- ---------
513 632 817
--------- --------- ---------
Income Before Cumulative Effect of Accounting Change.............................. 100 44 120
Cumulative Effect of Accounting Change (Note 7)................................... (577) -- --
--------- --------- ---------
Net Income (Loss)................................................................. $ (477) $ 44 $ 120
--------- --------- ---------
--------- --------- ---------
Net Income (Loss) Per Unit:
Before cumulative effect of accounting change................................... $ .24 $ .11 $ .29
Cumulative effect of accounting change.......................................... (1.37) -- --
--------- --------- ---------
Net income (loss)............................................................... $ (1.13) $ .11 $ .29
--------- --------- ---------
--------- --------- ---------
Cash Distributions Paid to Unitholders............................................ $ 114 $ 340 $ 360
--------- --------- ---------
--------- --------- ---------
Cash Distributions Per Unit....................................................... $ .27 $ .82 $ .87
--------- --------- ---------
--------- --------- ---------
Weighted Average Units Outstanding (In Millions).................................. 421.2 414.7 412.5
--------- --------- ---------
--------- --------- ---------
</TABLE>
(See Accompanying Notes)
14
<PAGE>
SUN ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(MILLIONS OF DOLLARS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31
--------------------
1994 1993
--------- ---------
<S> <C> <C>
Current Assets
Cash and short-term investments............................................................ $ 11 $ 4
Advances to affiliate (Note 3)............................................................. 9 --
Accounts and notes receivable and other current assets..................................... 88 113
--------- ---------
Total Current Assets......................................................................... 108 117
Properties, Plants and Equipment (Note 8).................................................... 993 1,625
Investment in Affiliate (Note 1)............................................................. 80 80
--------- ---------
Total Assets................................................................................. $ 1,181 $ 1,822
--------- ---------
--------- ---------
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Advances from affiliate (Note 3)........................................................... $ -- $ 22
Accounts payable........................................................................... 62 77
Accrued liabilities (Note 9)............................................................... 72 73
Current portion of long-term debt due affiliate (Note 10).................................. 10 9
Current portion of long-term debt (Note 10)................................................ 2 5
--------- ---------
Total Current Liabilities.................................................................... 146 186
Long-Term Debt Due Affiliate (Note 10)....................................................... 72 82
Long-Term Debt (Note 10)..................................................................... 2 4
Deferred Credits and Other Liabilities (Note 14)............................................. 27 25
Commitments and Contingent Liabilities (Note 11)
Partners' Capital (Notes 12 and 13)
Limited partnership interests.............................................................. 286 468
General partnership interests.............................................................. 648 1,057
--------- ---------
Partners' Capital............................................................................ 934 1,525
--------- ---------
Total Liabilities and Partners' Capital...................................................... $ 1,181 $ 1,822
--------- ---------
--------- ---------
<FN>
------------------------
The successful efforts method of accounting is followed.
</TABLE>
(See Accompanying Notes)
15
<PAGE>
SUN ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1994 1993 1992
--------- --------- ---------
<S> <C> <C> <C>
Cash and Cash Equivalents From Operating Activities
Net Income (Loss)..................................................................... $ (477) $ 44 $ 120
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization.......................................... 163 256 271
Dry hole costs and leasehold impairment........................................... 27 24 37
(Gain) loss on sale of assets..................................................... -- 7 (115)
Provision for relinquishment of non-producing properties.......................... -- -- 62
Cumulative effect of accounting change............................................ 577 -- --
Other............................................................................. 6 10 7
--------- --------- ---------
296 341 382
Changes in working capital:
Accounts and notes receivable and other current assets............................ 25 46 28
Accounts payable, accrued liabilities and advances from affiliates................ (41) 22 (69)
--------- --------- ---------
Net Cash Flow Provided From Operating Activities...................................... 280 409 341
--------- --------- ---------
Cash and Cash Equivalents From Investing Activities
Capital expenditures................................................................ (166) (199) (100)
Proceeds from divestments........................................................... 42 59 357
Other............................................................................... (12) (8) (5)
--------- --------- ---------
Net Cash Flow Provided From (Used For) Investing Activities........................... (136) (148) 252
--------- --------- ---------
Cash and Cash Equivalents From Financing Activities
Proceeds from borrowings............................................................ -- 5 10
Repayments of long-term debt........................................................ (14) (19) (239)
Cash distributions paid to unitholders.............................................. (114) (340) (360)
Sale of limited partnership units................................................... -- 70 --
--------- --------- ---------
Net Cash Flow Used For Financing Activities........................................... (128) (284) (589)
--------- --------- ---------
Changes in Cash and Cash Equivalents.................................................. 16 (23) 4
Cash and Cash Equivalents at Beginning of Year........................................ 4 27 23
--------- --------- ---------
Cash and Cash Equivalents at End of Year.............................................. $ 20 $ 4 $ 27
--------- --------- ---------
--------- --------- ---------
</TABLE>
(See Accompanying Notes)
16
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION AND CONTROL
Sun Energy Partners, L.P. (Sun Energy Partners), a Delaware limited
partnership, was formed on October 1, 1985 and prior to December 1, 1985 had no
operations and nominal assets and equity. Effective as of December 1, 1985, Sun
Energy Partners succeeded to all the domestic oil and gas operations of Oryx
Energy Company and certain of its affiliates (collectively, the Company). These
operations consist of the exploration for and development of oil and natural gas
reserves in the United States.
Sun Energy Partners is controlled by the Company, which is the managing
general partner. As of December 31, 1994, the Company had a partnership interest
of 98 percent in Sun Energy Partners. The remaining two percent limited
partnership interest is held by public unitholders in the form of depositary
units. Eighty-five percent of the Company's Board of Directors must approve any
additional issuance, sale or transfer of units which would reduce the Company's
holdings in Sun Energy Partners below eighty-five percent.
Sun Energy Partners operates through Sun Operating Limited Partnership, a
Delaware limited partnership, and several other operating partnerships
(collectively, the Operating Partnerships). In all of the partnerships which
comprise the Operating Partnerships, Sun Energy Partners holds a 99 percent
interest as the sole limited partner, while the Company holds a one percent
interest as the managing general partner.
Sun Energy Partners and the Operating Partnerships (collectively, the
Partnership) have no officers or employees. The officers and employees of the
Company perform all management functions.
BASIS OF PRESENTATION
The Partnership's consolidated financial statements have been prepared using
the proportionate method of consolidation for Sun Energy Partners and its 99
percent interest in the Operating Partnerships. Such financial statements are
prepared in accordance with generally accepted accounting principles which is
different from the basis used for reporting taxable income or loss to
unitholders.
CASH EQUIVALENTS
The Partnership considers highly liquid investments with original maturities
of less than three months to be cash equivalents. Cash equivalents are stated at
cost which approximates market value.
PROPERTIES, PLANTS AND EQUIPMENT
The successful efforts method of accounting is followed for costs incurred
in oil and gas operations.
CAPITALIZATION POLICY. Acquisition costs are capitalized when incurred.
Costs of unproved properties are transferred to proved properties when proved
reserves are found. Exploration costs, including geological and geophysical
costs and costs of carrying and retaining unproved properties, are charged
against income as incurred. Exploratory drilling costs are capitalized
initially; however, if it is determined that an exploratory well does not
contain proved reserves, such capitalized costs are charged to expense, as dry
hole costs, at that time. Development costs are capitalized. Costs incurred to
operate and maintain wells and equipment are expensed.
LEASEHOLD IMPAIRMENT AND DEPRECIATION, DEPLETION AND AMORTIZATION. Periodic
valuation provisions for impairment of capitalized costs of unproved properties
are expensed. The acquisition costs of proved properties are depleted by the
unit-of-production method based on proved reserves by field.
17
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Capitalized exploratory drilling costs which result in the discovery of proved
reserves and development costs are amortized by the unit-of-production method
based on proved developed reserves by field.
CEILING TEST. The Partnership periodically compares the estimated
undiscounted future cash flows of its proved reserves to their net book values,
using current realized prices and costs held constant. Effective January 1,
1994, the Partnership changed its policy for performing ceiling test comparisons
to a field-by-field basis (Note 7). Prior to 1994, the Partnership performed its
ceiling test comparisons on a total partnership basis. The Partnership impairs
the net book value of its proved properties to the extent that net book values
exceed the estimated undiscounted future cash flows.
DISMANTLEMENT, RESTORATION AND ABANDONMENT COSTS. Estimated costs of future
dismantlement, restoration and abandonment are accrued as a component of
depreciation, depletion and amortization expense; actual costs are charged to
the accrual.
RETIREMENTS. Gains and losses on the disposals of fixed assets are
generally reflected in income. For certain property groups, the cost less
salvage value of property sold or abandoned is charged to accumulated
depreciation, depletion and amortization except that gains and losses for these
groups are taken into income for unusual retirements or retirements involving an
entire property group.
INVESTMENT IN AFFILIATE
Effective in 1988, the Company issued three million shares of its $1 par
value common stock to an operating partnership of the Partnership in exchange
for certain assets. These shares are not entitled to vote at the Company's
annual meetings of shareholders. The Partnership accounts for this investment
under the cost method, whereby investment income is recognized by the
Partnership if and when common dividends are received from the Company. In
January 1994, Oryx Energy Company suspended the payment of quarterly dividends
to holders of its common stock.
CAPITALIZED INTEREST
The Partnership capitalizes interest costs incurred as a result of the
acquisition and installation of significant assets.
INCOME TAXES
The Operating Partnerships and Sun Energy Partners are treated as
partnerships for income tax purposes and, as a result, income or loss of the
Partnership is includable in the tax returns of the individual unitholders.
Accordingly, no recognition has been given to income taxes in the financial
statements.
At December 31, 1994, 1993 and 1992, the Partnership's financial reporting
bases of assets and liabilities exceeded the tax bases of its assets and
liabilities (net temporary differences) by $544 million, $1,049 million and
$1,077 million.
CASH FLOWS
For purposes of reporting cash flows, cash and cash equivalents includes
cash, highly liquid investments with remaining maturities of less than three
months (see "Cash Equivalents", above) and advances to affiliate.
Interest paid totaled $17 million, $13 million and $45 million in 1994, 1993
and 1992.
18
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
During 1994, the Partnership exchanged its interest in an undeveloped block
in the Gulf of Mexico for a royalty interest in Viosca Knoll 826. This
transaction was accounted for by the Partnership as a non-cash property
exchange. In accordance with Statement of Financial Accounting Standards No. 95,
"Statement of Cash Flows," non-cash transactions are not reflected within the
accompanying Consolidated Statements of Cash Flows.
SALES OF OIL AND GAS
Sales of oil and gas are recorded on the entitlement method. Differences
between actual production and entitlements result in a receivable when
underproduction occurs and a payable when overproduction occurs.
During 1994, sales of oil to the Partnership's top purchaser totaled
approximately 8 percent of oil revenue. During 1993, sales of oil to the
Partnership's top purchasers totaled approximately 21 and 16 percent. During
1994 and 1993, no individual customer accounted for more than 5 percent of the
Partnership's gas sales. The Partnership believes that the loss of any major
purchaser would not have a material adverse effect on its business.
OIL AND GAS PRICE HEDGING ACTIVITY
The Partnership, from time to time, enters into futures contracts to hedge
the impact of price fluctuations on anticipated crude oil and natural gas sales.
Advance payments under such contracts are deferred and charged to oil and gas
revenue during the anticipated sales periods. The differentials paid or received
during the terms of such agreements are accrued as oil and gas prices change and
are charged or credited to oil and gas sales (Note 2).
ENVIRONMENTAL COSTS
The Partnership establishes reserves for environmental liabilities as such
liabilities are incurred (Note 14).
STATEMENT PRESENTATION
Certain items in years prior to 1994 have been reclassified to conform to
the 1994 presentation.
2) FINANCIAL INSTRUMENTS
DERIVATIVES
As discussed in Note 1, the Partnership enters into hedging arrangements for
crude oil and natural gas prices with major financial institutions. The
Partnership does not enter into derivative transactions for trading purposes.
At December 31, 1994, the Partnership was a party to crude oil and natural
gas hedging contracts to hedge about 11 percent of its estimated 1995 crude oil
production at $17.80 per barrel and 40 percent of its estimated 1995 natural gas
production at $1.95 per mmbtu. At December 31, 1993, the Partnership was a party
to natural gas hedging contracts to hedge about 30 percent of its 1994 natural
gas production at an average floor of $2.04 per mmbtu and an average ceiling of
$2.28 per mmbtu. These arrangements serve to reduce the volatility associated
with prices of crude oil and natural gas. The aggregate carrying values of these
assets at December 31, 1994 and 1993 were nil, and the aggregate fair values,
based on quotes from brokers, were approximately $13 million and $4 million.
The above mentioned derivative contracts expose the Partnership to credit
risks. The Partnership has established controls to manage this risk and closely
monitors the creditworthiness of its counterparties which are major financial
institutions. The Partnership believes that losses from nonperformance are
unlikely to occur.
19
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2) FINANCIAL INSTRUMENTS (CONTINUED)
OTHER FINANCIAL INSTRUMENTS
At December 31, 1994 and 1993, the carrying values of the Partnership's
long-term debt, including amounts due within one year, were $86 million and $100
million (Note 10). At December 31, 1994 and 1993, the aggregate fair values of
the Partnership's long-term debt were approximately $93 million and $153
million, estimated primarily based on current rates available to the Partnership
for debt of the same remaining maturities.
3) RELATED PARTY TRANSACTIONS
ADVANCES TO/FROM AFFILIATE
The Company has served as the Partnership's lender and borrower of funds and
a clearing-house for the settlement of intercompany receivables and payables.
Deposits earn interest at a rate equal to the rate paid by a major money market
fund. Demand loans bear interest at a rate based on the prime rate.
LONG-TERM DEBT DUE AFFILIATE
The Partnership is indebted to the Company under a 9.75% note due 1995-2001.
In 1992 the Partnership prepaid $213 million of such debt from proceeds of asset
sales.
DIRECT AND INDIRECT COSTS
The Company is reimbursed by the Partnership for all direct costs incurred
in performing management functions and indirect costs (including payroll and
payroll related costs and the cost of postemployment benefits and management
incentive plans) allocable to the Partnership. The full cost of direct and
indirect costs incurred on behalf of the Partnership by the Company is allocated
to the Partnership based on services rendered and extent of use. Such costs,
which are charged principally to production cost, exploration cost and general
and administrative expense, totaled $73 million, $104 million and $127 million
for the years 1994, 1993 and 1992. The Company does not receive any carried
interests, promotions, back-ins or other similar compensation as the general
partner of the Partnership.
INTEREST INCOME
Interest income received from the Company, which is reflected in other
revenues in the consolidated statements of income, was earned on advances to the
Company and totaled $3 million, $5 million and $9 million during the years 1994,
1993 and 1992.
INTEREST COST
Interest cost paid to the Company, which is included in interest and debt
expense in the consolidated statements of income, was primarily incurred on
long-term debt due the Company and totaled $16 million, $12 million and $43
million during the years 1994, 1993 and 1992 (Note 10).
4) CHANGES IN BUSINESS
In 1991, the Company commenced a major restructuring program (Restructuring)
to reduce the Company's and Partnership's cost structures. The program outlined
a plan to sell substantially all of the Partnership's gas plant business (Note
5) and certain onshore producing oil and gas properties.
Associated with the Restructuring, the Partnership recognized a $62 million
provision for the early relinquishment of certain non-producing properties in
1992. At December 31, 1994, the asset disposals were complete.
In the first quarter of 1994, the Partnership recognized an $84 million
restructuring charge. This provision was revised to zero because of the
accounting change (Note 7).
20
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5) OTHER REVENUES -- NET
The components of other revenues were as follows:
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Interest income............................................................. $ 3 $ 5 $ 10
Gas plant margins*.......................................................... 3 4 29
Gain (loss) on sale of assets............................................... -- (7) 115
Miscellaneous............................................................... (11) (19) (8)
--- --- ---------
$ (5) $ (17) $ 146
--- --- ---------
--- --- ---------
<FN>
------------------------
*Associated with the Restructuring announced in 1991, the Company sold
substantially all of the Partnership's gas plant business.
</TABLE>
6) PRODUCTION TAXES
Production taxes consisted of the following:
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Severance...................................................................... $ 26 $ 31 $ 37
Property taxes................................................................. 15 17 19
--- --- ---
$ 41 $ 48 $ 56
--- --- ---
--- --- ---
</TABLE>
7) ACCOUNTING CHANGE
Effective January 1, 1994, the Partnership changed its accounting policy for
calculating the oil and gas asset ceiling test from a total Partnership basis to
an individual field basis. The Partnership believes the field basis is
preferable because it is the way the Partnership manages its business. The basis
underlying the calculation of the cumulative effect of this change is a
comparison of the undiscounted cash flows of each field's then existing proved
reserves to its net book value at each quarter-end during the life of the asset.
This subjects the ceiling test valuation to the lowest quarter-end price
experienced over the asset's life. As a result of this change, the Partnership
recognized a non-cash cumulative effect charge of $577 million to 1994 results.
Excluding the cumulative charge, the Partnership's income for 1994 was $100
million ($.24 per unit). On a pro forma basis, the Partnership reported net
earnings for 1993 and 1992 would have been a net loss of $198 million ($.47 per
unit) and net earnings of $63 million ($.15 per unit) if this accounting change
had been enacted prior to 1992.
21
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8) PROPERTIES, PLANTS AND EQUIPMENT
At December 31, the Partnership's properties, plants and equipment and
accumulated depreciation, depletion and amortization were as follows:
<TABLE>
<CAPTION>
1994 1993
---------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Gross Investment
Proved oil and gas properties.............................................. $ 3,914 $ 4,130
Unproved oil and gas properties............................................ 42 59
Other...................................................................... 59 58
---------- ----------
4,015 4,247
---------- ----------
Less Accumulated Depreciation, Depletion and Amortization
Proved oil and gas properties*............................................. 2,969** 2,571
Other...................................................................... 53 51
---------- ----------
3,022 2,622
---------- ----------
Net Investment............................................................... $ 993 $ 1,625
---------- ----------
---------- ----------
<FN>
------------------------
* Includes $29 million and $25 million for dismantlement, restoration and
abandonment at December 31, 1994 and 1993.
** Includes $577 million of impairment of proved oil and gas properties in
1994 (Note 7).
</TABLE>
9) ACCRUED LIABILITIES
At December 31, the Partnership's accrued liabilities were comprised of the
following:
<TABLE>
<CAPTION>
1994 1993
---- ----
(MILLIONS
OF DOLLARS)
<S> <C> <C>
Drilling and operating costs.................................................... $ 37 $ 35
Taxes payable................................................................... 19 23
Other........................................................................... 16 15
---- ----
$ 72 $ 73
---- ----
---- ----
</TABLE>
10) LONG-TERM DEBT
At December 31, the Partnership's long-term debt consisted of the following:
<TABLE>
<CAPTION>
1994 1993
---- ----
(MILLIONS
OF DOLLARS)
<S> <C> <C>
9.75% note payable to affiliate, due 1995-2001, payable in quarterly
installments................................................................... $ 82 $ 91
Capitalized lease obligation due 1996........................................... 4 6
Capitalized lease obligation and other long-term debt due 1994.................. -- 3
---- ----
86 100
Less: Current portion of note payable to affiliate.............................. 10 9
Current portion of capitalized lease obligations and other long-
term debt................................................................ 2 5
---- ----
$ 74 $ 86
---- ----
---- ----
</TABLE>
Under the Partnership's existing capitalized lease obligation, the
Partnership is obligated to make an annual payment of $2 million in each of the
years 1995 and 1996.
22
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10) LONG-TERM DEBT (CONTINUED)
Repayment obligations under the Partnership's long-term debt due affiliate
are $10 million, $11 million, $12 million, $13 million and $14 million in 1995,
1996, 1997, 1998 and 1999.
11) COMMITMENTS AND CONTINGENT LIABILITIES
The Partnership has operating leases for office space and other property and
equipment. Total rental expense for such leases for the years 1994, 1993 and
1992 was $33 million, $28 million and $28 million. Under contracts existing as
of December 31, 1994, future minimum annual rentals applicable to noncancellable
operating leases that have initial or remaining lease terms in excess of one
year were as follows (in millions of dollars):
<TABLE>
<S> <C>
Year Ending December 31:
1995.......................................................................... $ 24
1996.......................................................................... 8
1997.......................................................................... 3
1998.......................................................................... 3
1999.......................................................................... 3
Later years................................................................... 1
---
Total minimum payments required............................................. $ 42
---
---
</TABLE>
Several legal and administrative proceedings are pending against the
Partnership. Although the ultimate outcome of these proceedings cannot be
ascertained at this time, and it is reasonably possible that some of them could
be resolved unfavorably to the Partnership, management believes that any
liabilities which may arise would not be material.
12) PARTNERS' CAPITAL
<TABLE>
<CAPTION>
GENERAL PARTNER
LIMITED PARTNERS ----------------
----------------------------------------------------
ORYX ENERGY ORYX ENERGY
PUBLIC COMPANY TOTAL COMPANY TOTAL
-------------- ---------------- ---------------- ---------------- ----------------
UNITS DOLLARS UNITS DOLLARS UNITS DOLLARS UNITS DOLLARS UNITS DOLLARS
----- ------- ------- ------- ------- ------- ------- ------- ------- -------
(DOLLARS IN MILLIONS, UNITS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
December 31, 1991...................... 7,543 $ 38 112,912 $ 543 120,455 $ 581 292,000 $1,410 412,455 $1,991
Cash distributions................... -- (7) -- (99) -- (106) -- (254) -- (360)
Net income........................... -- 2 -- 33 -- 35 -- 85 -- 120
----- ------- ------- ------- ------- ------- ------- ------- ------- -------
December 31, 1992...................... 7,543 33 112,912 477 120,455 510 292,000 1,241 412,455 1,751
Sale of limited partnership units.... -- 1 8,716 48 8,716 49 -- 21 8,716 70
Cash distributions................... -- (7) -- (94) -- (101) -- (239) -- (340)
Net income........................... -- -- -- 10 -- 10 -- 34 -- 44
----- ------- ------- ------- ------- ------- ------- ------- ------- -------
December 31, 1993...................... 7,543 27 121,628 441 129,171 468 292,000 1,057 421,171 1,525
Cash distributions................... -- (2) -- (33) -- (35) -- (79) -- (114)
Net loss............................. -- (9) -- (138) -- (147) -- (330) -- (477)
----- ------- ------- ------- ------- ------- ------- ------- ------- -------
December 31, 1994...................... 7,543 $ 16 121,628 $ 270 129,171 $ 286 292,000 $ 648 421,171 $ 934
----- ------- ------- ------- ------- ------- ------- ------- ------- -------
----- ------- ------- ------- ------- ------- ------- ------- ------- -------
</TABLE>
13) CASH DISTRIBUTIONS
Beginning with the fourth quarter 1993, Distributable Cash was reduced by
the cash needed for capital outlays. This policy change reduced the cash paid to
unitholders but ended the ongoing ownership dilution faced by unitholders due to
Oryx Energy's purchases of newly issued partnership units to fund Sun Energy's
capital outlays. Distributable Cash is defined as revenues (including interest
income) less production cost; seismic, geological and geophysical costs
(including related costs); payments of principal of and interest on debt;
general and administrative expenses including
23
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
13) CASH DISTRIBUTIONS (CONTINUED)
reimbursements of the Company as managing general partner; adjustments for
capital expenditures (net of proceeds from divestments); and cash exploration
costs. No deduction is made for depreciation, depletion and amortization, for
property acquisition, and development expenditures.
Sun Energy Partners' quarterly cash distributions per unit for the years
1994, 1993 and 1992 were as follows:
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
<S> <C> <C> <C>
First Quarter.................................................................... $ .08 $ .25 $ .28
Second Quarter................................................................... .07 .16 .19
Third Quarter.................................................................... .07 .23 .18
Fourth Quarter................................................................... .05 .18 .22
</TABLE>
14) DEFERRED CREDITS AND OTHER LIABILITIES
At December 31, the Partnership's deferred credits and other liabilities
were comprised of the following:
<TABLE>
<CAPTION>
1994 1993
----- -----
(MILLIONS OF DOLLARS)
<S> <C> <C>
Accrued environmental cleanup costs............................................ $ 21 $ 20
Other.......................................................................... 6 5
--- ---
$ 27 $ 25
--- ---
--- ---
</TABLE>
Environmental cleanup costs have been accrued in response to the
identification of several sites that require cleanup based on environmental
pollution, some of which have been designated as superfund sites by the
Environmental Protection Agency (EPA). The Partnership has been named as a
Potentially Responsible Party (PRP) at four sites pursuant to the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980, as amended. At
two of these sites, the Partnership has been named as a de minimis party and
therefore expects its liability to be small. At a third site, the Partnership is
reviewing its options and anticipates that it will participate in steering
committee activities with the Environmental Protection Agency. At the fourth and
largest site, the Operating Industries, Inc. site in California, the Partnership
has participated in a steering committee consisting of 139 companies. The
steering committee and other PRP's previously entered into two partial consent
decrees with the EPA providing for remedial actions which have been or are to be
completed. The steering committee has successfully negotiated a third partial
consent decree which provides for the following remedial actions: a clay cover,
methane capturing wells, and leachate destruction facilities. The remaining work
at the site involves groundwater evaluation and long-term operation and
maintenance. The Partnership is a member of the group that is responsible for
carrying out the first phase of the work, which is expected to take 5 to 8
years. Completion of all phases is estimated to take up to 30 years. The maximum
liability of the group, which is joint and several for each member of the group,
is expected to range from approximately $450 million to $600 million, of which
the Partnership's share is expected to be approximately $10 million (net of $3
million in recoveries from third parties). Cleanup costs are payable over the
period that the work is completed.
Based on the facts outlined above and the Partnership's ongoing analyses of
the actions where it has been identified as a PRP, the Partnership believes that
it has accrued sufficient reserves to absorb the ultimate cost of such actions
and that such costs therefore will not have a material impact on the
Partnership's liquidity, capital resources or financial condition. While
liability at superfund sites is typically joint and several, the Partnership has
no reason to believe that defaults by other PRPs will result in liability of the
Partnership materially larger than expected.
24
<PAGE>
SUN ENERGY PARTNERS, L.P.
SUPPLEMENTARY FINANCIAL
AND OPERATING INFORMATION (UNAUDITED)
OIL AND GAS DATA
CAPITALIZED COSTS
<TABLE>
<CAPTION>
DECEMBER 31
--------------------------
1994 1993
---------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Proved properties............................................................. $ 3,914 $ 4,130
Unproved properties........................................................... 42 59
---------- ----------
Total capitalized costs....................................................... 3,956 4,189
Less accumulated depreciation, depletion and amortization..................... 2,969 2,571
---------- ----------
Net capitalized costs......................................................... $ 987 $ 1,618
---------- ----------
---------- ----------
</TABLE>
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Property acquisition costs:
Proved....................................................................... $ -- $ 9 $ --
Unproved..................................................................... 4 8 --
Exploration costs.............................................................. 38 58 48
Development costs.............................................................. 142 145 84
--------- --------- ---------
$ 184 $ 220 $ 132
--------- --------- ---------
--------- --------- ---------
</TABLE>
EXPLORATION COSTS
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Dry hole costs................................................................. $ 9 $ 21 $ 11
Leasehold impairment........................................................... 18 3 26
Geological and geophysical..................................................... 21 27 25
Other.......................................................................... 2 2 2
--------- --------- ---------
$ 50 $ 53 $ 64
--------- --------- ---------
--------- --------- ---------
</TABLE>
ESTIMATED NET QUANTITIES OF PROVED OIL AND GAS RESERVES
Proved reserve quantities were based on estimates prepared by Company
engineers in accordance with guidelines established by the Securities and
Exchange Commission and were reviewed by Gaffney, Cline & Associates, Inc.,
independent petroleum engineers. The Partnership considers such estimates to be
reasonable; however, due to inherent uncertainties and the limited nature of
reservoir data, estimates of underground reserves are imprecise and subject to
change over time as additional information becomes available.
25
<PAGE>
SUN ENERGY PARTNERS, L.P.
There has been no major discovery or other favorable or adverse event that
has caused a significant change in estimated proved reserves since December 31,
1994. The Partnership has no long-term supply agreements or contracts with
governments or authorities in which it acts as producer nor does it have any
interest in oil and gas operations accounted for by the equity method. All
reserves are located onshore and offshore within the United States.
<TABLE>
<CAPTION>
RECOVERABLE
CRUDE OIL AND NATURAL GAS
CONDENSATE LIQUIDS NATURAL GAS
(MILLIONS OF (MILLIONS OF (BILLIONS OF
BARRELS) BARRELS) CUBIC FEET)*
----------------- --------------- -------------
<S> <C> <C> <C>
PROVED RESERVES
BALANCE AT DECEMBER 31, 1991...................................... 291 65 1,757
Revisions of previous estimates................................... (14) -- (31)
Improved recovery................................................. 4 -- 1
Purchases of minerals in place.................................... -- -- --
Sales of minerals in place........................................ (21) (33) (195)
Extensions and discoveries........................................ 15 -- 175
Production........................................................ (23) (7) (212)
--
--- ------
BALANCE AT DECEMBER 31, 1992...................................... 252 25 1,495
Revisions of previous estimates................................... (4) (1) 5
Improved recovery................................................. 1 -- 1
Purchases of minerals in place.................................... -- -- 4
Sales of minerals in place........................................ (12) (2) (65)
Extensions and discoveries........................................ 19 2 166
Production........................................................ (20) (3) (189)
--
--- ------
BALANCE AT DECEMBER 31, 1993...................................... 236 21 1,417
Revisions of previous estimates................................... (2) 3 23
Improved recovery................................................. -- -- --
Purchases of minerals in place.................................... -- -- 2
Sales of minerals in place........................................ (22) -- (114)
Extensions and discoveries........................................ 6 -- 186
Production........................................................ (17) (3) (194)
--
--- ------
BALANCE AT DECEMBER 31, 1994...................................... 201 21 1,320
--
--
--- ------
--- ------
Proved Developed Reserves At:
December 31, 1991............................................... 210 56 1,337
December 31, 1992............................................... 173 20 1,058
December 31, 1993............................................... 154 16 1,000
December 31, 1994............................................... 128 16 898
<FN>
------------------------
*Natural gas volumes include liquefiable hydrocarbons approximating 5 percent
of total gas reserves which are recoverable at natural gas processing plants
downstream from the lease or field separation facilities. Such recoverable
liquids also have been included in natural gas liquids reserve volumes.
</TABLE>
26
<PAGE>
SUN ENERGY PARTNERS, L.P.
STANDARDIZED MEASURE
The standardized measure of discounted future net cash flows from estimated
production of proved oil and gas reserves is presented in accordance with the
provisions of Statement of Financial Accounting Standards No. 69, "Disclosures
about Oil and Gas Producing Activities" (SFAS No. 69). In computing this data,
assumptions other than those mandated by SFAS No. 69 could produce substantially
different results. The Partnership cautions against viewing this information as
a forecast of future economic conditions or revenues.
The standardized measure has been prepared assuming year-end selling prices
adjusted for future fixed and determinable contractual price changes, year-end
development, production and direct general and administrative costs and a ten
percent annual discount rate. No future income tax expense has been provided for
the Partnership since it incurs no income tax liability. (See Summary of
Significant Accounting Policies Income Taxes in the Notes to Consolidated
Financial Statements.) The year-end realized prices were $15.30 and $11.58 per
barrel of oil and $1.75 and $1.91 per mcf of gas for 1994 and 1993.
<TABLE>
<CAPTION>
1994 1993
---------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Future cash inflows............................................................... $ 5,672 $ 5,744
Future production and development costs........................................... (2,921) (3,616)
---------- ----------
Future net cash flows............................................................. 2,751 2,128
Discount at 10 percent............................................................ (1,062) (992)
---------- ----------
Standardized measure.............................................................. $ 1,689 $ 1,136
---------- ----------
---------- ----------
</TABLE>
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Balance, beginning of year............................................... $ 1,136 $ 1,992 $ 2,737
Increase (decrease) in discounted future net cash flows:
Sales of oil and gas production net of related costs .................. (382) (440) (522)
Revisions to estimates of proved reserves:
Prices............................................................... 370 (767) 1
Development costs.................................................... 304 (30) (288)
Production costs..................................................... (116) (10) 202
Quantities........................................................... 10 (9) (70)
Other................................................................ (69) (11) (282)
Extensions, discoveries and improved recovery, less related costs...... 216 96 230
Development costs incurred during the period........................... 147 168 97
Purchases of reserves in place......................................... 2 6 --
Sales of reserves in place............................................. (43) (58) (387)
Accretion of discount.................................................. 114 199 274
--------- --------- ---------
Balance, end of year..................................................... $ 1,689 $ 1,136 $ 1,992
--------- --------- ---------
--------- --------- ---------
</TABLE>
27
<PAGE>
SUN ENERGY PARTNERS, L.P.
QUARTERLY FINANCIAL INFORMATION
<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------------
JUNE
MARCH 31 30 SEPTEMBER 30 DECEMBER 31
-------- ------ ------------ -----------
(MILLIONS OF DOLLARS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C>
Revenue:
1994
As reported............... $ 159 $ 154 $ 148
Restatement of other
revenues for accounting
change................... 2 1 2
-------- ------ -----
As restated............... $ 161 $ 155 $ 150 $ 147
-------- ------ ----- -----
-------- ------ ----- -----
1993........................ $ 168 $ 186 $ 165 $ 157
-------- ------ ----- -----
-------- ------ ----- -----
Gross profit:*
1994........................ $ 45 $ 41 $ 39 $ 47
-------- ------ ----- -----
-------- ------ ----- -----
1993........................ $ 35 $ 57 $ 40 $ 26
-------- ------ ----- -----
-------- ------ ----- -----
Net income (loss):
1994
As reported............... $ (82) $ -- $ 11
-------- ------ -----
-------- ------ -----
As restated
Before cumulative effect
of accounting change... $ 21 $ 17 $ 29 $ 33
Cumulative effective of
accounting change...... (577) -- -- --
-------- ------ ----- -----
$ (556) $ 17 $ 29 $ 33
-------- ------ ----- -----
-------- ------ ----- -----
1993........................ $ 6 $ 33 $ 14 $ (9)
-------- ------ ----- -----
-------- ------ ----- -----
Net income (loss) per unit:
1994
As reported............... $ (.19) $ -- $ .03
-------- ------ -----
-------- ------ -----
As restated
Before cumulative effect
of accounting change... $ .05 $ .04 $ .07 $ .08
Cumulative effect of
accounting charge...... (1.37) -- -- --
-------- ------ ----- -----
$(1.32) $ .04 $ .07 $ .08
-------- ------ ----- -----
-------- ------ ----- -----
1993........................ $ .01 $ .08 $ .03 $ (.02)
-------- ------ ----- -----
-------- ------ ----- -----
<FN>
------------------------
*Gross profit equals oil and gas revenues plus gas plant margins less
production cost, exploration cost and depreciation, depletion and
amortization.
</TABLE>
28
<PAGE>
SUN ENERGY PARTNERS, L.P.
QUARTERLY OPERATING INFORMATION
<TABLE>
<CAPTION>
QUARTER ENDED
--------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 YEAR
----------- --------- ------------- ------------ ---------
<S> <C> <C> <C> <C> <C>
Crude oil and condensate:
Net production (thousand barrels daily):
1994............................................. 50 48 47 44 47
1993............................................. 56 55 55 56 55
Average price (per barrel):
1994............................................. $ 12.72 $ 15.28 $ 15.34 $ 15.56 $ 14.69
1993............................................. $ 17.31 $ 17.44 $ 15.33 $ 13.81 $ 15.96
Natural gas:
Net production (million cubic feet daily):
1994............................................. 548 515 536 533 533
1993............................................. 509 528 516 516 517
Average price (per thousand cubic feet):
1994............................................. $ 2.12 $ 1.92 $ 1.71 $ 1.72 $ 1.87
1993............................................. $ 1.78 $ 2.06 $ 1.90 $ 2.09 $ 1.96
</TABLE>
29
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Partnership has no employees. The Company, as the managing general
partner of the Partnership, has the responsibility for the Partnership's conduct
of operations. Set forth below is information concerning the ten current
directors of the Company and the nine current executive officers of the Company
(three of which are also directors). All elected executive officers of the
Company are elected annually by the Board of Directors of the Company. The
directors are divided into three classes with approximately one-third of the
directors constituting the Board being elected each year to serve a three-year
term. Class I directors (whose term expires in 1995) are Mr. Gill, Mr.
Hollingsworth and Mr. Pistor. Class II directors (whose term expires in 1996)
are Mr. Keiser, Mr. Seegers and Mr. White-Thomson. Class III directors (whose
term expires in 1997) are Mr. Box, Mr. Bradford and Mr. Moneypenny.
<TABLE>
<CAPTION>
NAME, AGE AND BUSINESS EXPERIENCE DURING
POSITION WITH THE COMPANY PAST FIVE YEARS
----------------------------------------------------- -----------------------------------------------------------
<S> <C>
Jerry W. Box, 56 .................................... Mr. Box has been in this position since December 1, 1994.
Executive Vice President, Exploration and From January 1992 through November 1994, he was Senior
Production, and Director Vice President, Exploration and Production of the Company.
From 1987 to 1991, he was Vice President, Exploration.
William E. Bradford, 60 ............................. Mr. Bradford has been President, Chief Operating Officer
Director and a director of Dresser Industries, Inc. since March
1992. He was President and Chief Executive Officer of
Dresser-Rand Company from February 1988 to March 1992.
From March 1982 to March 1992, he was Senior Vice
President of Operations of Dresser Industries, Inc. Mr.
Bradford is a director of Diamond Shamrock, Inc.
David F. Chavenson, 42 .............................. Mr. Chavenson assumed this position in October 1993. For
Treasurer the five years previous thereto, he was Assistant
Treasurer and Manager, Corporate Finance and Credit of the
Company.
Sherri T. Durst, 45 ................................. Ms. Durst assumed this position in December 1993. From
General Auditor February 1990 to December 1993, she served as Manager,
Financial Processes. For the six years previous thereto,
she held the position of Financial Systems Project
Manager.
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
NAME, AGE AND BUSINESS EXPERIENCE DURING
POSITION WITH THE COMPANY PAST FIVE YEARS
----------------------------------------------------- -----------------------------------------------------------
<S> <C>
Robert B. Gill, 63 .................................. Mr. Gill served as Vice Chairman of the Board of J.C.
Director Penney Company, Inc. from 1982 and Chief Operating Officer
of J.C. Penney Stores and Catalog from March 1, 1990 until
his retirement on July 1, 1992. Prior to his retirement,
he was a director of the National Junior Achievement,
Chairman of the Board of Trustees of the National 4-H
Council and a member of the board of directors of the U.S.
Chamber of Commerce. He currently is a trustee of Pace
University. Mr. Gill was a director of Greyhound Lines,
Inc. from May 1994 to January 24, 1995.
David S. Hollingsworth, 66 .......................... Mr. Hollingsworth served as Chairman of the Board and Chief
Director Executive Officer of Hercules Incorporated from 1987 until
his retirement on December 31, 1990. From 1986 to 1987, he
was Vice Chairman of the same company. Previously, he was
Vice President with various responsibilities, including
corporate planning and marketing. Mr. Hollingsworth is a
member of the board of directors of the Delaware Trust
Company. Prior to his retirement, Mr. Hollingsworth was a
member of the board of directors of the U.S. Chamber of
Commerce. He was also a member of the board and the
executive committee of both the Chemical Manufacturers
Association and the Medical Center of Delaware and a
member of the Delaware Business Roundtable.
Robert L. Keiser, 52 ................................ Mr. Keiser assumed this position on December 1, 1994. From
Chairman of the Board, Chief Executive January 1992 through November 1994, he was President and
Officer, and President Chief Operating Officer of the Company. From January 1990
through December 1991, he was President and Chief
Executive Officer of Oryx U.K. Energy Company. He was also
Vice President, International Exploration and Production
for the Company from January 1990 until August 1990 and
from April 1991 through December 1991. From July 1987 to
December 1989, he was Vice President, Planning and
Development of the Company.
William C. Lemmer, 50 ............................... Mr. Lemmer assumed this position on February 2, 1995. From
Vice President, General Counsel and June 1994 until February 1995, he served as Vice President
Secretary and General Counsel to the Company. For the five previous
years, he was Chief Counsel to the Company.
</TABLE>
31
<PAGE>
<TABLE>
<CAPTION>
NAME, AGE AND BUSINESS EXPERIENCE DURING
POSITION WITH THE COMPANY PAST FIVE YEARS
----------------------------------------------------- -----------------------------------------------------------
<S> <C>
Edward W. Moneypenny, 53 ............................ Mr. Moneypenny has been in this position since December 1,
Executive Vice President, Finance, Chief 1994. From January 1992 through November 1994, he was
Financial Officer, and Director Senior Vice President, Finance and Chief Financial Officer
of the Company. From 1988 to 1991, he was Vice President,
Finance and Chief Financial Officer of the Company.
Charles H. Pistor, Jr., 64 .......................... Mr. Pistor has been the Vice Chair of Southern Methodist
Director University since October 1991. He served as Chairman of
the Board and Chief Executive Officer of NorthPark
National Bank from 1988 to 1990. He retired as Vice
Chairman of First RepublicBank Corporation, and Chairman
and Chief Executive Officer of First RepublicBank Dallas,
N.A. in April 1988. Before that time, he was Chairman of
the Board and Chief Executive Officer of RepublicBank
Dallas, N.A. Mr. Pistor is a past president of the
American Bankers Association Mr. Pistor also serves as a
director of AMR Corporation, American Brands, Inc. and
Centex Corporation. He is a trustee of Southern Methodist
University.
Paul R. Seegers, 65 ................................. Mr. Seegers is President of Seegers Enterprises. He was
Director Chairman of the Board of Centex Corporation from July 1988
until his retirement in July 1991. From July 1985 to July
1988, he was also its Chief Executive Officer and, from
July 1978 to July 1985, he was Vice Chairman and Co-Chief
Executive Officer. He is a member of the board of
directors of Centex Corporation and is Chairman of its
Executive Committee. Mr. Seegers is Chairman of the Board
of Methodist Hospitals of Dallas and a trustee of
Southwestern Medical Foundation.
William P. Stokes, Jr., 53 .......................... Mr. Stokes assumed this position on February 2, 1995. From
Vice President, Marketing January 1993 until February 1995, he was Vice President,
Corporate Development and Human Relations. From January
1990 until January 1993, he served the Company as Vice
President, Planning and Development. For the five years
previous thereto, Mr. Stokes held the position of Manager
Western Production Region of the Company.
Robert L. Thompson, 48 .............................. Mr. Thompson assumed this position on February 2, 1995.
Comptroller and Corporate Planning From February 1993 through January 1995, he served the
Director Company as Director of Business Planning and Acquisitions.
From January 1992 through January 1993, he was Director of
Planning and Analysis and for the three previous years he
was Director of Financial Analysis.
</TABLE>
32
<PAGE>
<TABLE>
<CAPTION>
NAME, AGE AND BUSINESS EXPERIENCE DURING
POSITION WITH THE COMPANY PAST FIVE YEARS
----------------------------------------------------- -----------------------------------------------------------
<S> <C>
Ian L. White-Thomson, 58 ............................ Mr. White-Thomson has been President and Chief Executive
Director Officer of U.S. Borax Inc. since 1988; in addition,
effective April 1, 1995, he has been appointed Chief
Executive of the global RTZ Borax group. Prior to 1988, he
was Vice President, Marketing and then Executive Vice
President of the same company. Mr. White-Thomson has been
a director of U.S. Borax Inc. since 1973. In 1985-86, he
was Group Executive of Pennsylvania Glass Sand Corporation
and Ottawa Silica Company, newly acquired subsidiaries of
U.S. Borax Inc., and organized their combination as U.S.
Silica, of which company he was Group Executive in 1987.
Mr. White-Thomson has been a director of the American
Mining Congress since 1989 and he has previously served as
a director and held several positions, including Chairman,
of the Chemical Industry Council of California. He is a
director of KCET Community Television of Southern
California. He was born and educated in England and became
a U.S. citizen in 1982.
</TABLE>
ITEM 11. EXECUTIVE COMPENSATION
The directors, officers, and employees of the Company (the managing general
partner) receive no direct compensation from the Partnership for their services
to the Partnership. Such persons receive compensation from the Company, a
substantial portion of which is generally reimbursed to the Company by the
Partnership as costs allocable to it. (See Note 2 to the Consolidated Financial
Statements.)
The Partnership reimburses the Company for all direct costs and indirect
costs associated with the Partnership's activities. For the year 1994, the
Company received $73 million as reimbursement of costs allocable to the
Partnership. Such amounts included salaries of employees and allocations of
certain executive and administrative expenses. The aggregate amount reimbursed
by the Partnership to the Company for salaries paid to each person serving as
Chief Executive Officer of the Company during 1994 and each of the four most
highly compensated executive officers of the Company during 1994 other than the
Chief Executive Officer was approximately $1,330,000 for 1994. (See Note 3 to
the Consolidated Financial Statements.)
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table provides certain information regarding beneficial
ownership of the limited partnership units of Sun Energy Partners, L.P. as of
December 31, 1994.
33
<PAGE>
UNITS OF SUN ENERGY PARTNERS, L.P.
<TABLE>
<CAPTION>
NUMBER OF PERCENT OF
BENEFICIAL OWNER UNITS CLASS
-------------------------------------------------------------------------------- ----------- ----------
<S> <C> <C>
Oryx Energy Company
13155 Noel Road
Dallas, TX 75240-5067.......................................................... 413,627,359 98.2 *
All Directors and Executive Officers of Managing General Partner (Oryx Energy
Company) as a Group (16)**..................................................... 1,200
<FN>
------------------------
*Assumes that Oryx Energy Company's 292,000,000 general partnership units are
converted into limited partnership units of Sun Energy Partners, L.P.
**As of December 31, 1994, the directors and executive officers of Oryx Energy
Company, as a group, beneficially owned less that one percent of the
outstanding shares of Oryx Energy Company.
</TABLE>
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In its capacity as managing general partner of the Partnership, the Company
controls the Partnership and its operations, and has served as a lender and
borrower of funds for the Partnership. Following is a table which summarizes
lending activities between the Partnership and the Company during the year ended
December 31, 1994:
<TABLE>
<CAPTION>
BALANCE DUE BALANCE DUE
TO (FROM) TO (FROM)
PARTNERSHIP PARTNERSHIP
DECEMBER 31, 1993 ADDITIONS REPAYMENTS DECEMBER 31, 1994
------------------- ------------- --------------- -------------------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
Variable Rate Advances to (from) Oryx Energy
Company........................................... $ (22) $ 26 $ 57 $ 9
--- --- --- ---
--- --- --- ---
[9.75]% Note Payable to Oryx Energy Company........ $ (91) $ -- $ 9 $ (82)
--- --- --- ---
--- --- --- ---
</TABLE>
During 1994, the largest balance owed to the Partnership by the Company for
variable rate advances was $14 million. The largest balance owed to the Company
by the Partnership during 1994 resulting from advances from Oryx Energy Company
and amounts due under the 9.75% Note Payable was $137 million. Certain
information required by this section is included in Notes to the Consolidated
Financial Statements. See Notes 1, 3 and 10 included elsewhere in this Form
10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following Documents are filed as a part of this report:
1. Financial Statements:
See Index to Financial Statements, Supplementary Financial and Operating
Information on page 12.
34
<PAGE>
2. Exhibits:
<TABLE>
<C> <S>
3(a) --Second Amended and Restated Agreement of Limited Partnership of Sun Energy
Partners, L.P., dated December 10, 1985 (incorporated by reference to Exhibit 3(a)
of the Form SE filed March 20, 1986).
3(b) --Certificate of Limited Partnership of Sun Energy Partners, L.P., dated October 1,
1985 (incorporated by reference to Exhibit 3(b) of the Partnership's Form 10-K for
the one month ended December 31, 1985).
4(a) --Deposit Agreement, made as of December 3, 1985 among Sun Energy Partners, L.P.,
Manufacturers Hanover Trust Company, Sun Company, Inc., Oryx Energy Company and
All Limited Partners in Sun Energy Partners, L.P. (incorporated by reference to
Exhibit 4(a) of the Form SE filed March 20, 1986).
4(b) --Instruments defining the rights of security holders, including indentures: The
Partnership will provide copies of the instruments relating to long-term debt to
the SEC upon request.
16 --Accountant's Preferability Letter
22 --Affiliated Operating Partnerships/Subsidiary Corporations of Sun Energy Partners.
L.P. (incorporated by reference to Exhibit 22 of the Form SE filed March 18,
1988).
24(a) --Power of Attorney executed by certain officers and directors of Oryx Energy
Company, managing general partner of Sun Energy Partners, L.P.
24(b) --Certified copy of the resolution authorizing certain officers to sign on behalf of
Oryx Energy Company, managing general partner of Sun Energy Partners, L.P.
28(a) --Agreement of Limited Partnership of Sun Operating Limited Partnership dated
November 18, 1985, as amended (incorporated by reference to Exhibit 28(a) of the
Form SE filed March 20, 1986).
28(b) --Certificate of Limited Partnership of Sun Operating Limited Partnership dated
November 19, 1985 (incorporated by reference to Exhibit 28(b) of the Partnership's
Form 10-K for the one month ended December 31, 1985).
28(c) --Sun Operating Limited Partnership 9.75% Promissory Note (incorporated by reference
to Exhibit 28(c) of the Partnership's Annual Report on Form 10-K for the fiscal
year ended December 31, 1991, as amended by Amendment No. 1 on Form 8 dated July
17, 1992, Commission File No. 1-9033).
28(d) --Letter Agreement Dated November 21, 1990, Between Oryx Energy Company and Atlantic
Richfield Company (incorporated by reference to Exhibit 28(a) of the Partnership's
Current Report on Form 8-K dated January 31, 1991, Commission File No. 1-9033).
28(e) --Amendment Dated November 28, 1990 to Letter Agreement Dated November 21, 1990,
Between Oryx Energy Company and Atlantic Richfield Company (incorporated by
reference to Exhibit 28(b) of the Partnership's Current Report on Form 8-K dated
January 31, 1991, Commission File No. 1-9033).
</TABLE>
(b) Reports on Form 8-K:
The Partnership did not file any reports on Form 8-K during the quarter
ended December 31, 1994.
35
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
SUN ENERGY PARTNERS, L.P.
By: ORYX ENERGY COMPANY
(MANAGING GENERAL PARTNER)
*By: /s/ EDWARD W. MONEYPENNY
-----------------------------------
Edward W. Moneypenny
EXECUTIVE VICE PRESIDENT, FINANCE,
CHIEF FINANCIAL OFFICER AND
DIRECTOR
Date March 22, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by or on behalf of the following persons on behalf
of the Registrant and in the capacities with Oryx Energy Company, Managing
General Partner, and on the date indicated:
SIGNATURE TITLE DATE
----------------------------------- ------------------------- ----------------
JERRY W. BOX** Executive Vice President,
----------------------------------- Exploration and
Jerry W. Box Production, and Director
WILLIAM E. BRADFORD** Director
-----------------------------------
William E. Bradford
ROBERT B. GILL** Director
-----------------------------------
Robert B. Gill
DAVID S. HOLLINGSWORTH** Director
-----------------------------------
David S. Hollingsworth
ROBERT L. KEISER** Chairman of the Board,
----------------------------------- Chief
Robert L. Keiser Executive Officer,
and President
(principal
executive officer) March 22, 1995
/s/ EDWARD W. MONEYPENNY Executive Vice President,
----------------------------------- Finance, Chief
Edward W. Moneypenny Financial Officer
(principal
financial officer), and
Director
CHARLES H. PISTOR, JR.** Director
-----------------------------------
Charles H. Pistor, Jr.
PAUL R. SEEGERS** Director
-----------------------------------
Paul R. Seegers
IAN L. WHITE-THOMSON** Director
-----------------------------------
Ian L. White-Thomson
**By: /s/ EDWARD W. MONEYPENNY
-----------------------------------
Edward W. Moneypenny
ATTORNEY-IN-FACT
------------------------
*Attorney-in-Fact pursuant to Resolution of the Board of Directors of the
Managing General Partner which is being filed as an Exhibit to this Form 10-K.
**Original powers of attorney authorizing Robert L. Keiser and Edward W.
Moneypenny or any one of them, to sign this Form 10-K Annual Report on behalf
of Sun Energy Partners, L.P., is being filed as an Exhibit to this Form 10-K.
36
<PAGE>
EXHIBIT 16
To The Board of Directors, Oryx Energy Company:
We are providing this letter to you for inclusion as an exhibit to the Sun
Energy Partners L.P. (the Partnership) Form 10-K filing pursuant to Item 601
of Regulation S-K.
We have read management's justification for the change in accounting method
for assessing the impairment of proved oil and gas properties from a
world-wide basis to a field-by-field basis contained in the Partnership's
Form 10-K for the year ended December 31, 1994. Based on our reading of the
data and discussions with Partnership officials of the business judgment and
business planning factors relating to the change, we believe management's
justification to be reasonable. Accordingly, in reliance on management's
determination as regards elements of business judgment and business planning,
we concur that the newly adopted accounting principle described above is
preferable in the Partnership's circumstances to the method previously
applied.
Coopers & Lybrand L.L.P.
February 19, 1995
Dallas, Texas
<PAGE>
EXHIBIT 24(A)
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Robert L. Keiser and Edward W. Moneypenny, and
each of them (with full power to each of them to act alone), his or her true and
lawful attorney-in-fact and agent, with full power of substitution and
resubstitution, for him or her and in his or her name, place and stead, in any
and all capacities with Oryx Energy Company, in its capacity as managing general
partner of Sun Energy Partners, L.P., to sign the Annual Report of Sun Energy
Partners, L.P. for the fiscal year ended December 31, 1994 on Form 10-K pursuant
to Section 13 or 15(d) of the Securities Exchange Act of 1934 and any or all
amendments to the Annual Report and to file the same, with all exhibits thereto
and other documents in connection therewith with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents, and each of them,
full power and authority to do and perform each and every act and thing
requisite and necessary to be done in and about the premises, as fully to all
intents and purposes as he or she might or could do in person, hereby ratifying
and confirming all that said attorneys-in-fact and agents or any of them, or
their substitutes, may lawfully do or cause to be done by virtue hereof.
SIGNATURE TITLE DATE
----------------------------------- ------------------------- ----------------
/S/ ROBERT L. KEISER Chairman of the Board, March 2, 1995
----------------------------------- Chief Executive Officer,
(Robert L. Keiser) President, and Director
(principal executive
officer)
/s/ EDWARD W. MONEYPENNY Executive Vice President, March 2, 1995
----------------------------------- Finance, Chief Financial
(Edward W. Moneypenny) Officer, and Director
(principal financial
officer)
/s/ JERRY W. BOX Executive Vice President, March 2, 1995
----------------------------------- Exploration and
(Jerry W. Box) Production and Director
/s/ ROBERT L. THOMPSON Comptroller and Corporate March 2, 1995
----------------------------------- Planning Director
(Robert L. Thompson) (principal accounting
officer)
/s/ WILLIAM E. BRADFORD Director March 2, 1995
-----------------------------------
(William E. Bradford)
/s/ CAROL E. DINKINS Director March 2, 1995
-----------------------------------
(Carol E. Dinkins)
/s/ ROBERT B. GILL Director March 2, 1995
-----------------------------------
(Robert B. Gill)
<PAGE>
SIGNATURE TITLE DATE
----------------------------------- ------------------------- ----------------
/s/ DAVID S. HOLLINGSWORTH Director March 2, 1995
-----------------------------------
(David S. Hollingsworth)
/s/ CHARLES H. PISTOR, JR. Director March 2, 1995
-----------------------------------
(Charles H. Pistor, Jr.)
/s/ PAUL R. SEEGERS Director March 2, 1995
-----------------------------------
(Paul R. Seegers)
/s/ IAN L. WHITE-THOMSON Director March 2, 1995
-----------------------------------
(Ian L. White-Thomson)
<PAGE>
EXHIBIT 24(b)
CERTIFICATE
I, William C. Lemmer, hereby certify that I am Secretary of Oryx Energy
Company, a Delaware corporation and that the following is a true and correct
copy of resolution adopted by the Board of Directors of Oryx Energy Company on
the 2nd day of March, 1995:
RESOLVED that the Annual Report of Sun Energy Partners L.P. ("MLP")
to the Securities and Exchange Commission on Form 10-K for the year
ended December 31, 1994, prepared and to be filed by the Company as
managing general partner of the MLP,is hereby approved in the form
presented to this meeting as Exhibit D, subject to such revisions or
amendments as may be approved by the Executive Vice President,
Finance and Chief Financial Officer or the Comptroller and Corporate
Planning Director to assure compliance with applicable laws and
regulations, and that said officers or either of them is hereby
authorized to sign the Form 10-K on behalf of the Company.
I further certify that this resolution has not been revoked or amended,
and is now in full force and effect.
Executed this 23rd day of March, 1995.
/s/ William C. Lemmer
-----------------------------------
WILLIAM C. LEMMER
